Edgar Filing: ALLIANCE RESOURCE PARTNERS LP

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007

¨	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)

Securities registered pursuant to Section 12(b) of the Act: Common Units representing limited partner interests


Title of Each Class		Name of Each Exchange On Which Registered
Common Units		NASDAQ Stock Market, LLC

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x Yes ¨ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨ Yes x No

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. x Yes ¨ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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

Large Accelerated Filer x Accelerated Filer ¨ Non-Accelerated Filer ¨ Smaller Reporting Company ¨

(Do not check if smaller reporting company)

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

The aggregate value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $857,632,818 as of June 29, 2007, the last business day of the registrant’s most recently completed second fiscal quarter, based on the reported closing price of the common units as reported on the NASDAQ Stock Market, LLC on such date.

As of February 25, 2008, 36,613,458 common units were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

TABLE OF CONTENTS


		Page
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	34
Item 2.	Properties	35
Item 3.	Legal Proceedings	37
Item 4.	Submission of Matters to a Vote of Securities Holders	38

PART II

Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	38
Item 6.	Selected Financial Data	39
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	63
Item 8.	Financial Statements and Supplementary Data	64
Item 9.	Changes in and Disagreements with Accountant on Accounting and Financial Disclosure	94
Item 9A.	Controls and Procedures	94
Item 9B.	Other Information	97

PART III

Item 10.	Directors, Executive Officers and Corporate Governance of the Managing General Partner	98
Item 11.	Executive Compensation	103
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	115
Item 13.	Certain Relationships and Related Transactions, and Director Independence	117
Item 14.	Principal Accountant Fees and Services	120

PART IV

Item 15.	Exhibits and Financial Statement Schedules	121

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. 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. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are reasonable, but are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are:

•

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

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

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risks associated with the expansion of our operations and properties;

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

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

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

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customer delays or defaults in making payments;

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

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

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greater than expected increases in raw material costs;

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greater than expected shortage of skilled labor;

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

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

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greater than expected environmental regulation, costs and liabilities;

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

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

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results of litigation, including claims not yet asserted;

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

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coal market’s share of electricity generation;

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prices of fuel that compete with or impact coal usage, such as oil or natural gas;

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legislation, regulatory and court decisions and interpretations thereof, including but not limited to issues related to climate change;

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the impact from provisions of The Energy Policy Act of 2005;

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The impact from provisions of or changes in enforcement activities associated with the Mine Improvement and New Emergency Response Act of 2006 as well as any subsequent federal or state legislation or regulations;

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replacement of coal reserves;

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a loss or reduction of direct or indirect benefits from certain state and federal tax credits;

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

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other factors, including those discussed in Item 1A. “Risk Factors” and Item 3. “Legal Proceedings.”

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 Annual Report on Form 10-K;

•

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 authorized persons acting on our behalf.

iii

Significant Relationships Referenced in this Annual Report

•

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

•

References to “ARLP” mean 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, the managing general partner of Alliance Resource Partners, L.P., also referred to as our managing general partner.

•

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

•

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

•

References to “Alliance Coal” mean Alliance Coal, LLC, the holding company for the operations of Alliance Resource Operating Partners, L.P., also referred 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, the general partner of Alliance Holdings GP, L.P.

PART I

ITEM 1.

BUSINESS

General

We are a diversified producer and marketer of coal primarily 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 fourth largest coal producer in the eastern United States. At December 31, 2007, we had approximately 712.8 million tons of coal reserves in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia. In 2007, we produced 24.3 million tons of coal and sold 24.7 million tons of coal of which 25.9% was low-sulfur coal, 13.2% was medium-sulfur coal and 60.9% was high-sulfur coal. In 2007, approximately 93.4% of our medium- and high-sulfur coal was sold to utility plants with installed pollution control devices, also known as “scrubbers,” to remove sulfur dioxide. We classify low-sulfur coal as coal with a sulfur content of less than 1%, medium-sulfur coal as coal with a sulfur content between 1% and 2%, and high-sulfur coal as coal with a sulfur content of greater than 2%.

At December 31, 2007, we operated eight mining complexes in Illinois, Indiana, Kentucky, Maryland, and West Virginia. Three of our mining complexes supplied coal feedstock and provided services to third-party coal synfuel facilities located at or near these complexes. The synfuel facilities ceased operations in December 2007 as the federal non-conventional source fuel tax credit expired. We also operated a coal loading terminal on the Ohio River at Mt. Vernon, Indiana. Our mining activities are conducted in three geographic regions commonly referred to in the coal industry as the Illinois Basin, Central Appalachian and Northern Appalachian regions. We have grown historically, and expect to grow in the future, through expansion of our operations by adding and developing mines and coal reserves in these regions.

ARLP is a Delaware limited partnership listed on the NASDAQ Global Select Market under the ticker symbol “ARLP.” ARLP was formed in May 1999 to acquire, upon completion of ARLP’s initial public offering on August 19, 1999, certain coal production and marketing assets of Alliance Resource Holdings, Inc., a Delaware corporation (“ARH”), 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, the President and Chief Executive Officer of our managing general partner. SGP, a Delaware limited liability company, holds a 0.01% general partner interest in each of ARLP and the Intermediate Partnership.

We are managed by our managing general partner, MGP, a Delaware limited liability company, which holds a 0.99% and 1.0001% managing general partner interest in ARLP and the Intermediate Partnership, respectively. AHGP is a Delaware limited partnership that was formed to become the owner and controlling member of MGP. AHGP completed its initial public offering (“AHGP IPO”) on May 15, 2006 and is listed on the NASDAQ Global Select Market

under the ticker symbol “AHGP.” 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 15,544,169 common units of ARLP. The following diagram depicts our organization and ownership as of December 31, 2007:

LOGO

(1)

The Management Group are current and former members of our management, who are the former indirect owners of MGP, and their affiliates.

(2)

The units held by our special general partner and most of the units held by the Management Group are subject to a transfer restriction agreement that, subject to a number of exceptions (including certain transfers by Joseph W. Craft III in which the other parties to the agreement are entitled or required to participate), prohibits the transfer of such units unless approved by a majority of the disinterested members of the board of directors of AGP pursuant to certain procedures set forth in the agreement.

Our internet address is www.arlp.com, and we make available on our internet website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and Forms 3, 4 and 5 for our Section 16 filers (and amendments and exhibits, such as press releases, to such filings) as soon as reasonably practicable after we electronically file with or furnish such material to the Securities and Exchange Commission. Our “Code of Ethics” for the chief executive officer and senior financial officers of our managing general partner is also posted on our website. Information on our website or any other website is not incorporated by reference into this report and does not constitute a part of this report.

Developing Mine Safety Laws and Regulations

In 2006, the U.S. Congress, as well as several state legislatures (including those in West Virginia, Illinois and Kentucky), passed new legislation addressing mine safety practices and imposing stringent new mine safety and accident reporting requirements and increasing civil and criminal penalties for violations of mine safety laws. In addition, the Mine Safety and Health Administration (“MSHA”), which monitors compliance with federal laws, published a final rule addressing mine safety equipment, training, and emergency reporting requirements and established stringent “Emergency Temporary Standards” for sealing off abandoned areas of underground coal mines. Pending federal legislation, if enacted, would impose additional safety and health requirements on coal mining. Although we are unable to quantify the full impact, we have experienced, and anticipate we will continue to experience, higher operating expenses and increased capital expenditures as a result of these new laws and regulations. Please read “Regulation and Laws—Mine Health and Safety Laws.”

Mining Operations

We produce a diverse range of steam coals with varying sulfur and heat contents, which enables us to satisfy the broad range of specifications required by our customers. The following chart summarizes our coal production by region for the last five years.


	Year Ended December 31,
Regions and Complexes	2007	2006	2005	2004	2003
	(tons in millions)
Illinois Basin:
Dotiki, Warrior, Pattiki, Hopkins and Gibson complexes	17.9	16.9	15.7	13.6	12.3
Central Appalachian:
Pontiki and MC Mining complexes	3.2	3.5	3.3	3.6	3.6
Northern Appalachian:
Mettiki complex	3.2	3.3	3.3	3.2	3.3

Total	24.3	23.7	22.3	20.4	19.2

The following map shows the location of each of our mining complexes:

LOGO

Illinois Basin Operations

Our Illinois Basin mining operations are located in western Kentucky, southern Illinois and southern Indiana. We have approximately 1,690 employees in the Illinois Basin and currently operate five mining complexes. Additionally, we hosted a coal synfuel facility at two of our mining complexes through December 2007.

Dotiki Complex. Our subsidiary, Webster County Coal, LLC (“Webster County Coal”), operates Dotiki, which is an underground mining complex located near the city of Providence in Webster County, Kentucky. The complex was opened in 1966, and we purchased the mine in 1971. The Dotiki complex utilizes continuous mining units employing room-and-pillar mining techniques to produce high-sulfur coal. Dotiki’s preparation plant has a throughput capacity of 1,300 tons of raw coal an hour.

Coal from the Dotiki complex is shipped via the CSX Transportation, Inc. (“CSX”) and Paducah & Louisville Railway, Inc. (“PAL”) railroads and by truck on U.S. and state highways. Our primary customers for coal produced at Dotiki are Seminole Electric Cooperative, Inc. (“Seminole”) and Tennessee Valley Authority (“TVA”), both of which purchase our coal pursuant to long-term contracts for use in their scrubbed generating units.

Warrior Complex. Our subsidiary, Warrior Coal, LLC (“Warrior”), operates the Cardinal mine, an underground mining complex located near the city of Madisonville in Hopkins County, Kentucky. The Warrior complex was opened in 1985 and acquired by us in February 2003. Warrior utilizes continuous mining units employing room-and-pillar mining techniques to produce high-sulfur coal. Warrior’s preparation plant has a throughput capacity of 600 tons of raw coal an hour. Warrior’s production can be shipped via the CSX and PAL railroads and by truck on U.S. and state highways. Additionally, Warrior purchased supplemental production from a third-party supplier during the first half of 2007.

In 2007, Warrior sold most of its production to Synfuel Solutions Operating, LLC (“SSO”) for feedstock in the production of coal synfuel. SSO’s coal synfuel production facility was moved from our mining complex operated by our subsidiary, Hopkins County Coal, LLC (“Hopkins County Coal”), to our Warrior complex in April 2003. We had long-term agreements with SSO to host and operate its coal synfuel facility, supply the facility with coal feedstock, assist SSO with the marketing of coal synfuel and provide other services, which provided us with coal sales, rental and service fees from SSO. Certain of these services were performed by Alliance Service, Inc. (“Alliance Service”), a wholly-owned subsidiary of Alliance Coal. Alliance Service is subject to federal and state income taxes.

On December 31, 2007, the federal non-conventional source fuel tax credit expired. As a result, and under their terms, these long-term agreements with SSO expired on December 31, 2007. For 2007, the incremental net income benefit from the combination of the various coal synfuel-related agreements associated with the facility located at Warrior was approximately $22.4 million, assuming that coal pricing would not have increased without the availability of synfuel.

SSO shipped coal synfuel to electric utilities that have been purchasers of our coal. We maintained “back-up” coal supply agreements directly with these long-term customers for our coal, which automatically provided for the sale of our coal to them in the event they did not purchase coal synfuel from SSO. In 2008, our primary customer for coal produced at Warrior will be Louisville Gas and Electric Company, pursuant to a long-term coal supply agreement that was one of these “back-up” agreements. As such, while we will be able to sell the production that would have been sold to SSO to our “back-up” purchasers, we may not be able to recover the $22.4 million in incremental net income benefit of the synfuel related operations.

Pattiki Complex. Our subsidiary, White County Coal, LLC (“White County Coal”), operates Pattiki, an underground mining complex located near the city of Carmi in White County, Illinois. We began construction of the complex in 1980 and have operated it since its inception. Our Pattiki complex utilizes continuous mining units employing room-and-pillar mining techniques to produce high-sulfur coal. The preparation plant has a throughput capacity of 1,000 tons of raw coal an hour.

Coal from the Pattiki complex is shipped via the Evansville Western Railway, Inc. (“EVW”) railroad. Two of our primary customers for coal produced at Pattiki are Northern Indiana Public Service Company and Seminole for use in their scrubbed generating units. Pattiki production is also shipped via rail to our Mt. Vernon transloading facility for sale to utilities capable of receiving barge deliveries. In 2008, Pattiki also expects to ship a significant portion of its production to Corn Products International, Inc., Tampa Electric Company, and Vectren Corporation.

Hopkins Complex. Hopkins County Coal’s mining complex, which we acquired in January 1998, is located near the city of Madisonville in Hopkins County, Kentucky. During 2006, Hopkins County Coal ceased production from its Newcoal surface mine, which is being reclaimed, and continued with the development of its Elk Creek mine in the underground reserves leased by Hopkins County Coal in 2005.

The Elk Creek mine, an underground mining complex using continuous mining units employing room-and-pillar mining techniques to produce high-sulfur coal, emerged from development in the second quarter of 2006 with production from the operation of three mining units. In November 2007, Elk Creek added a fourth production unit and is adding a fifth unit which is scheduled to be operational in the second quarter of 2008.

We are utilizing both existing and newly constructed coal handling and other surface facilities at Hopkins County Coal to process and ship coal produced from the Elk Creek mine. In conjunction with the development of the Elk Creek mine, Hopkins County Coal constructed a new preparation plant with a throughput capacity of 1,200 tons of raw coal an hour. Hopkins County Coal’s Elk Creek production can be shipped via the CSX and PAL railroads and by truck on U.S. and state highways. Elk Creek has historically sold its production to a diverse group of customers and in 2008 expects TVA to be a primary customer.

Gibson Complex. Our subsidiary, Gibson County Coal, LLC (“Gibson County Coal”), operates the Gibson mine, an underground mining complex located near the city of Princeton in Gibson County, Indiana. The mine began production in November 2000 and utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal. The preparation plant has a throughput capacity of 700 tons of raw coal an hour. We refer to the reserves mined at this location as the “Gibson North” reserves. We also control undeveloped reserves in Gibson County that are not contiguous to the reserves currently being mined, which we refer to as the “Gibson South” reserves.

Production from Gibson is a low-sulfur coal that historically has been primarily shipped via truck approximately 10 miles on U.S. and state highways to Gibson’s principal customer, PSI Energy Inc. (d/b/a Duke Energy Indiana, Inc.), a subsidiary of Cinergy Corporation (d/b/a Duke Energy Corporation) (“PSI”). Gibson’s production is also trucked or railed to our Mt. Vernon transloading facility for sale to utilities capable of receiving barge deliveries. In 2007, we completed construction of a new rail loop at Gibson, providing access to both the CSX and Norfolk Southern Railway Company (“NS”) railroads and expanding the market for coal produced at Gibson.

In January 2005, Gibson County Coal entered into long-term agreements with PC Indiana Synthetic Fuel #2, L.L.C. (“PCIN”) to host its coal synfuel facility, supply the facility with coal feedstock, assist PCIN with the marketing of coal synfuel and provide other services. The synfuel facility commenced operations at Gibson in May 2005. A significant portion of Gibson’s production was sold to PCIN, providing us with coal sales, rental and service fees from PCIN based on the synfuel facility throughput tonnages. PCIN shipped coal synfuel to various customers that have been purchasers of our coal and with which we maintained “back-up” coal supply agreements, which automatically provided for the sale of our coal to them in the event they did not purchase coal synfuel from PCIN. In 2008, our primary customer for coal produced at Gibson will be PSI, pursuant to a long-term coal supply agreement that was one of these “back-up” agreements. On December 31, 2007, the federal non-conventional source fuel tax credit expired. As a result, and under their terms, the PCIN agreements expired on December 31, 2007. For 2007, the incremental net income benefit from the combination of the various coal synfuel related agreements associated with the facility located at Gibson was approximately $4.3 million, assuming that coal pricing would not have increased without the availability of synfuel. As such, while we will be able to sell the production that would have been sold to PCIN to PSI and other “back-up” purchasers, we may not be able to recover the incremental net income benefit of the synfuel related operations.

We have partially completed the permitting process for the Gibson South reserves and continue to actively evaluate its development. Capital expenditures required to develop the Gibson South reserves are estimated to be in the range of approximately $100 million to $110 million, excluding capitalized interest and capitalized mine development costs associated with net cost related to incidental production. For more information about mine development costs, please read “Mine Development Costs” under “Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies.” Assuming sufficient sales commitments are obtained and the permitting process continues as anticipated, initial production could commence in 2010 to 2012. For more information on the permitting process, and matters that could hinder or delay the process, please read “Regulation and Laws – Mining Permits and Approvals.” When the Gibson South mine reaches full production capacity, we expect annual production of approximately 2.7 million to 3.1 million tons. Definitive development commitment for Gibson South is dependent upon final approval by the board of directors of our managing general partner (“Board of Directors”).

River View. In April 2006, we acquired 100% of the membership interest in River View Coal, LLC (“River View”) from ARH. River View currently controls, through coal leases or direct ownership, approximately 117.1 million tons of proven and probable high-sulfur coal in the Kentucky No. 7, No. 9 and No. 11 coal seams underlying properties located primarily in Union County, Kentucky, as well as certain surface properties, facilities and permits. River View is in the process of updating its existing permits and evaluating the timing and manner of future development of the reserve. We expect to develop River View as an underground mining complex using continuous mining units employing room-and-pillar mining techniques, with production from the operation of four mining units and capacity to expand to up to eight mining units. In July 2007, we began construction of the slope and shaft at River View. However, definitive development commitment for River View is dependent upon final approval of the Board of Directors. Capital expenditures required to develop the River View reserves are estimated to be in the range of approximately $130 million to $160 million, excluding capitalized interest and capitalized mine development costs associated with net cost related to incidental production. For more information about mine development costs, please read “Mine Development Costs” under “Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies.”

Assuming sufficient sales commitments are obtained and the permitting process continues as anticipated, initial production could commence in 2009 or 2010. For more information on the permitting process, and matters that could hinder or delay the process, please read “Regulation and Laws – Mining Permits and Approvals.” When the River View mine reaches its production capacity with four mining units, we expect annual production of approximately 3.1 million tons, with the ability to expand annual production to 6.4 million tons with additional mining units.

Central Appalachian Operations

Our Central Appalachian mining operations are located in eastern Kentucky. We have approximately 530 employees in Central Appalachia and operate two mining complexes producing low-sulfur coal.

Pontiki Complex. Our subsidiary, Pontiki Coal, LLC (“Pontiki”), owns an underground mining complex located near the city of Inez in Martin County, Kentucky. We constructed the mine in 1977. Pontiki owns the mining complex and leases the reserves, and our subsidiary, Excel Mining, LLC (“Excel”), conducts all mining operations. Our Pontiki operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal. The preparation plant has a throughput capacity of 900 tons of raw coal an hour. In the fourth quarter of 2005, Pontiki migrated some of its mining units from the Pond Creek seam into the Van Lear seam, and full production in the Van Lear seam was reached in the second quarter of 2006. As a result, production at Pontiki is now roughly 50% Pond Creek seam coal and 50% Van Lear seam coal. Coal produced in 2007 remained low sulfur, but because of changes in geology and production from the Van Lear seam, it no longer met the compliance requirements of Phase II of the Federal Clean Air Act (“CAA”) (see “Regulation and Laws—Air Emissions” below). Coal produced from the mine is shipped in large part to electric utilities located in the southeastern United States and also to industrial or stoker users throughout the eastern United States via the NS railroad or by truck via U.S. and state highways to various docks on the Big Sandy River in Kentucky.

MC Mining Complex. Our subsidiary, MC Mining, LLC (“MC Mining”), owns an underground mining complex located near the city of Pikeville in Pike County, Kentucky. We acquired the mine in 1989. MC Mining owns the mining complex and leases the reserves, and Excel, an affiliate of MC Mining, conducts all mining operations. The operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal. The preparation plant has a throughput capacity of 1,000 tons of raw coal an hour. Substantially all of the coal produced at MC Mining in 2007 met or exceeded the compliance requirements of Phase II of the CAA. Production from the mine is shipped via the CSX railroad or by truck via U.S. and state highways to various docks on the Big Sandy River. MC Mining sells its low-sulfur production primarily under short-term contracts and into the spot market.

Northern Appalachian Operations

Our Northern Appalachian mining operations are located in Maryland and West Virginia. We have approximately 230 employees and operate one mining complex in Northern Appalachia. We also control undeveloped reserves in West Virginia and Pennsylvania.

Mettiki (MD) Operation. Our subsidiary, Mettiki Coal, LLC (“Mettiki (MD)”), previously operated an underground longwall mine located near the city of Oakland in Garrett County, Maryland. Underground longwall mining operations ceased at this mine in October 2006 upon the exhaustion of the economically mineable reserves, and the longwall mining equipment was moved from the Mettiki (MD) operation to the operation of our subsidiary, Mettiki Coal (WV), LLC (“Mettiki (WV)”) (discussed below). Medium-sulfur coal produced from two small-scale third-party mining operations (a surface strip mine and an underground mine in the Bakerstown seam) on properties controlled by Mettiki (MD) and another of our subsidiaries, Backbone Mountain, LLC, is processed at the Mettiki complex and supplements the Mettiki (WV) production, providing blending optimization and allowing the operation to take advantage of market opportunities as they arise.

Our Mettiki (MD) preparation plant has a throughput capacity of 1,350 tons of raw coal an hour. A portion of the Mettiki (WV) production is transported to this preparation plant for processing, and then trucked to a newly constructed blending facility at the Virginia Electric and Power Company (“VEPCO”) Mt. Storm Power Station. The preparation plant also is served by the CSX railroad, providing the opportunity to capitalize on the metallurgical coal market.

Mettiki (WV) Operation. In July 2005, Mettiki (WV) began continuous miner development of the Mountain View mine located in Tucker County, West Virginia. Upon completion of mining at the Mettiki (MD) longwall operation, the longwall mining equipment was moved to the Mountain View mine and put into operation in November 2006. Production from the Mountain View mine is transported by truck either to the Mettiki (MD) preparation plant or to the coal blending facility at the VEPCO Mt. Storm Power Station.

Production from the Mountain View mine in 2007 was primarily supplied to Mt. Storm Coal Supply, LLC (“Mt. Storm”) for its synfuel facility, which was located at the Mt. Storm Power Station. Our agreement to supply coal to Mt. Storm terminated at the end of 2007 in conjunction with the termination of the synfuel tax credit program. For 2007, the incremental net income benefit from this agreement was approximately $1.8 million, assuming that coal pricing would not have increased without the availability of synfuel.

Our primary customer for the medium-sulfur coal produced at Mettiki is VEPCO, which purchases the coal for use in the scrubbed generating units at its Mt. Storm Power Station in West Virginia. A seven-year agreement to supply coal to the VEPCO Mt. Storm Power Station from the Mountain View mine was negotiated and finalized in June 2005. Prior to termination of our agreement to supply coal to Mt. Storm, this agreement also served as a “back-up” agreement with VEPCO for the sale of our coal in the event that VEPCO did not purchase coal synfuel from Mt. Storm. As such, while we will be able to sell the production that would have been sold to Mt. Storm to VEPCO and other “back-up” purchasers, we may not be able to recover the $1.8 million in incremental net income benefit of the synfuel related operations.

Penn Ridge Coal. In December 2005, our subsidiary, Penn Ridge Coal, LLC (“Penn Ridge”), entered into a coal lease and sales agreement with affiliates of Allegheny Energy, Inc. (“Allegheny”), to pursue development of Allegheny’s Buffalo coal reserve in Washington County, Pennsylvania. The Buffalo coal reserve lease is estimated to include approximately 56.7 million tons of proven and probable high-sulfur coal in the Pittsburgh No. 8 seam. We have initiated the permitting process for the Buffalo coal reserves and are evaluating its development. Capital expenditures required to develop the Penn Ridge reserves are estimated to be in the range of approximately $165 million to $175 million, excluding capitalized interest and capitalized mine development costs associated with net cost related to incidental production. For more information about mine development costs, please read “Mine Development Cost” under “Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies.” Assuming sufficient sales commitments are obtained and the permitting process is completed, initial production could commence in 2011 to 2013. For more information on the permitting process, and matters that could hinder or delay the process, please read “Regulation and Laws – Mining Permits and Approvals.” When the Penn Ridge mine reaches full production capacity, we expect annual production of up to 5.0 million tons. Definitive development commitment for Penn Ridge is dependent upon final approval of the Board of Directors.

Tunnel Ridge. Our subsidiary, Tunnel Ridge, LLC (“Tunnel Ridge”), controls, through a coal lease agreement with our special general partner, approximately 70.5 million tons of proven and probable high-sulfur coal in the Pittsburgh No. 8 coal seam in West Virginia and Pennsylvania. An underground mining permit was issued by the West Virginia Department of Environmental Protection on February 12, 2007, and we have submitted applications for all other permits necessary to conduct operations, which currently are under review. Capital expenditures required to develop the Tunnel Ridge reserves are estimated to be in the range of approximately $210 million to $235 million, excluding capitalized interest and capitalized mine development costs associated with net cost related to incidental production. For more information about mine development costs, please read “Mine Development Costs” under “Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies.” Assuming sufficient sales commitments are obtained and the permitting process continues as anticipated, initial production could commence in 2009 to 2011. When the Tunnel Ridge mine reaches full production capacity, we expect annual production of up to 6.0 million tons. For more information on the permitting process, and matters that could hinder or delay the process, please read “Regulation and Laws – Mining Permits and Approvals.” Definitive development commitment for Tunnel Ridge is dependent upon final approval of the Board of Directors.

Other Operations

Mt. Vernon Transfer Terminal, LLC

Our subsidiary, Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”), leases land and operates a coal loading terminal on the Ohio River (mile marker 827.5) at Mt. Vernon, Indiana. Coal is delivered to Mt. Vernon by both rail and truck. The terminal has a capacity of 8.0 million tons per year with existing ground storage of approximately 60,000 to 70,000 tons. During 2007, the terminal loaded approximately 1.6 million tons for customers of Pattiki, Gibson and Elk Creek.

Coal Brokerage

As markets allow, we buy coal from non-affiliated producers principally throughout the eastern United States, which we then resell, both directly and indirectly, primarily to utility customers. We have a policy of matching our outside coal purchases and sales to minimize market risks associated with buying and reselling coal. Purchased coal that is delivered to our operations and commingled with our production is not classified as brokerage coal. In 2007, we did not purchase or sell any coal that was classified as brokerage coal other than coal revenues associated with the settlement agreement with ICG, LLC (“ICG”) described in “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Operating Expenses.”.

Matrix Design Group, LLC

Our subsidiaries, Matrix Design Group, LLC and Alliance Design Group, LLC (collectively, “MDG”), provide a variety of mine products and services for our mining operations and to unrelated parties. We acquired this business in September 2006. MDG’s products and services include design and installation of underground mine hoists for transporting employees and materials in and out of mines; design of systems for automating and controlling various aspects of industrial and mining environments; and design and sale of mine safety equipment, including its miner and equipment tracking system. In 2007, our financial results were not significantly impacted by MDG’s activities.

Additional Services

We develop and market additional services in order to establish ourselves as the supplier of choice for our customers. Examples of the kind of services we have offered to date include ash and scrubber sludge removal, coal yard maintenance and arranging alternate transportation services. Revenues from these services have historically represented less than one percent of our total revenues. In 2007, our financial results were not significantly impacted by the sale of limestone products by our affiliate, Mid-America Carbonates, LLC (“MAC”).

Reportable Segments

Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Segment Information under “Item 8. Financial Statements and Supplementary Data—Note 21. Segment Information” for information concerning our reportable segments.

Coal Marketing and Sales

As is customary in the coal industry, we have entered into long-term coal supply agreements with many of our customers. These arrangements are mutually beneficial to us and our customers in that they provide greater predictability of sales volumes and sales prices. In 2007, approximately 90.2% and 89.3% of our sales tonnage and total coal sales, respectively, were sold under long-term contracts (contracts having a term of one year or greater) with maturities ranging from 2008 to 2024. Our total nominal commitment under significant long-term contracts for existing operations was approximately 100.0 million tons at December 31, 2007, and is expected to be delivered as follows: 26.8 million tons in 2008, 18.9 million tons in 2009, 15.5 million tons in 2010, and 38.8 million tons thereafter during the remaining terms of the relevant coal supply agreements. The total commitment of coal under contract is an approximate number because, in some instances, our contracts contain provisions that could cause the nominal total commitment to increase or decrease by as much as 20%. The contractual time commitments for customers to nominate future purchase volumes under these contracts are sufficient to allow us to balance our sales commitments with prospective production capacity. In addition, the nominal total commitment can otherwise change because of price reopener provisions contained in certain of these long-term contracts.

The provisions of long-term contracts are the results of both bidding procedures and extensive negotiations with each customer. As a result, the provisions of these contracts vary significantly in many respects, including, among others, price adjustment features, price and contract reopener terms, permitted sources of supply, force majeure provisions, coal qualities, and quantities. Virtually all of our long-term contracts are subject to price adjustment provisions, which permit an increase or decrease periodically in the contract price to reflect changes in specified price indices or items such as taxes, royalties or actual production costs. These provisions, however, may not assure that the contract price will reflect every change in production or other costs. Failure of the parties to agree on a price pursuant to an adjustment or a reopener provision can lead to early termination of a contract. Some of the long-term contracts also

permit the contract to be reopened for renegotiation of terms and conditions other than the pricing terms, and where a mutually acceptable agreement on terms and conditions cannot be concluded, either party may have the option to terminate the contract. The long-term contracts typically stipulate procedures for quality control, sampling and weighing. Most contain provisions requiring us to deliver coal within stated ranges for specific coal characteristics such as heat, sulfur, ash, moisture, grindability, volatility and other qualities. Failure to meet these specifications can result in economic penalties or termination of the contracts. While most of the contracts specify the approved seams and/or approved locations from which the coal is to be mined, some contracts allow the coal to be sourced from more than one mine or location. Although the volume to be delivered pursuant to a long-term contract is stipulated, the buyers often have the option to vary the volume within specified limits.

Reliance on Major Customers

Our three largest customers in 2007 were SSO, Mt. Storm and Seminole. During 2007, we derived approximately 37.9% of our total revenues from these three customers, which individually accounted for 10.0% or more of our 2007 total revenues. For more information about these customers, please read “Item 8. Financial Statements and Supplementary Data – Note 20. Concentration of Credit Risk and Major Customers.”

Competition

The coal industry is intensely competitive. The most important factors on which we compete are coal quality (including sulfur and heat content), transportation costs from the mine to the customer and the reliability of supply. Our principal competitors include Alpha Natural Resources, Inc., Arch Coal, Inc., CONSOL Energy, Inc., Foundation Coal Holdings, Inc., International Coal Group, Inc., James River Coal Company, Massey Energy Company, Murray Energy, Inc., Patriot Coal Corporation and Peabody Energy Corp. Some of these coal producers are larger and have greater financial resources and larger reserve bases than we do. We also compete directly with a number of smaller producers in the Illinois Basin, Central Appalachian and Northern Appalachian regions. As the price of domestic coal increases, we may also begin to compete with companies that produce coal from one or more foreign countries.

Additionally, coal competes with other fuels such as petroleum, natural gas, hydropower and nuclear energy for steam and electrical power generation. Over time, costs and other factors, such as safety and environmental considerations, may affect the overall demand for coal as a fuel.

Transportation

Our coal is transported to our customers by rail, truck and barge. Depending on the proximity of the customer to the mine and the transportation available for delivering coal to that customer, transportation costs can range from 6% to 65% of the total delivered cost of a customer’s coal. As a consequence, the availability and cost of transportation constitute important factors in the marketability of coal. We believe our mines are located in favorable geographic locations that minimize transportation costs for our customers, and in many cases we are able to accommodate transportation options. Typically, our customers pay the transportation costs from the mine or preparation plant to the destination, which is the standard practice in the industry. In 2007, the largest volume transporter of our coal shipments, including coal synfuel shipped by SSO, was CSX, which moved approximately 38.8% of our tonnage over its rail system. The practices of, and rates set by, the transportation company serving a particular mine or customer might affect, either adversely or favorably, our marketing efforts with respect to coal produced from the relevant mine.

Regulation and Laws

The coal mining industry is subject to regulation by federal, state and local authorities on matters such as:

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employee health and safety;

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mine permits and other licensing requirements;

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air quality standards;

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water quality standards;

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storage of petroleum products and substances which are regarded as hazardous under applicable laws or which, if spilled, could reach waterways or wetlands;

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plant and wildlife protection;

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reclamation and restoration of mining properties after mining is completed;

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the discharge of materials into the environment;

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storage and handling of explosives;

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wetlands protection;

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surface subsidence from underground mining; and

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the effects, if any, that mining has on groundwater quality and availability.

In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal. It is possible that new legislation or regulations may be adopted, or that existing laws or regulations may be differently interpreted or more stringently enforced, any of which could have a significant impact on our mining operations or our customers’ ability to use coal.

We are committed to conducting mining operations in compliance with applicable federal, state and local laws and regulations. However, because of the extensive and detailed nature of these regulatory requirements, it is extremely difficult for us and other underground coal mining companies in particular, as well as the coal industry in general to comply with all requirements at all times. None of our violations to date has had a material impact on our operations or financial condition. While it is not possible to quantify the costs of compliance with applicable federal and state laws and the associated regulations, those costs have been and are expected to continue to be significant. Compliance with these laws and regulations has substantially increased the cost of coal mining for domestic coal producers.

Capital expenditures for environmental matters have not been material in recent years. We have accrued for the present value of the estimated cost of asset retirement obligations and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement obligations and mine closing costs are based upon permit requirements and the costs and timing of asset retirement obligations and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if we later determine these accruals to be insufficient.

Mining Permits and Approvals

Numerous governmental permits or approvals are required for mining operations. Applications for permits require extensive engineering and data analysis and presentation, and must address a variety of environmental, health, and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage, use and disposal of waste and other substances and other impacts on the environment, the construction of water containment areas, and reclamation of the area after coal extraction. Meeting all requirements imposed by any of these authorities may be costly and time consuming, and may delay or prevent commencement or continuation of mining operations in certain locations.

As is typical in the coal industry, we strive to obtain mining permits within a time frame that allows us to mine reserves as planned on an uninterrupted basis. Typically, we commence actions to obtain permits between 18 and 24 months before we plan to mine a new area. In our experience, permits generally are approved within 12 to 18 months after a completed application is submitted, although regulatory authorities exercise considerable discretion in the timing and scope of permit issuance and the public has rights to engage in the permitting process, including intervention in the courts, which can cause delay. Generally, we have not experienced material difficulties in obtaining mining permits in the areas where our reserves are located. However, the permitting process for certain mining operations has extended over several years and we cannot assure you that we will not experience difficulty or delays in obtaining mining permits in the future.

We are required to post bonds to secure performance under our permits. Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws and regulations described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws and regulations. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations that have outstanding environmental violations. Although, like other coal companies, we have been cited for violations in the ordinary course of our business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

Recently, two townships in Pennsylvania enacted ordinances that purport to prohibit all coal mining activities within the townships, invalidate mining permits issued by any state or federal government entity, and, in some instances, require

divestiture of all currently held coal property interests. Some of the coal reserves of our Tunnel Ridge and Penn Ridge subsidiaries are located within these townships. We believe these ordinances violate several provisions of the United States Constitution and the Pennsylvania Constitution as well as federal and state mining laws, and we will initiate legal action seeking to have them invalidated if necessary. We believe such litigation would be successful. However, in the event it was not and these ordinances were not repealed, the ordinances would prevent mining our properties within those townships which could adversely affect our results of operation and financial condition.

Mine Health and Safety Laws

Stringent safety and health standards have been imposed by federal legislation since 1969 when the Federal Coal Mine Health and Safety Act of 1969 (“CMHSA”) was adopted. The Federal Mine Safety and Health Act of 1977 (“FMSHA”), and regulations adopted pursuant thereto, significantly expanded the enforcement of health and safety standards of the CMHSA, and imposed extensive and detailed safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations, and numerous other matters. MSHA monitors and rigorously enforces compliance with these federal laws and regulations. In addition, as part of the FMSHA, the Federal Black Lung Benefits Act (“BLBA”), requires payments of benefits by all businesses that conduct current mining operations to coal miners with black lung disease and to some survivors of miners who die from this disease. Most of the states where we operate also have state programs for mine safety and health regulation and enforcement. In combination, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and rigorous system for protection of employee safety and health affecting any segment of any industry, and this regulation has a significant effect on our operating costs. Our competitors in all of the areas in which we operate are subject to the same laws and regulations.

Mining accidents resulting in fatalities in West Virginia and Kentucky in early 2006 received national attention and prompted responses at both the national and state level, leading to increased scrutiny of industry safety practices and emergency response and evacuation procedures aimed primarily at underground coal mining operations, as well as costly new requirements for additional emergency equipment and safety structures. For example, on March 9, 2006, MSHA published new emergency rules on mine safety, which imposed new mine safety equipment, training, and emergency reporting requirements which became effective immediately upon their publication in the Federal Register. Building on MSHA’s regulatory efforts, Congress passed the Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”), which was signed into law on June 15, 2006. The MINER Act significantly amends the FMSHA, requiring improvements in mine safety practices, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, MSHA published a final rule, which, among other things, revised the emergency rules to comport with the requirements of the Act. The final rule became effective on December 8, 2006. Civil penalties for regulatory violations were also increased substantially by new MSHA rules that took effect on April 23, 2007. Then, on May 22, 2007, extremely stringent “Emergency Temporary Standards” for sealing off abandoned areas of underground coal mines took effect, pending further study and possible modification.

At the state level, West Virginia enacted legislation in January 2006 imposing stringent new mine safety and accident reporting requirements and increasing civil and criminal penalties for violations of mine safety laws. Other states, including Illinois, Pennsylvania, and Kentucky, have either proposed or passed similar bills and resolutions addressing mine safety practices, and it is possible that additional state mine safety bills may be passed at some point in the future. Fatalities related to an August 2007 mine accident in Utah also triggered intensified regulatory scrutiny and gave momentum to pending federal legislation to impose additional safety and health requirements on coal mining. Although we are unable to quantify the full impact, implementing and complying with these new laws and regulations have and are expected to continue to have an adverse impact on our results of operation and financial position.

Black Lung Benefits Act

The BLBA levies a tax on production of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price, in order to compensate miners who are totally disabled due to black lung disease and some survivors of miners who died from this disease, and who were last employed as miners prior to 1970 or subsequently where no responsible coal mine operator has been identified for claims. In addition, BLBA provides that some claims for which coal operators had previously been responsible are or will become obligations of the government trust funded by the tax. The Revenue Act of 1987 extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent. For miners last employed as miners after 1969 and who are determined to have contracted black lung, we self-insure the potential cost of compensating such miners using our actuary estimates of the cost of present and future claims. We are also liable under state statutes for black lung claims.

Revised BLBA regulations took effect in January 2001, relaxing the stringent award criteria established under previous regulations and thus potentially allowing more new federal claims to be awarded and allowing previously denied claimants to re-file under the revised criteria. These regulations may also increase black lung related medical costs by broadening the scope of conditions for which medical costs are reimbursable, and increase legal costs by shifting more of the burden of proof to the employer. Moreover, Congress and state legislatures regularly consider various items of black lung legislation that, if enacted, could adversely affect our business, financial condition, and results of operation.

Workers’ Compensation

We are required to compensate employees for work-related injuries. Several states in which we operate consider changes in workers’ compensation laws from time to time. We generally self-insure this potential expense using our actuary estimates of the cost of present and future claims. For more information concerning our requirement to maintain bonds to secure our workers’ compensation obligations, see the discussion of surety bonds below under “—Surface Mining Control and Reclamation Act.”

Coal Industry Retiree Health Benefits Act

The Federal Coal Industry Retiree Health Benefits Act (“CIRHBA”) was enacted to fund health benefits for some United Mine Workers of America retirees. CIRHBA merged previously established union benefit plans into a single fund into which “signatory operators” and “related persons” are obligated to pay annual premiums for beneficiaries. CIRHBA also created a second benefit fund for miners who retired between July 21, 1992, and September 30, 1994, and whose former employers are no longer in business. Because of our union-free status, we are not required to make payments to retired miners under CIRHBA, with the exception of limited payments made on behalf of predecessors of MC Mining. However, in connection with the sale of the coal assets acquired by ARH in 1996, MAPCO Inc., now a wholly-owned subsidiary of The Williams Companies, Inc., agreed to retain, and be responsible for, all liabilities under CIRHBA.

Surface Mining Control and Reclamation Act

The Federal Surface Mining Control and Reclamation Act (“SMCRA”), establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities.

SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore the surface to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. We believe we are in compliance in all material respects with applicable regulations relating to reclamation.

In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The Abandoned Mine Lands Tax was set to expire June 30, 2006; however, on December 20, 2006, President Bush signed into law the “Tax Relief and Health Care Act of 2006,” which, among other things, extended the Abandoned Mine Reclamation Fund provisions until September 30, 2021. This new law also reduced the tax for surface-mined and underground-mined coal to $0.315 per ton and $0.135 per ton, respectively, beginning in the fourth quarter 2007 through 2012. In fiscal years 2013 through 2021, the tax for surface-mined and underground-mined coal will be reduced to $0.28 per ton and $0.12 per ton, respectively. We have accrued the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation or orphaned mine sites and acid mine drainage (“AMD”) control on a statewide basis.

Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine operators and other third-parties can be imputed to other companies that are deemed, according to the regulations, to have “owned” or “controlled” the third-party violator. Sanctions against the “owner” or “controller” are quite severe and can include being blocked from receiving new permits and having any permits that have been issued since the time of the violations revoked or, in the case of civil penalties and reclamation fees, since the time those amounts became due. Also, on February 1, 2008, the Citizens Coal Council and the Kentucky Resources Council filed a complaint in the U.S. District Court for the District of Columbia challenging the Federal Office of Surface Mining’s (“OSM”) final rule on ownership and control, including the core definitions of “control,” “own” and “transfer, assignment or sale of permit rights”, adding to the uncertainty in this area. We are not aware of any currently pending or asserted claims against us relating to the “ownership” or “control” theories discussed above. However, we cannot assure you that such claims will not be asserted in the future.

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, to pay certain black lung claims, and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for us and for our competitors to secure new surety bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. It is possible that surety bonds issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on us. In addition, bonding requirements in some states have become more onerous. For example, West Virginia’s bonding system requires coal companies to post site-specific bonds in an amount up to $5,000.00 per acre and imposes a per-ton tax on mined coal, currently set at $0.07/ton, which is paid to the West Virginia Special Reclamation Fund (“SRF”). An environmental group is claiming the SRF is underfunded and that the OSM has an obligation under SMCRA to ensure the SRF funds are increased to cover the supposed shortfall. See The West Virginia Highlands Conservancy, Plaintiff, v. Dirk Kempthorne, Secretary of the Department of the Interior, et al., Defendants, and the West Virginia Coal Association, Intervenor/Defendant, Civil Action No. 2:00-cv-1062 (United States District Court for the Southern District of West Virginia). If the Court ultimately agrees, we could be forced to bear an increase in the tax on coal mined in West Virginia.

Air Emissions

The CAA and similar state and local laws and regulations that regulate emissions into the air, affect coal mining operations. The CAA directly impacts our coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants. There have been a series of federal rulemakings focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and any additional measures required under the U.S. Environmental Protection Agency (“EPA”) laws and regulations will make it more costly to operate coal-fired power plants and, depending on the requirements of the implementation plan of the state in which each plant is located, could make coal a less attractive fuel alternative in the planning and building of power plants in the future. Any reduction in coal’s share of power generating capacity could have a material adverse effect on our business, financial condition and results of operations.

The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels.

The EPA has promulgated rules, referred to as the “Nitrogen Oxide SIP Call,” that require coal-fired power plants in 21 eastern states and Washington D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. Additionally, in March 2005, the EPA issued the final Clean Air Interstate Rule (“CAIR”), which will permanently cap nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. beginning in 2009 and 2010, respectively. CAIR requires these states to achieve the required

nitrogen oxide and sulfur dioxide emission reductions by requiring power plants to either participate in an EPA-administered “cap-and-trade” program that caps these emissions in two phases, or by meeting an individual state emissions budget through measures established by the state. Similarly, in March 2005, the EPA finalized the Clean Air Mercury Rule (“CAMR”), which establishes a two-part, nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. If fully implemented, CAMR would permit states to develop and manage their own mercury control regulations or participate in an interstate cap-and-trade program for mercury emission allowances. The CAIR and CAMR rules are the subject of ongoing litigation, and on February 8, 2008, the D.C. Circuit Court of Appeals vacated the CAMR rule for further consideration by the EPA. While the future of CAIR and CAMR is uncertain, the additional costs that could be associated with the implementation of rules like these at operating coal-fired power generation facilities could render coal a less attractive fuel source.

The EPA has adopted new, more stringent national air quality standards for ozone and fine particulate matter. As a result, some states will be required to amend their existing state implementation plans to attain and maintain compliance with the new air quality standards. For example, in December 2004, the EPA designated specific areas in the United States as being in “non-attainment” regions subject to new national ambient air quality standard for fine particulate matter. In March 2007, the EPA published final rules addressing how states would implement plans to bring applicable non-attainment regions into compliance with the new air quality standard. Under the EPA’s final rulemaking, states have until April 2008 to submit their implementation plans to the EPA for approval. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, our mining operations and our customers could be affected when the new standards are implemented by the applicable states.

In June 2005, the EPA announced final amendments to its regional haze program originally developed in 1999 to improve visibility in national parks and wilderness areas. As part of the new rules, affected states were required to develop implementation plans by December 2007 that, among other things, identify facilities that will have to reduce emissions and comply with stricter emission limitations. This program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas. In addition, this program may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide, and particulate matter. Demand for our coal could be affected when these new standards are implemented by the applicable states.

The Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities, including some of our customers, alleging violations of the new source review provisions of the CAA. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the new source review program. Several of these lawsuits have settled, but others remain pending. Depending on the ultimate resolution of these cases, demand for our coal could be affected.

Carbon Dioxide Emissions

The Kyoto Protocol to the United Nations Framework Convention on Climate Change calls for developed nations to reduce their emissions of greenhouse gases to 5% below 1990 levels by 2012. Carbon dioxide, which is a major by-product of the combustion of coal and other fossil fuels, is subject to the Kyoto Protocol. The Kyoto Protocol went into effect on February 16, 2005, for those nations that ratified the treaty.

Although the United States is not participating in the Kyoto Protocol, the current session of Congress is considering climate control legislation, including multiple bills introduced in the House and the Senate that would restrict greenhouse gas emissions. Several states have already adopted legislation, regulations and/or regulatory initiatives to reduce emissions of greenhouse gases. For instance, California recently adopted the “California Global Warming Solutions Act of 2006,” which requires the California Air Resources Board to achieve a 25% reduction in emissions of greenhouse gases from sources in California by 2020.

On April 2, 2007, the United States Supreme Court held in Massachusetts v. EPA that unless EPA affirmatively concludes that greenhouse gases are not causing climate change, the EPA must regulate greenhouse gas emissions from new automobiles under the CAA. The Supreme Court remanded the matter to the EPA for further consideration. This litigation did not directly concern the EPA’s authority to regulate greenhouse gas emissions from stationary sources, such as coal mining operations or coal-fired power plants. However, the Court’s decision is likely to influence another lawsuit that was filed in the U.S. Court of Appeals for the District of Columbia Circuit, involving a challenge to the EPA’s decision not to regulate carbon dioxide from power plants and other stationary sources under a CAA new source

performance standard rule, which specifies emissions limits for new facilities. The court remanded the question to the EPA for further consideration in light of the ruling in Massachusetts v. EPA. Any federal or state restrictions on emissions of greenhouse gases that may be imposed in areas of the United States in which we conduct business could adversely affect our operations and demand for our products.

The permitting of a number of proposed new coal-fired power plants has also recently been contested by environmental organizations for concerns related to greenhouse gas emissions from new plants. In October 2007, state regulators in Kansas became the first to deny an air emissions construction permit for a new coal-fired power plant based on the plant’s projected emissions of carbon dioxide. State regulatory authorities in Florida and North Carolina have also rejected the construction of new coal-fired power plants based on the uncertainty surrounding the potential costs associated with greenhouse gas emissions from these plants under future laws limiting the emission of carbon dioxide. In several states, where new coal-fired power plants have been approved without limits imposed on their greenhouse gas emissions, environmental organizations have appealed the issuance of the CAA permits for these facilities to the EPA’s Environmental Appeals Board (“EAB”). In January 2008, the EAB ruled on the Illinois petition, denying review on procedural grounds.

While higher prices for natural gas and oil, and improved efficiencies and new technologies for coal-fired electric power generation have helped to increase demand for our coal, it is possible that future federal and state initiatives to control carbon dioxide emissions could result in increased costs associated with coal consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for coal consumption could result in some customers switching to alternative sources of fuel, which could have a material adverse effect on our business, financial condition, and results of operations.

Water Discharge

The Federal Clean Water Act (“CWA”) and similar state and local laws and regulations affect coal mining operations by imposing restrictions on effluent discharge into waters and the discharge of dredged or fill material into the waters of the United States. Regular monitoring, as well as compliance with reporting requirements and performance standards, is a precondition for the issuance and renewal of permits governing the discharge of pollutants into water. Section 404 of the CWA imposes permitting and mitigation requirements associated with the dredging and filling of wetlands and streams. The CWA and equivalent state legislation, where such equivalent state legislation exists, affect coal mining operations that impact wetlands and streams. Although permitting requirements have been tightened in recent years, we believe we have obtained all necessary permits required under CWA Section 404 as it has traditionally been interpreted by the responsible agencies. However, mitigation requirements under existing and possible future “fill” permits may vary considerably. For that reason, the setting of post-mine asset retirement obligation accruals for such mitigation projects is difficult to ascertain with certainty and may increase in the future. Although more stringent permitting requirements may be imposed in the future, we are not able to accurately predict the impact, if any, of such permitting requirements.

The U.S. Army Corps of Engineers (“Corps of Engineers”) maintains two permitting programs under CWA Section 404: one for “individual” permits and a more streamlined program for “general” permits.

Recent federal district court decisions in West Virginia, and related litigation filed in federal district court in Kentucky, have created uncertainty regarding the future ability to obtain general permits authorizing the construction of valley fills for the disposal of overburden from mining operations. A July 2004 decision by the Southern District of West Virginia in Ohio Valley Environmental Coalition v. Bulen enjoined the Huntington District of the Corps of Engineers from issuing further permits pursuant to Nationwide Permit 21, which is a general permit issued by the Corps of Engineers to streamline the process for obtaining permits under Section 404 of the CWA. The Fourth Circuit Court of Appeals issued a decision on November 23, 2005, vacating the district court decision in Bulen and remanding the case to the lower court for consideration of further challenge to the general permit. That challenge is still pending. A similar lawsuit, Kentucky Riverkeeper v. Rowlette, has been filed in federal district court in Kentucky that seeks to enjoin the issuance of permits pursuant to Nationwide Permit 21 by the Louisville District of the U.S. Army Corps of Engineers. We do not operate any mines located within the Southern District of West Virginia and currently only utilize Nationwide Permit 21 at one location in Indiana. In the event current or future litigation contesting the use of Nationwide Permit 21 is successful, we may be required to apply for individual discharge permits pursuant to Section 404 of the CWA in areas that would have otherwise utilized Nationwide Permit 21. Such a change could result in delays in obtaining required mining permits to conduct operations, which could in turn result in reduced production, cash flow, and profitability.

On September 22, 2005, environmental groups led by the Ohio Valley Environmental Coalition filed suit in the Federal District Court for the Southern District of West Virginia challenging the Corps of Engineers’ authority to issue individual CWA Section 404 discharge permits for certain mountaintop mining projects. The case, styled Ohio Valley Environmental Coalition v. United States Army Corps of Engineers, alleges that the Corps of Engineers generally acted arbitrarily and capriciously in issuing certain Section 404 permits to operators engaged in mountaintop mining operations. By order of March 23, 2007, the Court rescinded four individual permits, ruling that the Corps of Engineers had not properly supported its findings that permitted fills would not cause significant impacts. The case has been remanded to the Corps of Engineers for further evaluation of the applications, and the Corps of Engineers could be required to conduct a more extensive “Environmental Impact Statement” for each permit, a process that could add substantial time to a permit decision and result in a permit denial. The decision is on appeal to the Fourth Circuit, and should be resolved sometime in 2008.

By order of June 13, 2007, the same Court issued another order declaring that discharges from valley fills into sediment ponds constructed in-stream and used to control levels of sediment and other pollutants from mine sites must themselves be permitted under the CWA and meets the same standards as the effluent discharged from these ponds. Because it is frequently impracticable to construct these ponds in locations other than an existing stream channel without moving substantial amounts of additional overburden, compliance with this order could substantially increase development costs at new mining operations in West Virginia. This order is also on appeal to the Fourth Circuit. In December 2007, a similar lawsuit has been filed against the Corps of Engineers in the federal court in the Western District of Kentucky (Kentucky Waterways Alliance, Inc., et al. v. U.S. Army Corps of Engineers, et al., Civil Action No. 3:07-cv-00677) challenging a permit issued to a mining operation located in Leslie County, Kentucky. The Corps of Engineers has voluntarily suspended its consideration of the permit application in that case for agency re-evaluation, and the case is currently stayed.

Although our mining operations are not implicated in any of these particular cases, it is possible that litigation affecting the Corps of Engineers’ ability to issue CWA permits could adversely affect our ability to obtain permits in a timely manner and could therefore adversely affect our results of operation and financial position.

Each state is required to submit to the EPA their biennial CWA Section 303(d) lists identifying all waterbodies not meeting state specified water quality standards. For each listed waterbody, the state is required to begin developing a Total Maximum Daily Load (“TMDL”) to:

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determine the maximum pollutant loading the waterbody can assimilate without violating water quality standards;

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identify all current pollutant sources and loadings to that waterbody;

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calculate the pollutant loading reduction necessary to achieve water quality standards; and

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establish a means of allocating that burden among and between the point and non-point sources contributing pollutants to the waterbody.

We are currently participating in stakeholders meetings and in negotiations with various states and the EPA to establish reasonable TMDLs that will accommodate expansion of our operations. These and other regulatory developments may restrict our ability to develop new mines, or could require our customers or us to modify existing operations, the extent of which we cannot accurately or reasonably predict.

The Federal Safe Drinking Water Act (“SDWA”) and its state equivalents affect coal mining operations by imposing requirements on the underground injection of fine coal slurry, fly ash, and flue gas scrubber sludge, and by requiring permits to conduct such underground injection activities. The inability to obtain these permits could have a material impact on our ability to inject such materials into the inactive areas of some of our old underground mine workings.

In addition to establishing the underground injection control program, the SDWA also imposes regulatory requirements on owners and operators of “public water systems.” This regulatory program could impact our reclamation operations where subsidence or other mining-related problems require the provision of drinking water to affected adjacent homeowners. However, it is unlikely that any of our reclamation activities would fall within the definition of a “public water system.” While we have several drinking water supply sources for our employees and contractors that are subject to SDWA regulation, the SDWA is unlikely to have a material impact on our operations.

Hazardous Substances and Wastes

The Federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), otherwise known as the “Superfund” law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for the release of hazardous substances may be subject to joint and several liability under CERCLA for the costs of cleaning up the hazardous substances released into the environment and for damages to natural resources. Some products used in coal mining operations generate waste containing hazardous substances. We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.

The Federal Resource Conservation and Recovery Act (“RCRA”) and corresponding state laws regulating hazardous waste affect coal mining operations by imposing requirements for the generation, transportation, treatment, storage, disposal, and cleanup of hazardous wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous substances. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.

In 2000, the EPA declined to impose hazardous waste regulatory controls on the disposal of some coal combustion by-products (“CCB”), including the practice of using CCB as mine fill. However, under pressure from environmental groups, the EPA has continued evaluating the possibility of placing additional solid waste burdens on the disposal of such materials. On March 1, 2006, the National Academy of Sciences released a report commissioned by Congress that studied CCB mine filling practices and recommended federal regulatory oversight of CCB mine filling under either SMCRA or the non-hazardous waste provisions of RCRA. As a result of this report, OSM on March 14, 2007 issued an Advanced Notice of Rule Making proposing federal regulations on CCB mine filling practices. On August 29, 2007, EPA published a Notice of Data Availability concerning information regarding the disposal of CCB in landfills and surface impoundments that has been generated since the decision in 2000. No rules on the land disposal of CCB have yet been released. Accordingly, although we believe the beneficial uses of CCB that we employ do not constitute poor environmental practices, it is not currently possible to assess how any such regulations would impact our operations or those of our customers.

Other Environmental, Health And Safety Regulation

In addition to the laws and regulations described above, we are subject to regulations regarding underground and above ground storage tanks in which we may store petroleum or other substances. Some monitoring equipment that we use is subject to licensing under the Federal Atomic Energy Act. Water supply wells located on our properties are subject to federal, state, and local regulation.

The Federal Safe Explosives Act (“SEA”) applies to all users of explosives. Knowing or willful violations of SEA may result in fines, imprisonment, or both. In addition, violations of SEA may result in revocation of user permits and seizure or forfeiture of explosive materials.

The costs of compliance with these requirements should not have a material adverse effect on our business, financial condition or results of operations.

Employees

To conduct our operations, we employ approximately 2,600 employees, including approximately 150 corporate employees and approximately 2,450 employees involved in active mining operations. Our work-force is entirely union-free. We believe that relations with our employees are generally good.

Administrative Services

In connection with AHGP’s IPO, ARLP entered into an administrative services agreement (“Administrative Services Agreement”) with our managing general partner, our Intermediate Partnership, AGP, AHGP and Alliance Resource Holdings, II (“ARH II”). Under the Administrative Services Agreement, certain employees, including some executive officers, provide administrative services for AHGP and ARH II and their respective affiliates. We are reimbursed for services rendered by our employees on behalf of these entities as provided under the Administrative Services Agreement. We billed and recognized administrative service revenue under this agreement of $0.3 million for the year ended December 31, 2007 from AHGP and $0.4 million for the year ended December 31, 2007 from ARH II. Please read “Item 13 – Certain Relationships and Related Transactions, and Director Independence – Administrative Services.”

Managing General Partner Contribution

During 2007 our managing general partner contributed 50,980 common units of AHGP, valued at approximately $1.1 million at the time of contribution, and $0.8 million of cash to us for the purpose of funding certain expenses associated with our employee compensation programs. As provided under our partnership agreement, we made a special allocation to our managing general partner of certain general and administrative expenses equal to the amount of the contribution. Please read “Item 13 – Certain Relationships and Related Transactions, and Director Independence – Managing General Partner Contribution.”

ITEM 1A.

RISK FACTORS

Risks Inherent in an Investment in Us

Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.

The amount of cash we can distribute to holders of our common units or other partnership securities each quarter principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

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the amount of coal we are able to produce from our properties;

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the price at which we are able to sell coal, which is affected by the supply of and demand for domestic and foreign coal;

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the level of our operating costs;

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weather conditions;

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the proximity to and capacity of transportation facilities;

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domestic and foreign governmental regulations and taxes;

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the price and availability of alternative fuels;

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the effect of worldwide energy conservation measures; and

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prevailing economic conditions.

In addition, the actual amount of cash available for distribution will depend on other factors, including:

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the level of our capital expenditures;

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the cost of acquisitions, if any;

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our debt service requirements and restrictions on distributions contained in our current or future debt agreements;

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fluctuations in our working capital needs;

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our ability to borrow under our credit agreement to make distributions to our unitholders; and

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the amount, if any, of cash reserves established by our managing general partner, in its discretion, for the proper conduct of our business.

Because of these factors, we may not have sufficient available cash to pay a specific level of cash distributions to our unitholders. Furthermore, you should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowing, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses and may be unable to make cash distributions during periods when we record net income. Please read “—Risks Related to our Business” for a discussion of further risks affecting our ability to generate distributable cash flow.

We may issue an unlimited number of limited partner interests, on terms and conditions established by our managing general partner, without the consent of our unitholders, which will dilute your ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.

The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

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our unitholders’ proportionate ownership interest in us will decrease;

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the amount of cash available for distribution on each unit may decrease;

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the relative voting strength of each previously outstanding unit may be diminished;

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the ratio of taxable income to distributions may increase; and

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the market price of our common units may decline.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public markets, including sales by our existing unitholders.

As of December 31, 2007, AHGP owned 15,544,169 of our common units. AHGP also owns our managing general partner. In the future, AHGP may sell some or all of these units or it may distribute our common units to the holders of its equity interests and those holders may dispose of some or all of these units. The sale or disposition of a substantial number of our common units in the public markets could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.

An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

The credit and risk profile of our managing general partner and its owners could adversely affect our credit ratings and profile.

The credit and risk profile of our managing general partner or owners of our managing general partner may be factors in credit evaluations of us as a master limited partnership. This is because our managing general partner can exercise significant influence over our business activities, including our cash distribution policy, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of AHGP, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness. As of December 31, 2007, AHGP had no outstanding debt.

AHGP is principally dependent on the cash distributions from its general and limited partner equity interests in us to service its indebtedness. Any distribution by us to AHGP will be made only after satisfying our then-current obligations to our creditors. Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect that we are separate from AHGP and entities that control AHGP, our credit ratings and risk profile could be adversely affected if the ratings and risk profiles of such entities were viewed as substantially lower or more risky than ours.

Our unitholders do not elect our managing general partner or vote on our managing general partner’s officers or directors. As of December 31, 2007, AHGP owned approximately 42.5% of our outstanding units, a sufficient number to block any attempt to remove our general partner.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our managing general partner and will have no right to elect our managing general partner on an annual or other continuing basis.

In addition, if our unitholders are dissatisfied with the performance of our managing general partner, they will have little ability to remove our general partner. Our managing general partner may not be removed except upon the vote of the holders of at least 66.7% of our outstanding units. As of December 31, 2007, AHGP held approximately 42.5% of our outstanding units. Consequently, it will be particularly difficult for our managing general partner to be removed without the consent of AHGP. As a result, the price at which our units trade may be lower because of the absence or reduction of a takeover premium in the trading price.

Furthermore, unitholders’ voting rights are further restricted by a provision in our partnership agreement that provides that any units held by a person that owns 20.0% or more of any class of units then outstanding, other than our managing general partner and its affiliates, cannot be voted on any matter.

The control of our managing general partner may be transferred to a third-party without unitholder consent.

Our managing general partner may transfer its general partner interest in us to a third-party in a merger or in a sale of its equity securities without the consent of our unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the members of our managing general partner to sell or transfer all or part of their ownership interest in our managing general partner to a third-party. The new owner or owners of our managing general partner would then be in a position to replace the directors and officers of our managing general partner and control the decisions made and actions taken by the Board of Directors and officers.

Unitholders may be required to sell their units to our managing general partner at an undesirable time or price.

If at any time less than 20.0% of our outstanding common units are held by persons other than our general partners and their affiliates, our managing general partner will have the right to acquire all, but not less than all, of those units at a price no less than their then-current market price. As a consequence, a unitholder may be required to sell his common units at an undesirable time or price. Our managing general partner may assign this purchase right to any of its affiliates or to us.

Cost reimbursements due to our general partners may be substantial and may reduce our ability to pay the distributions to unitholders.

Prior to making any distributions to our unitholders, we will reimburse our general partners and their affiliates for all expenses they have incurred on our behalf. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to the unitholders. Our managing general partner has sole discretion to determine the amount of these expenses and fees. For additional information, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Related-Party Transactions, Administrative Services, and Item 8. Financial Statements and Supplementary Data – Note 18. Related-Party Transactions.”

Your liability as a limited partner may not be limited, and our unitholders may have to repay distributions or make additional contributions to us under certain circumstances.

As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a general partner if you participate in the “control” of our business. Our general partner generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions.

Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Our partnership agreement limits our managing general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partners that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that waive or consent to conduct by our managing general partner and its affiliates and which reduce the obligations to which our managing general partner would otherwise be held by state-law fiduciary duty standards. The following is a summary of the material restrictions contained in our partnership agreement on the fiduciary duties owed by our general partners to the limited partners. Our partnership agreement:

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permits our managing general partner to make a number of decisions in its “sole discretion.” This entitles our managing general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

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provides that our managing general partner is entitled to make other decisions in its “reasonable discretion”;

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generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our managing general partner may consider the interests of all parties involved, including its own. Unless our managing general partner has acted in bad faith, the action taken by our managing general partner shall not constitute a breach of its fiduciary duty; and

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provides that our general partners and our officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our general partners and those other persons acted in good faith.

In order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above.

Some of our executive officers and directors face potential conflicts of interest in managing our business.

Certain of our executive officers and directors are also officers and/or directors of AHGP. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our unitholders’ best interests. In addition, these overlapping executive officers and directors allocate their time among us and AHGP. These officers and directors face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

Our managing general partner’s discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

Our partnership agreement requires our managing general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.

Our general partners have conflicts of interest and limited fiduciary responsibilities, which may permit our general partners to favor their own interests to the detriment of our unitholders.

As of December 31, 2007, AHGP owned approximately 42.5% of our outstanding limited partner interests. Conflicts of interest could arise in the future as a result of relationships between our general partners and their affiliates, on the one hand, and us, on the other hand. As a result of these conflicts our general partners may favor their own interests and those of their affiliates over the interests of our unitholders. The nature of these conflicts includes the following considerations:

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Remedies available to our unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty are limited. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other duties under applicable state law.

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Our managing general partner is allowed to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duties to our unitholders.

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Our general partners’ affiliates are not prohibited from engaging in other businesses or activities, including those in direct competition with us, except as provided in the omnibus agreement (please see “Item 13. Certain Relationships and Related Transactions, and Director Independence – Omnibus Agreement”).

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Our managing general partner determines the amount and timing of our asset purchases and sales, capital expenditures, borrowings and reserves, each of which can affect the amount of cash that is distributed to unitholders.

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Our managing general partner determines whether to issue additional units or other equity securities in us.

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Our managing general partner determines which costs are reimbursable by us.

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Our managing general partner controls the enforcement of obligations owed to us by it.

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Our managing general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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Our managing general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or from entering into additional contractual arrangements with any of these entities on our behalf.

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In some instances our managing general partner may borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

Risks Related to our Business

A substantial or extended decline in coal prices could negatively impact our results of operations.

The prices we receive for our production depends upon factors beyond our control, including:

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the supply of and demand for domestic and foreign coal;

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the price and availability of alternative fuels;

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weather conditions;

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the proximity to, and capacity of, transportation facilities;

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worldwide economic conditions;

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domestic and foreign governmental regulations and taxes; and

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the effect of worldwide energy conservation measures.

A substantial or extended decline in coal prices could materially and adversely affect us by decreasing our revenues in the event that we are not otherwise protected pursuant to the specific terms of our coal supply agreements.

A material amount of our net income and cash flow has been dependent on our ability to realize direct or indirect benefits from federal income tax credits such as non-conventional source fuel tax credits. The non-conventional source fuel tax credit expired on December 31, 2007. The loss of the benefits to us from these tax credits could negatively impact our results of operations and reduce our cash available for distributions.

In 2007, we derived a material amount of our net income under long-term synfuel-related agreements with SSO, PCIN and Mt. Storm (see discussions under “Warrior Complex,” “Gibson Complex” and “Mettiki (WV)” in Item 1. Business). These agreements terminated on December 31, 2007 in connection with the expiration on that date of the non-conventional synfuel tax credit. In 2007, the incremental net income benefit to us from these synfuel-related agreements was approximately $28.5 million. The elimination of synfuel tax credits and the loss of related benefits to us could negatively impact our results of operations and reduce our cash available for distributions.

Competition within the coal industry may adversely affect our ability to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.

We compete with other large coal producers and hundreds of small coal producers in various regions of the United States for domestic coal sales. The industry has undergone significant consolidation over the last decade. This consolidation has led to several competitors having significantly larger financial and operating resources than us. In addition, we compete to some extent with western surface coal mining operations that have a much lower per ton cost of production and produce low-sulfur coal. Over the last 20 years, growth in production from western coal mines has substantially exceeded growth in production from the east. Declining prices from an oversupply of coal in the market could reduce our revenues and our cash available for distribution.

Any change in consumption patterns by utilities away from the use of coal could affect our ability to sell the coal we produce.

Some power plants are fueled by natural gas because of the relatively cheaper construction costs of such plants compared to coal-fired plants and because natural gas is a cleaner burning fuel. The domestic electric utility industry accounts for approximately 90% of domestic coal consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as hydroelectric power, and environmental and other governmental regulations. A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could negatively impact our results of operations and reduce our cash available for distribution.

From time to time conditions in the coal industry may make it more difficult for us to extend existing or enter into new long-term coal supply agreements. This could affect the stability and profitability of our operations.

A substantial decrease in the amount of coal sold by us pursuant to long-term contracts would reduce the certainty of the price and amounts of coal sold and subject our revenue stream to increased volatility. If that were to happen, changes in spot market coal prices would have a greater impact on our results, and any decreases in the spot market price for coal could adversely affect our profitability and cash flow. In 2007, we sold approximately 90.2% of our sales tonnage under contracts having a term greater than one year. We refer to these contracts as long-term contracts. Long-term sales contracts have historically provided a relatively secure market for the amount of production committed under the terms of the contracts. From time to time industry conditions may make it more difficult for us to enter into long-term contracts with our electric utility customers, and if supply exceeds demand in the coal industry, electric utilities may become less willing to lock in price or quantity commitments for an extended period of time. Accordingly, we may not be able to continue to obtain long-term sales contracts with reliable customers as existing contracts expire.

Some of our long-term coal supply agreements contain provisions allowing for the renegotiation of prices and, in some instances, the termination of the contract or the suspension of purchases by customers.

Some of our long-term contracts contain provisions that allow for the purchase price to be renegotiated at periodic intervals. These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to the contract to agree on a new price. Any adjustment or renegotiation leading to a significantly lower contract price could adversely affect our operating profit margins. Accordingly, long-term contracts may provide only limited protection during adverse market conditions. In some circumstances, failure of the parties to agree on a price under a reopener provision can also lead to early termination of a contract.

Several of our long-term contracts also contain provisions that allow the customer to suspend or terminate performance under the contract upon the occurrence or continuation of certain specified events. These events are called “force majeure” events. Some of these events that are specific to the coal industry include:

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our inability to deliver the quantities or qualities of coal specified;

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changes in the CAA rendering use of our coal inconsistent with the customer’s pollution control strategies; and

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the occurrence of events beyond the reasonable control of the affected party, including labor disputes, mechanical malfunctions and changes in government regulations.

In the event of early termination of any of our long-term contracts, if we are unable to enter into new contracts on similar terms our business, financial condition and results of operations could be adversely affected.

Extensive environmental laws and regulations affect coal consumers, and have corresponding effects on the demand for our coal as a fuel source.

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from coal-fired electric power plants, which are the ultimate consumers of our coal. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. A substantial portion of our coal has a high-sulfur content, which may result in increased sulfur dioxide emissions when combusted. Accordingly, these laws and regulations may affect demand and prices for our low- and high-sulfur coal. There is also continuing pressure on state and federal regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants. As a result of these current and proposed laws, regulations and regulatory initiatives, electricity generators may elect to switch to other fuels that generate less of these emissions, possibly further reducing demand for our coal. Please read “Item 1. Business – Regulation and Laws—Air Emissions” and “—Carbon Dioxide Emissions.”

We depend on a few customers for a significant portion of our revenues, and the loss of one or more significant customers could affect our ability to maintain the sales volume and price of the coal we produce.

During 2007, we derived approximately 37.9% of our total revenues from three customers, which individually accounted for 10.0% or more of our 2007 total revenues. If we were to lose any of these customers without finding replacement customers willing to purchase an equivalent amount of coal on similar terms, or if these customers were to decrease the amounts of coal purchased or the terms, including pricing terms, on which they buy coal from us, it could have a material adverse effect on our business, financial condition and results of operations.

Litigation resulting from disputes with our customers may result in substantial costs, liabilities and loss of revenues.

From time to time we have disputes with our customers over the provisions of long-term coal supply contracts relating to, among other things, coal pricing, quality, quantity and the existence of specified conditions beyond our control that suspend performance obligations under the particular contract. Disputes may occur in the future and we may not be able to resolve those disputes in a satisfactory manner.

Our profitability may decline due to unanticipated mine operating conditions and other events that are not within our control and that may not be fully covered under our insurance policies.

Our mining operations are influenced by changing conditions or events that can affect production levels and costs at particular mines for varying lengths of time and, as a result, can diminish our profitability.

These conditions and events include, among others:

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fires;

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mining and processing equipment failures and unexpected maintenance problems;

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prices for fuel, steel, explosives and other supplies;

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fines and penalties incurred as a result of alleged violations of environmental and safety laws and regulations;

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variations in thickness of the layer, or seam, of coal;

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amounts of overburden, partings, rock and other natural materials;

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weather conditions, such as heavy rains and flooding;

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accidental mine water discharges and other geological conditions;

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employee injuries or fatalities;

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labor-related interruptions;

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inability to acquire mining rights or permits; and

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fluctuations in transportation costs and the availability or reliability of transportation.

These conditions have had, and can be expected in the future to have, a significant impact on our operating results. Prolonged disruption of production at any of our mines would result in a decrease in our revenues and profitability, which could materially adversely impact our quarterly or annual results.

commercial property program, representing 35% of the primary $30.0 million layer and 2.5% of the second layer of $20.0 million in excess of the $30.0 million primary layer. We do not participate in the third layer of $25.0 million in excess of $50.0 million. The 14.7% participation rate for this year’s renewal is consistent with our prior year participation. 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 60-day waiting period for business interruption and an additional $5.0 million aggregate deductible. 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.

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

Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least one year of experience and proficiency in multiple mining tasks. In recent years, a shortage of trained coal miners has caused us to operate certain mining units without full experienced staff, which decreases our productivity and increases our costs. This shortage of trained coal miners is the result of a significant percentage of experienced coal miners reaching retirement age, combined with the difficulty of retaining existing workers in and attracting new workers to the coal industry. Thus, this shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our profitability.

Although none of our employees are members of unions, our work force may not remain union-free in the future.

None of our employees is represented under collective bargaining agreements. However, all of our work force may not remain union-free in the future. If some or all of our currently union-free operations were to become unionized, it could adversely affect our productivity and increase the risk of work stoppages at our mining complexes. In addition, even if we remain union-free, our operations may still be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our operations.

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

Mining companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. The permitting rules are complex and can change over time. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. The public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required by us to conduct our operations may not be issued, maintained or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations. Limitations on our ability to conduct our mining operations due to the inability to obtain or renew necessary permits or similar approvals could reduce our production, cash flow and profitability. Please read “Item 1. Business – Regulations and Laws – Mining Permits and Approvals.”

Lawsuits filed in the federal Southern District of Western Virginia and in the federal Eastern District of Kentucky have sought to enjoin the issuance of permits pursuant to Nationwide Permit 21, which is a general permit issued by the Corps of Engineers to streamline the process for obtaining permits under Section 404 of the CWA. In the event current or future litigation contesting the use of Nationwide Permit 21 is successful, we may be required to apply for individual discharge permits pursuant to Section 404 of the CWA in areas that would have otherwise utilized Nationwide Permit 21. In addition, lawsuits filed in the federal Southern District of West Virginia and in the federal Western District of Kentucky have challenged the Corps of Engineers’ issuance of certain individual Section 404 permits and led to a decision on March 23, 2007, by the U.S. District Court for the Southern District of West Virginia rescinding the permits in question based on a finding that the Corps of Engineers issued the permits in violation of the CWA and National Environmental Policy Act. This decision is currently on appeal to the U.S. Court of Appeals for the Fourth Circuit. Although our mining operations are not implicated in any of these particular cases, it is possible that this ruling may have long-term effects on the Corps of Engineers’ ability to issue CWA permits and could thereby adversely affect our results of operation and financial position. Such a change could result in delays in obtaining required mining permits to conduct operations, which could in turn result in reduced production, cash flow and profitability. Please read “Item 1. Business – Regulations and Laws – Water Discharge.”

Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenues by causing us to reduce our production or by impairing our ability to supply coal to our customers.

Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources. Conversely, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, difficulty in coordinating the many eastern coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make coal shipments originating in the eastern United States inherently more expensive on a per-mile basis than coal shipments originating in the western United States. Historically, high coal transportation rates from the western coal producing areas into certain eastern markets limited the use of western coal in those markets. Lower or higher rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created major competitive challenges, as well as opportunities, for eastern coal producers. In the event of lower transportation costs, the increased competition could have a material adverse effect on our business, financial condition and results of operations.

Some of our mines depend on a single transportation carrier or a single mode of transportation. Disruption of any of these transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events could temporarily impair our ability to supply coal to our customers. Our transportation providers may face difficulties in the future that may impair our ability to supply coal to our customers, resulting in decreased revenues. If there are disruptions of the transportation services provided by our primary rail or barge carriers that transport our coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

In recent years, the states of Kentucky and West Virginia have increased enforcement of weight limits on coal trucks on their public roads. It is possible that all states in which our coal is transported by truck may modify their laws to limit truck weight limits. Such legislation and enforcement efforts could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect revenues.

Mine expansions and acquisitions involve a number of risks, any of which could cause us not to realize the anticipated benefits.

Since our formation and the acquisition of our predecessor in August 1999, we have expanded our operations by adding and developing mines and coal reserves in existing, adjacent and neighboring properties. We continually seek to expand our operations and coal reserves. If we are unable to successfully integrate the companies, businesses or properties we acquire through such expansion, our profitability may decline and we could experience a material adverse effect on our business, financial condition, or results of operations.

Expansion and acquisition transactions involve various inherent risks, including:

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uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental or mine safety liabilities) of, expansion and acquisition opportunities;

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the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition;

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problems that could arise from the integration of the new operations; and

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unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or acquisition opportunity.

Any one or more of these factors could cause us not to realize the benefits anticipated to result from an expansion or acquisition. Any expansion or acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. In addition, future expansions or acquisitions could result in us assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous expansions and/or acquisitions.

We may not be able to successfully grow through future acquisitions.

Historically, a portion of our growth and operating results have been from acquisitions. Our future growth could be limited if we are unable to continue to make acquisitions, or if we are unable to successfully integrate the companies, businesses or properties we acquire. We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown. Moreover, any acquisition could be dilutive to earnings and distributions to unitholders and any additional debt incurred to finance an acquisition could affect our ability to make distributions to unitholders. Our ability to make acquisitions in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

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

Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by our customers. Because our reserves decline as we mine coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our profitability and financial condition. Exhaustion of reserves at particular mines also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

Our business depends, in part, upon our ability to find, develop or acquire additional coal reserves that we can recover economically. Our existing reserves will decline as they are depleted. Our planned development projects and acquisition activities may not increase our reserves significantly and we may not have continued success expanding existing and developing additional mines. We believe that there are substantial reserves on certain adjacent or neighboring properties that are unleased and otherwise available. However, we may not be able to negotiate leases with the landowners on acceptable terms. An inability to expand our operations into adjacent or neighboring reserves under this strategy could have a material adverse effect on our business, financial condition or results of operations.

The estimates of our coal reserves may prove inaccurate, and you should not place undue reliance on these estimates.

The estimates of our coal reserves may vary substantially from actual amounts of coal we are able to economically recover. The reserve data set forth in “Item 2. Properties” represent our engineering estimates. All of the reserves presented in this Annual Report on Form 10-K constitute proven and probable reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may vary considerably from actual results. These factors and assumptions relate to:

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geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our experiences in areas where we currently mine;

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the percentage of coal in the ground ultimately recoverable;

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historical production from the area compared with production from other producing areas;

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the assumed effects of regulation by governmental agencies; and

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assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes and development and reclamation costs.

For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. As a result, you should not place undue reliance on the coal reserve data included herein.

Mining in certain areas in which we operate is more difficult and involves more regulatory constraints than mining in other areas of the United States, which could affect the mining operations and cost structures of these areas.

The geological characteristics of some of our coal reserves, such as depth of overburden and coal seam thickness, make them difficult and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. In addition, permitting, licensing and other environmental and regulatory requirements associated with certain of our mining operations are more costly and time-consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to use coal produced by, our mines.

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

Our coal mining operations continue to be affected by commodity prices. We use significant amounts of steel, petroleum products and other raw materials in various pieces of mining equipment, supplies and materials, including the roof bolts required by the room and pillar method of mining. Steel prices have risen significantly in recent years, and historically, the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel have fluctuated. In 2007, we continued to experience increases in the cost of materials and supplies, particularly consumables such as steel, copper and power. There may be acts of nature or terrorist attacks or threats that could also increase the future costs of raw materials. If the price of steel, petroleum products or other raw materials increase, our operational expenses will increase and could have a significant negative impact on our profitability.

Our indebtedness may limit our ability to borrow additional funds, make distributions to unitholders or capitalize on business opportunities.

We have long-term indebtedness, consisting of our outstanding 8.31% senior unsecured notes and our revolving credit facility. At December 31, 2007, our total indebtedness outstanding was $154.0 million. Our leverage may:

•

adversely affect our ability to finance future operations and capital needs;

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limit our ability to pursue acquisitions and other business opportunities;

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make our results of operations more susceptible to adverse economic or operating conditions; and

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make it more difficult to self-insure for our workers’ compensation obligations.

In addition, we have unused borrowing capacity under our revolving credit facility. Future borrowings, under our credit facilities or otherwise, could result in a significant increase in our leverage.

Our payments of principal and interest on any indebtedness will reduce the cash available for distribution on our units. We will be prohibited from making cash distributions:

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during an event of default under any of our indebtedness; or

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if either before or after such distribution, it fails to meet a coverage test based on the ratio of our consolidated debt to our consolidated cash flow.

Various limitations in our debt agreements may reduce our ability to incur additional indebtedness, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

Federal and state laws require bonds to secure our obligations related to statutory reclamation requirements and workers’ compensation and black lung benefits. Our inability to acquire or failure to maintain surety bonds that are required by state and federal law would have a material adverse effect on us.

Federal and state laws require us to place and maintain bonds to secure our obligations to repair and return property to its approximate original state after it has been mined (often referred to as “reclaim” or “reclamation”), to pay federal and state workers’ compensation and pneumoconiosis, or black lung, benefits and to satisfy other miscellaneous obligations. These bonds provide assurance that we will perform our statutorily required obligations and are referred to

as “surety” bonds. These bonds are typically renewable on a yearly basis. The failure to maintain or the inability to acquire sufficient surety bonds, as required by state and federal laws, could subject us to fines and penalties and result in the loss of our mining permits. Such failure could result from a variety of factors, including:

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lack of availability, higher expense or unreasonable terms of new surety bonds;

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the ability of current and future surety bond issuers to increase required collateral, or limitations on availability of collateral for surety bond issuers due to the terms of our credit agreements; and

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the exercise by third-party surety bond holders of their rights to refuse to renew the surety.

We have outstanding surety bonds with third-parties for reclamation expenses, federal and state workers’ compensation obligations and other miscellaneous obligations. We may have difficulty maintaining our surety bonds for mine reclamation as well as workers’ compensation and black lung benefits. Our inability to acquire or failure to maintain these bonds would have a material adverse effect on us.

Our mining operations are subject to extensive and costly laws and regulations, and such current and future laws and regulations could increase current operating costs or limit our ability to produce coal.

We are subject to numerous and comprehensive federal, state and local laws and regulations affecting the coal mining industry, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge or release of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Certain of these laws and regulations may impose joint and several strict liability without regard to fault or legality of the original conduct. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial liabilities, and the issuance of injunctions limiting or prohibiting the performance of operations. Complying with these laws and regulations may be costly and time consuming and may delay commencement or continuation of exploration or production operations. The possibility exists that new laws or regulations (or judicial interpretations or more stringent enforcement of existing laws and regulations) may be adopted or that judicial interpretations or more stringent enforcement of existing laws and regulations may occur, in the future that could materially affect our mining operations, cash flow, and profitability, either through direct impacts such as new requirements impacting our existing mining operations, or indirect impacts such as new laws and regulations that discourage or limit our customers’ use of coal.

As a result of recent mining accidents that caused fatalities in West Virginia and Kentucky, Congress and several state legislatures (including those in West Virginia, Illinois and Kentucky) have passed new laws addressing mine safety practices and imposing stringent new mine safety and accident reporting requirements and increased civil and criminal penalties for violations of mine safety laws. Implementing and complying with these new laws and regulations has increased and will continue to increase our operational expense and to have an adverse effect on our results of operation and financial position. For more information, please read “Item 1. Business – Regulation and Laws – Mine Health and Safety Laws.”

Some of our operating subsidiaries lease a portion of the surface properties upon which their mining facilities are located.

Our operating subsidiaries do not, in all instances, own all of the surface properties upon which their mining facilities have been constructed. Certain of the operating companies have constructed and now operate all or some portion of their facilities on properties owned by unrelated third-parties with whom the applicable company has entered into a long-term lease. We have no reason to believe that there exists any risk of loss of these leasehold rights given the terms and provisions of the subject leases and the nature and identity of the third-party lessors; however, in the unlikely event of any loss of these leasehold rights, operations could be disrupted or otherwise adversely impacted as a result of increased costs associated with retaining the necessary land use.

Tax Risks to Our Common Unitholders

If we were to become subject to entity-level taxation for federal or state tax purposes, our cash available for distribution to you would be substantially reduced.

The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (“IRS”) on this matter.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations, that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because taxes would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flow and after-tax return to you, likely causing a substantial reduction in the value of our units.

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. At the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us or as an entity, the cash available for distribution to you would be reduced.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions that we take, even positions taken with the advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

You will be required to pay federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that result from your share of our taxable income.

Tax gain or loss on the disposition of our units could be different than expected.

If you sell your units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis therein, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation and depletion recapture. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax-exempt entities and non-U.S. persons owning our units face unique tax issues that may result in adverse tax consequences to them.

Investment in units by tax-exempt entities, such as individual retirement accounts (known as “IRAs”) and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

We treat each purchaser of our units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.

Because we cannot match transferors and transferees of units, we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of units and could have a negative impact on the value of our units or result in audit adjustments to your tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests within a twelve-month period will result in the termination of our partnership for federal income tax purposes.

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 twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A termination does not affect our classification as a partnership for federal income tax purposes.

You will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where you do not live as a result of investing in our units.

In addition to federal income taxes, you will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states in the future. It is your responsibility to file all federal, state and local tax returns.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

Coal Reserves

We must obtain permits from applicable state regulatory authorities before beginning to mine particular reserves. For more information on this permitting process, and matters that could hinder or delay the process, please read “Item 1. Business — Regulation and Laws — Mining Permits and Approvals.”

Our reported coal reserves are those we believe can be economically and legally extracted or produced at the time of the filing of this Annual Report on Form 10-K. In determining whether our reserves meet this economical and legal standard, we take into account, among other things, our potential ability or inability to obtain a mining permit, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices.

At December 31, 2007, we had approximately 712.8 million tons of coal reserves. All of the estimates of reserves which are presented in this Annual Report on Form 10-K are of proven and probable reserves (as defined below) and adhere to the standards described in USGS Circular 831 and USGS Bulletin 1450-B. For information on the locations of our mines, please read “Mining Operations” under “Item 1. Business.”

The following table sets forth reserve information, at December 31, 2007, about each of our mining operations:


Operations	Mine Type	Heat Content (Btus per pound)	Proven and Probable Reserves								Reserve Assignment
			Pounds S0₂ per MMbtu								Reserve Assignment
			<1.2		1.2-2.5		>2.5		Total		Assigned		Unassigned
			(tons in millions)
*Illinois Basin Operations*
Dotiki (KY)	Underground	12,300	—		—		125.6		125.6		125.6		—
Warrior (KY)	Underground	12,350	—		—		57.4		57.4		24.4		33.0
Hopkins (KY)	Underground	12,300	—		—		47.1		47.1		32.0		15.1
	/Surface	11,500	—		—		7.8		7.8		7.8		—
River View (KY)	Underground	11,700	—		—		117.1		117.1		117.1		—
Pattiki (IL)	Underground	11,800	—		—		54.5		54.5		54.5		—
Gibson (North) (IN)	Underground	11,600	—		25.3		4.0		29.3		29.3		—
Gibson (South) (IN)	Underground	11,600	—		18.5		64.1		82.6		—		82.6

Region Total			—		43.8		477.6		521.4		390.7		130.7

*Central Appalachian Operations*
Pontiki (KY)	Underground	12,800	—		14.9		—		14.9		14.9		—
MC Mining (KY)	Underground	12,800	18.0		—		1.8		19.8		19.8		—

Region Total			18.0		14.9		1.8		34.7		34.7		—

*Northern Appalachian Operations*
Mettiki (MD)	Underground	13,000	—		2.8		7.4		10.2		10.2		—
Mountain View (WV)	Underground	13,000	—		5.1		14.2		19.3		19.3		—
Tunnel Ridge (PA/WV)	Underground	12,600	—		—		70.5		70.5		70.5		—
Penn Ridge (PA)	Underground	12,500	—		—		56.7		56.7		56.7		—

Region Total			—		7.9		148.8		156.7		156.7		—

Total			18.0		66.6		628.2		712.8		582.1		130.7

% of Total			2.5	%	9.4	%	88.1	%	100.0	%	81.7	%	18.3	%

Our reserve estimates are prepared from geological data assembled and analyzed by our staff of geologists and engineers. This data is obtained through our extensive, ongoing exploration drilling and in-mine channel sampling programs. Our drill spacing criteria adhere to standards as defined by the U.S. Geological Survey. The maximum acceptable distance from seam data points varies with the geologic nature of the coal seam being studied, but generally the standard for (a) proven reserves is that points of observation are no greater than ¹/2 mile apart and are projected to extend as a ¹/4 mile wide belt around each point of measurement and (b) probable reserves is that points of observation are between ¹/2 and 1 ¹/2 miles apart and are projected to extend as a ¹/2 mile wide belt that lies ¹/4 mile from the points of measurement.

Reserve estimates will change from time to time to reflect mining activities, additional analysis, new engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods, and other factors. Weir International Mining Consultants performed an overview audit of our reserves and calculation methods in October 2005.

Reserves represent that part of a mineral deposit that can be economically and legally extracted or produced, and reflect estimated losses involved in producing a saleable product. All of our reserves are steam coal, except for the coal being produced at the small contour strip operation at our Mettiki (MD) complex, which has metallurgical qualities. The 18.0 million tons of reserves listed as <1.2 pounds of SO₂ per MMbtu are compliance coal under Phase II of CAA.

Assigned reserves are those reserves that have been designated for mining by a specific operation.

Unassigned reserves are those reserves that have not yet been designated for mining by a specific operation.

Btu values are reported on an as-shipped, fully washed basis. Shipments that are either fully or partially raw will have a lower Btu value.

We control certain leases for coal deposits that are near, but not contiguous to, our primary reserve bases. The tons controlled by these leases are classified as non-reserve coal deposits and are not included in our reported reserves. These non-reserve coal deposits are as follows: Dotiki – 15.6 million tons, Pattiki – 4.9 million tons, Hopkins County Coal – 1.8 million tons, River View – 24.7 million tons, Gibson (North) – 1.4 million tons, Gibson (South) – 11.1 million tons, Warrior – 3.0 million tons, Tunnel Ridge – 7.0 million tons, Penn Ridge – 3.4 million tons and Pontiki – 0.2 million tons.

We lease most of our reserves and generally have the right to maintain leases in force until the exhaustion of the mineable and merchantable coal within the leased premises or for so long as we are conducting mining operations in a larger defined coal reserve area. These leases provide for royalties to be paid to the lessor at a fixed amount per ton or as a percentage of the sales price. Many leases require payment of minimum royalties, payable either at the time of the execution of the lease or in periodic installments, even if no mining activities have begun. These minimum royalties are normally credited against the production royalties owed to a lessor once coal production has commenced.

Acquisition of Illinois Basin Coal Reserves. In June 2007, our subsidiary, Alliance Resource Properties, LLC (“Alliance Resource Properties”), acquired from a subsidiary of Consol Energy, Inc. the rights to approximately 78.4 million tons of high-sulfur coal reserves encompassing approximately 13,500 acres located in Webster and Hopkins Counties, Kentucky. As a result of the purchase, we gained control of approximately 78.4 million tons of coal in the Kentucky No. 9, No. 11 and No. 13 coal seams, along with related surface properties. Additionally, as a result of this transaction, we reclassified 8.4 million tons of high-sulfur non-reserve coal deposits as reserves, increasing our reserves at the time by approximately 14%.

Mining Operations

The following table sets forth production and other data about each of our mining operations:


Operations	Location	Tons Produced			Transportation	Equipment
Operations	Location	2007	2006	2005	Transportation	Equipment
		(tons in millions)
*Illinois Basin Operations*
Dotiki	Kentucky	4.6	4.7	4.7	CSX, PAL, truck	CM
Warrior	Kentucky	4.6	4.5	4.1	CSX, PAL, truck	CM
Hopkins	Kentucky	2.6	1.6	0.9	CSX, PAL, truck	DL, CM
Pattiki	Illinois	2.9	2.5	2.6	EVW, barge	CM
Gibson (North)	Indiana	3.2	3.6	3.4	CSX, NS, truck, barge	CM

Region Total		17.9	16.9	15.7

*Central Appalachian Operations*
Pontiki	Kentucky	1.4	1.6	1.7	NS, truck, barge	CM
MC Mining	Kentucky	1.8	1.9	1.6	CSX, truck, barge	CM

Region Total		3.2	3.5	3.3

*Northern Appalachian Operations*
Mettiki	Maryland	0.4	2.8	3.3	Truck, CSX	LW, CM, CS
Mountain View	West Virginia	2.8	0.5	—	Truck, CSX	LW, CM

Region Total		3.2	3.3	3.3

TOTAL		24.3	23.7	22.3


CSX		- CSX Railroad
NS		- Norfolk Southern Railroad
PAL		- Paducah & Louisville Railroad
CM		- Continuous Miner
CS		- Contour Strip
DL		- Dragline with Stripping Shovel, Front End Loaders and Dozers
LW		- Longwall
EVW		- Evansville Western Railroad

ITEM 3.

LEGAL PROCEEDINGS

We are subject to various types of litigation in the ordinary course of our business. We are not engaged in any litigation that we believe is material to our operations, including without limitation, any litigation relating to our long-term coal supply contracts (e.g., relating to, among other things, coal quality, quantity, pricing and the existence of force majeure conditions) or under the various environmental protection statutes to which we are subject. However, we cannot assure you that disputes or litigation will not arise or that we will be able to resolve any such future disputes or litigation in a satisfactory manner. The information under “General Litigation” and “Other” in “Item 8. Financial Statements and Supplementary Data. – Note 19. Commitments and Contingencies” is incorporated herein by this reference.

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. On August 30, 2007, the court dismissed the plaintiffs’ complaint. On September 17, 2007, plaintiffs filed a notice of appeal of that dismissal to the United States Court of Appeals for the Fifth Circuit and their appeal is pending. 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.

On June 15, 2006, Mettiki (MD) was issued a Notice of Violation by the Maryland Department of Environment (“MDE”) for alleged exceedances of permitted sulfur dioxide emissions. These alleged exceedances occurred between May 23, 2006 and June 12, 2006, at the Mettiki (MD) Thermal Coal Dryer associated with the longwall mining operation, located in Garrett County, Maryland. This self-reported violation was promptly corrected and Mettiki (MD) demonstrated to the satisfaction of MDE that it is in compliance with MDE regulations. On July 18, 2007, a consent decree was filed by the MDE which required Mettiki (MD) to pay a penalty assessment of $150,000. The assessment has been paid.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS

None.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The common units representing limited partners’ interests are listed on the NASDAQ Global Select Market under the symbol “ARLP”. The common units began trading on August 20, 1999. On February 25, 2008, the closing market price for the common units was $39.37 per unit. As of February 25, 2008, there were 36,613,458 common units outstanding. There were approximately 23,399 record holders and beneficial owners (held in street name) of common units at December 31, 2007.

The following table sets forth the range of high and low sales prices per common unit and the amount of cash distributions declared and paid with respect to the units, for the two most recent fiscal years:


	High		Low		Distributions Per Unit
1st Quarter 2006	$	40.70	$	33.68	$0.460 (paid May 15, 2006)
2nd Quarter 2006	$	43.79	$	34.00	$0.500 (paid August 14, 2006)
3rd Quarter 2006	$	39.00	$	33.84	$0.500 (paid November 14, 2006)
4th Quarter 2006	$	37.45	$	33.59	$0.540 (paid February 14, 2007)
1st Quarter 2007	$	38.00	$	33.40	$0.540 (paid May 15, 2007)
2nd Quarter 2007	$	45.50	$	37.50	$0.560 (paid August 14, 2007)
3rd Quarter 2007	$	44.40	$	30.12	$0.560 (paid November 14, 2007)
4th Quarter 2007	$	41.08	$	33.00	$0.585 (paid February 14, 2008)

We distribute to our partners, on a quarterly basis, all of our available cash. “Available cash”, as defined in our partnership agreement, generally means, with respect to any quarter, all cash on hand at the end of each quarter, plus working capital borrowings after the end of the quarter, less cash reserves in the amount necessary or appropriate in the reasonable discretion of our managing general partner to (a) provide for the proper conduct of our business, (b) comply with applicable law or any debt instrument or other agreement of ours or any of our affiliates, and (c) provide funds for distributions to unitholders and the general partners for any one or more of the next four quarters. If quarterly distributions of available cash exceed the minimum quarterly distribution (“MQD”) and certain target distribution levels as established in our partnership agreement, our managing general partner will receive distributions based on specified increasing percentages of the available cash that exceed the MQD and the target distribution levels. Our partnership agreement defines the MQD as $0.25 for each full fiscal quarter.

Under the quarterly incentive distribution provisions of the partnership agreement, 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.

Equity Compensation Plans

The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” contained herein.

ITEM 6.

SELECTED FINANCIAL DATA

Our historical financial data below were derived from our audited consolidated financial statements as of and for the years ended December 31, 2007, 2006, 2005, 2004 and 2003.

(in millions, except per unit and per ton data)


	Year Ended December 31,
	2007			2006			2005			2004			2003
Statements of Income
Sales and operating revenues:
Coal sales	$	960.3		$	895.8		$	768.9		$	599.4		$	501.6
Transportation revenues		37.7			39.9			39.1			29.8			19.5
Other sales and operating revenues		35.3			31.9			30.7			24.1			21.6

Total revenues		1,033.3			967.6			838.7			653.3			542.7

Expenses:
Operating expenses		685.1			627.8			521.5			436.4			368.8
Transportation expenses		37.7			39.9			39.1			29.8			19.5
Outside purchases		22.0			19.2			15.1			9.9			8.5
General and administrative		34.4			30.9			33.5			45.4			28.3
Depreciation, depletion and amortization		85.3			66.5			55.6			53.7			52.5
Net gain from insurance settlement (1)		(11.5	)		—			—			(15.2	)		—

Total operating expenses		853.0			784.3			664.8			560.0			477.6

Income from operations		180.3			183.3			173.9			93.3			65.1
Interest expense (net of interest capitalized)		(11.7	)		(12.2	)		(14.6	)		(15.8	)		(16.3	)
Interest income		1.7			3.0			2.8			0.8			0.3
Other income		1.4			0.9			0.6			1.0			1.4

Income before income taxes, cumulative effect of accounting change and minority interest		171.7			175.0			162.7			79.3			50.5
Income tax expense		1.6			2.4			2.7			2.7			2.6

Income before cumulative effect of accounting change and minority interest		170.1			172.6			160.0			76.6			47.9
Cumulative effect of accounting change (2)		—			0.1			—			—			—
Minority interest		0.3			0.2			—			—			—

Net income	$	170.4		$	172.9		$	160.0		$	76.6		$	47.9

General Partners’ interest in net income	$	31.3		$	24.6		$	12.4		$	3.3		$	0.3

Limited Partners’ interest in net income	$	139.1		$	148.3		$	147.6		$	73.3		$	47.6

Basic net income per limited partner unit	$	3.07		$	3.06		$	2.89		$	1.76		$	1.30

Diluted net income per limited partner unit	$	3.05		$	3.03		$	2.84		$	1.71		$	1.26

Weighted average number of units outstanding-basic		36,548,150			36,425,350			36,288,527			35,881,896			35,161,468

Weighted average number of units outstanding-diluted		36,800,212			36,810,383			36,977,061			36,874,336			36,325,678

Balance Sheet Data:
Working capital	$	25.9		$	37.4		$	76.1		$	54.2		$	16.4
Total assets		701.7			635.0			532.7			412.8			336.5
Long-term obligations (3)		137.1			127.5			144.0			162.0			180.0
Total liabilities		384.5			386.5			376.9			357.6			323.9
Partners’ capital		317.2			248.5			155.8			55.2			12.6
Other Operating Data:
Tons sold		24.7			24.4			22.8			20.8			19.5
Tons produced		24.3			23.7			22.3			20.4			19.2
Revenues per ton sold (4)	$	40.31		$	38.02		$	35.07		$	29.98		$	26.83
Cost per ton sold (5)	$	30.02		$	27.78		$	25.00		$	23.64		$	20.80
Other Financial Data:
Net cash provided by operating activities	$	244.0		$	250.9		$	193.6		$	145.1		$	110.3
Net cash used in investing activities		(178.7	)		(137.7	)		(110.2	)		(77.6	)		(77.8	)
Net cash used in financing activities		(101.0	)		(108.5	)		(82.6	)		(46.4	)		(31.3	)
EBITDA (6)		267.0			250.8			230.1			147.9			119.0
Maintenance capital expenditures (7)		76.3			67.8			56.7			31.6			30.0

(1)

Represents the net gain from the final settlement with our insurance underwriters for claims relating to the MC Mining Mine Fire in 2007 (Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – MC Mining Mine Fire”) and the Dotiki Mine Fire Incident in 2004.

(2)	Represents the cumulative effect of the accounting change attributable to the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 123R, Share-Based Payments, on January 1, 2006.

(3)	Long-term obligations include long-term portions of debt and capital lease obligations.

(4)	Revenues per ton sold are based on the total of coal sales and other sales and operating revenues divided by tons sold.

(5)	Cost per ton sold is based on the total of operating expenses, outside purchases and general and administrative expenses divided by tons sold.

(6)

EBITDA is defined as income before income taxes, cumulative effect of accounting change, minority interest, interest income, interest expense and depreciation, depletion and amortization. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

•

our operating performance and return on investment as compared to those of other companies in the coal energy sector, without regard to financing or capital structures; and

•

the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDA should not be considered as an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles. EBITDA is not intended to represent cash flow and does not represent the measure of cash available for distribution. Our method of computing EBITDA may not be the same method used to compute similar measures reported by other companies, or EBITDA may be computed differently by us in different contexts (i.e. public reporting versus computation under financing agreements).

The following table presents a reconciliation of (a) GAAP “Cash Flows Provided by Operating Activities” to a non-GAAP EBITDA and (b) non-GAAP EBITDA to GAAP net income (in thousands):


	Year Ended December 31,
	2007			2006			2005			2004			2003
Cash flows provided by operating activities	$	244,012		$	250,923		$	193,618		$	145,055		$	110,312
Non-cash compensation expense		(3,925	)		(4,112	)		(8,193	)		(20,320	)		(7,687	)
Asset retirement obligations		(2,419	)		(2,101	)		(1,918	)		(1,622	)		(1,341	)
Coal inventory adjustment to market		(21	)		(319	)		(573	)		(488	)		(687	)
Net gain (loss) on sale of property, plant and equipment		3,189			1,188			(179	)		332			885
Gain from insurance recoveries for property damage		2,357			—			—			—			—
Gain from insurance settlement proceeds received in a prior period		5,088			—			—			—			—
Loss on retirement of damaged vertical belt equipment		—			—			(1,298	)		—			—
Other		(811	)		(1,119	)		(580	)		(587	)		(532	)
Net effect of working capital changes		7,898			(5,317	)		34,770			7,915			(553	)
Interest expense, net		9,952			9,175			11,816			14,963			15,981
Income taxes		1,669			2,443			2,682			2,641			2,577

EBITDA		266,989			250,761			230,145			147,889			118,955
Depreciation, depletion and amortization		(85,310	)		(66,489	)		(55,637	)		(53,664	)		(52,495	)
Interest expense, net		(9,952	)		(9,175	)		(11,816	)		(14,963	)		(15,981	)
Income taxes		(1,669	)		(2,443	)		(2,682	)		(2,641	)		(2,577	)
Cumulative effect of accounting change		—			112			—			—			—
Minority interest		332			161			—			—			—

Net income	$	170,390		$	172,927		$	160,010		$	76,621		$	47,902

(7)

Our maintenance capital expenditures, as defined under the terms of our partnership agreement, are those capital expenditures required to maintain, over the long-term, the operating capacity of our capital assets.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

The following discussion of our financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, please see “Item 8. Financial Statements and Supplementary Data. – Note 1. Organization and Presentation and Note 2. Summary of Significant Accounting Policies.”

Executive Overview

We are a diversified producer and marketer of steam coal primarily to major U.S. utilities and industrial users. In 2007, our total production was 24.3 million tons and our total sales were 24.7 million tons. The coal we produced in 2007 was approximately 25.9% low-sulfur coal, 13.2% medium-sulfur coal and 60.9% high-sulfur coal. We classify low-sulfur coal as coal with a sulfur content of less than 1%, medium-sulfur coal as coal with a sulfur content between 1% and 2%, and high-sulfur coal as coal with a sulfur content of greater than 2%.

We currently operate eight mining complexes, and at December 31, 2007, had approximately 712.8 million tons of proven and probable coal reserves in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia. We believe we control adequate reserves to implement our currently contemplated mining plans. We also operated a coal loading terminal on the Ohio River at Mt. Vernon, Indiana. Please see “Item 1. Business – Mining Operations” for further discussion of our mines. Three of our mining complexes supplied coal feedstock and provided services to third-party coal synfuel facilities located at or near these complexes. Operations at these third-party synfuel facilities ended in December 2007 as the federal non-conventional source fuel tax credit expired. A more detailed discussion of our synfuel-related arrangements is described below under “– Liquidity and Capital Resources.”

As discussed in more detail in “Item 1A. Risk Factors,” our results of operations in the short-term could be negatively impacted by prices for fuel, steel, explosives and other supplies, unforeseen geologic conditions or mining and processing equipment failures and unexpected maintenance problems, and by the availability or reliability of transportation for coal shipments. On a long-term basis, our results of operations could be impacted by our ability to obtain and renew permits necessary for our operations, secure or acquire coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts, or the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs or limit our customers’ ability to utilize coal as fuel for electricity generation.

Our principal expenses related to the production of coal are labor and benefits, equipment, materials and supplies, maintenance, royalties and excise taxes. Unlike many of our competitors in the eastern U.S., we employ a totally union-free workforce. Many of the benefits of the union-free workforce are not necessarily reflected in direct costs, but we believe are related to higher productivity. In addition, while we do not pay our customers’ transportation costs, they may be substantial and are often the determining factor in a coal consumer’s contracting decision. Our mining operations are located near many of the major eastern utility generating plants and on major coal hauling railroads in the eastern U.S.

Our primary business strategy is to create sustainable, capital-efficient growth in distributable cash flow to maximize our distributions to our unit holders by:

•

expanding our operations by adding and developing mines and coal reserves in existing, adjacent or neighboring properties;

•

extending the lives of our current mining operations through acquisition and development of coal reserves using our existing infrastructure;

•

continuing to make productivity improvements to remain a low-cost producer in each region in which we operate;

•

strengthening our position with existing and future customers by offering a broad range of coal qualities, transportation alternatives and customized services; and

•

developing strategic relationships to take advantage of opportunities created within the coal industry.

We have four reportable segments: the Illinois Basin, Central Appalachia, Northern Appalachia and Other and Corporate. The first three segments correspond to the three major coal producing regions in the eastern United States. Coal quality, coal seam height, mining and transportation methods and regulatory issues are similar within each of these three segments.

•

Illinois Basin segment is comprised of Webster County Coal’s Dotiki mine, Gibson County Coal’s Gibson North mine and Gibson South property, Hopkins County Coal’s Elk Creek mine, White County Coal’s Pattiki mine and Warrior Coal’s Cardinal mine, the River View property and Alliance Resource Properties, LLC. In 2007, mine development began at the River View property. We are in the process of permitting the Gibson South property for future mine development.

•

Central Appalachian segment is comprised of Pontiki Coal’s Pond Creek and Van Lear mines, and MC Mining’s Excel No. 3 mine.

•

Northern Appalachian segment is comprised of Mettiki Coal’s D-Mine and Mettiki Coal (WV)’s Mountain View mine, two small third-party mining operations, and the Tunnel Ridge and Penn Ridge coal properties. In late 2006, we completed the transition of longwall operations from the D-Mine to the Mountain View mine. We are in the process of permitting the Tunnel Ridge and Penn Ridge properties for future mine development. For more information on the permitting process, and matters that could hinder or delay the process, please read “Item 1. Business – Regulation and Laws – Mining Permits and Approvals.”

•

Other and Corporate segment includes marketing and administrative expenses, the Mt. Vernon dock activities, coal brokerage activity, MAC and MDG.

How We Evaluate Our Performance

Our management uses a variety of financial and operational measurements to analyze our segment performance. Primary measurements include the following: (1) salable tons produced per unit shift; (2) coal sales price per ton; (3) Segment Adjusted EBITDA Expense per ton; and (4) EBITDA.

Salable Tons Produced Per Unit Shift. We review salable tons produced per unit shift as part of our operational analysis to measure the productivity of our operating segments which is significantly influenced by mining conditions and the efficiency of our preparation plants.

Coal Sales Price per Ton. We define coal sales price per ton as total coal sales divided by tons sold. We review coal sales price per ton for our marketing efforts, market demand and trend analysis.

Segment Adjusted EBITDA Expense per Ton. We define Segment Adjusted EBITDA Expense per ton as the sum of operating expenses, outside purchases and other income divided by total tons sold. We review segment adjusted EBITDA expense per ton for cost trends.

EBITDA. We define EBITDA as net income before net interest expense, income taxes, depreciation, depletion and amortization, cumulative effect of accounting change and minority interest. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis,

•

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

•

our operating performance and return on investment as compared to those of other companies in the coal energy sector, without regard to financing or capital structures; and

•

the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Sources of Our Revenue and 2008 Expectations

In 2007, approximately 86.9% of our sales tonnage was consumed by electric utilities (or coal synfuel facilities whose ultimate customers were electric utilities) with the balance consumed by cogeneration plants and industrial users. In 2007, approximately 90.2% of our sales tonnage, including approximately 94.0% of our medium- and high-sulfur coal sales tonnage, was sold under long-term contracts. The balance of our sales was made in the spot market. Our long-term contracts contribute to our stability and profitability by providing greater predictability of sales volumes and sales prices. In 2007, approximately 93.4% of our medium- and high-sulfur coal was sold to utility plants with installed pollution control devices, also known as scrubbers, to remove sulfur dioxide.

We are currently anticipating coal production for 2008 in a range of 26.2 to 26.7 million tons, essentially all of which is committed to contract pricing. We have also secured sales commitments for approximately 18.9 million tons, 15.5 million tons and 12.1 million tons in 2009, 2010 and 2011, respectively, of which approximately 8.3 million tons, 9.7 million tons and 9.7 million tons currently remain open to market pricing in 2009, 2010 and 2011, respectively.

During 2008, we are expecting total average coal sales prices per ton to be comparable to 2007 levels, excluding synfuel-related benefits. Based on current estimates for coal production and coal sales prices, we are anticipating 2008 revenues in a range of $1.0 to $1.03 billion, excluding transportation revenues.

We are currently estimating 2008 operating expenses per ton will be comparable to 2007 levels. The lower costs for producing the incremental tons discussed above are expected to offset anticipated cost increases attributable to labor and benefits, maintenance, regulatory compliance, and materials and supplies.

Expiration of Federal Non-Conventional Source Fuel Tax Credit

In recent years, we have earned a material amount of income by supplying three third-party coal synfuel facilities with coal feedstock and related services. For 2007, the incremental income benefit from the combination of the various coal synfuel-related agreements was approximately $28.5 million, assuming that coal pricing would not have increased without the availability of synfuel. The federal synfuel tax benefit expired on December 31, 2007. While we have alternative purchasers for our coal that would have been previously sold to the synfuel facilities, we may not be able to recover the $28.5 million in incremental net income benefit from our synfuel related operations. A more detailed discussion of our synfuel-related arrangements is described below under “– Liquidity and Capital Resources.”

Analysis of Historical Results of Operations

2007 Compared with 2006

In 2007, we reported net income of $170.4 million, a decrease of 1.5% compared to 2006 net income of $172.9 million. The 2007 results were negatively impacted by higher materials and supplies and maintenance expenses per ton, higher incentive compensation expenses and increased depreciation and amortization, partially offset by higher average coal sales prices per ton and a $12.3 million benefit representing the net gain and reduced operating expenses associated with the final settlement of claims related to the MC Mining Mine Fire described below.


	December 31,				December 31,
	2007		2006		2007		2006
	(in thousands)				(per ton sold)
Tons sold		24,725		24,351		N/A		N/A
Tons produced		24,269		23,738		N/A		N/A
Coal sales	$	960,354	$	895,823	$	38.84	$	36.79
Operating expenses and outside purchases	$	707,054	$	646,969	$	28.60	$	26.57

Coal sales. Coal sales increased 7.2% to $960.3 million for 2007 from $895.8 million for 2006. The increase of $64.5 million reflected increased sales volumes (contributing $13.8 million of the increase) and higher average coal sales prices (contributing $50.7 million of the increase). Tons sold increased 1.5% to 24.7 million tons for 2007 from 24.4 million tons in 2006. Tons produced increased 2.2% to 24.3 million tons for 2007 from 23.7 million tons in 2006. Average coal sales prices increased 5.6%, or $2.05 per ton sold in 2007 as compared to 2006, primarily attributable to higher pricing on long-term sales contracts particularly in the Northern Appalachian segment described below.

Operating expenses. Operating expenses increased 9.1% to $685.1 million in 2007 from $627.8 million in 2006. The increase of $57.3 million primarily resulted from an increase in operating expenses associated with additional 407,000 produced tons sold as well as the following specific factors:

•

Labor and benefit expenses per ton increased 1.3% to $9.69 per ton in 2007 from $9.57 per ton in 2006. The increase of $0.12 per ton resulted from pay rate increases, higher health care costs, productivity reductions due to recently enacted federal and state regulations partly offset by lower workers’ compensation expense due to changes in estimates associated with year end valuations and improved productivity at certain mines that transitioned out of the development stage in 2006;

•

Material and supplies and maintenance expenses per ton increased 8.4% and 8.2%, respectively, to $8.75 and $3.05 per ton respectively in 2007 from $8.07 and $2.82 per ton respectively in 2006. The respective increases of $0.68 and $0.23 per ton resulted from increased costs for certain products and services (particularly roof support costs and transportation costs) used in the mining process, as well as, higher regulatory compliance costs. Those regulations also contributed to increased mine administrative expenses;

•

Production taxes and royalties (which were incurred as a percentage of coal sales or based on coal volumes) increased $10.2 million and included the impact of West Virginia severance tax on coal sold from Mountain View mine as compared to Maryland. We completed the transition of longwall operations to the Mountain View mine in West Virginia from the depleted Mettiki D-Mine in Maryland in the fourth quarter of 2006;

•

Reduced expenses of $9.0 million in 2007 as compared to 2006 were associated with the purchase and sale of more coal during 2006 under a settlement agreement we entered into with ICG in November 2005. Consistent with the guidance in the Financial Accounting Standards Board’s (“FASB”) Emerging Issues Task Force (“EITF”) Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, Pontiki Coal’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 Coal’s sales price to ICG is reported as an operating expense. We fully satisfied our coal sales agreement with ICG in April 2007. For more information about the ICG settlement agreement, please read “Other” under “Item 8. Financial Statements and Supplementary Data – Note 19. Commitments and Contingencies”;

•

The 2006 operating expenses were reduced by $13.9 million reflecting capitalized costs net of revenues received for incidental coal production during mine development. In 2007, there was no incidental coal production associated with mine development. See “Item 8, Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies - Mine Development Costs”;

•

Reduced tax credit benefits of $6.6 million in 2007 were due to reduced coal production in Maryland. (See comments above concerning production taxes and royalties and depletion of the Mettiki D-Mine in Maryland); and

•

2007 benefited from net gains of $3.2 million realized from sale of surplus equipment.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of rental and service fees from third-party coal synfuel production facilities, Mt. Vernon transloading revenues, and outside services and administrative services revenue from affiliates. Other sales and operating revenues increased 10.7% to $35.3 million in 2007 from $31.9 million in 2006. The increase of $3.4 million was primarily attributable to an increase in rental and service fees associated with increased volumes at third-party coal synfuel facilities, increased revenues from hoist and control system services, mine safety services and products, and revenues from outside services, partially offset by lower transloading revenues due to decreased volumes. Synfuel operations ended on December 31, 2007. A more detailed discussion of our synfuel-related arrangements is discussed below under “– Liquidity and Capital Resources.”

Outside purchases. Outside purchases increased $2.8 million to $22.0 million in 2007 from $19.2 million in 2006. The increase was primarily attributable to an increase in outside purchases in our Central Appalachia region to supply new market opportunities partially offset by lower purchases in the Illinois Basin and Northern Appalachian regions.

General and administrative. General and administrative expenses for 2007 increased to $34.5 million compared to $30.9 million for 2006. The increase of $3.6 million was primarily attributable to increased headcount and related salary and benefit costs and higher incentive compensation expense.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased to $85.3 million in 2007 compared to $66.5 million in 2006. The increase of $18.8 million was primarily attributable to additional depreciation expense associated with an increase in capital expenditures, particularly at our Elk Creek, Mountain View and Van Lear mines, and other infrastructure investments in recent years that have increased our production capacity.

Interest expense. Interest expense, net of capitalized interest, decreased to $11.7 million in 2007 from $12.2 million in 2006. The decrease of $0.5 million was principally attributable to reduced interest expense resulting from the August 2007 and 2006 scheduled principal payments of $18.0 million, respectively, on our senior notes, partially offset by increased interest expense under our revolving credit facility.

Interest income. Interest income decreased to $1.7 million for 2007 from $3.0 million in 2006. The decrease of $1.3 million resulted from decreased interest income earned on marketable securities, which were substantially liquidated to fund increased capital expenditures during 2006.

Transportation revenues and expenses. Transportation revenues and expenses decreased 5.5% to $37.7 million in 2007 from $39.9 million for 2006. The decrease of $2.2 million was primarily attributable to lower average per ton transportation charges in 2007 as compared to 2006, primarily driven by the location of our customers for which we arranged transportation. The decrease was partially offset by higher transported coal volumes in 2007. The cost of transportation services are a pass-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 decreased 1.9% to $171.7 million for 2007 compared to $175.1 million for 2006. The decrease of $3.4 million reflects the impact of the changes in revenues and expenses described above.

Income tax expense. Income tax expense decreased to $1.7 million for 2007 from $2.4 million for 2006, primarily due to operating losses associated with Matrix Design Group, LLC, a business Alliance Services acquired in September 2006, partially offset by increased tax expense due to increased volumes at the third-party coal synfuel facilities.

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

Minority interest. In March 2006, White County Coal and Alexander J. House (“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 and to manufacture and sell rock dust. We consolidate MAC’s financial results in accordance with FASB Interpretation (“FIN”) No. 46R, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. Based on the guidance in FIN No. 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 $0.3 million for 2007 and $0.2 million for 2006, and is recorded as minority interest on our consolidated income statement.

Segment Information. Please read “Item 8. Financial Statements and Supplementary Data—Note 21 Segment Information” for more information concerning our reportable segments. Our 2007 Segment Adjusted EBITDA increased $19.8 million, or 7.0%, to $301.4 million from 2006 Segment Adjusted EBITDA of $281.6 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are as follows (in thousands):


	Year Ended December 31,						Increase (Decrease)
	2007			2006			Increase (Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	208,658		$	206,209		$	2,449		1.2	%
Central Appalachia		58,937			40,050			18,887		47.2	%
Northern Appalachia		35,478			29,911			5,567		18.6	%
Other and Corporate		(1,605	)		5,475			(7,080	)	(3	)
Elimination		—			—			—		—

Total Segment Adjusted EBITDA (1)	$	301,468		$	281,645		$	19,823		7.0	%

Tons sold
Illinois Basin		17,970			17,354			616		3.5	%
Central Appalachia		3,455			3,552			(97	)	(2.7	)%
Northern Appalachia		3,300			3,423			(123	)	(3.6	)%
Other and Corporate		—			22			(22	)	(3	)
Elimination		—			—			—		—

Total tons sold		24,725			24,351			374		1.5	%

Coal sales
Illinois Basin	$	612,850		$	587,087		$	25,763		4.4	%
Central Appalachia		193,104			182,922			10,182		5.6	%
Northern Appalachia		147,315			106,628			40,687		38.2	%
Other and Corporate		7,085			19,186			(12,101	)	(63.1	)%
Elimination		—			—			—		—

Total coal sales	$	960,354		$	895,823		$	64,531		7.2	%

Other sales and operating revenues
Illinois Basin	$	25,371		$	24,168		$	1,203		5.0	%
Central Appalachia		99			304			(205	)	(67.4	)%
Northern Appalachia		4,201			2,010			2,191		(3	)
Other and Corporate		10,423			7,639			2,784		36.44	%
Elimination		(4,802	)		(2,266	)		(2,536	)	(3	)

Total other sales and operating revenues	$	35,292		$	31,855		$	3,437		10.8	%

Segment Adjusted EBITDA Expense
Illinois Basin	$	429,563		$	405,045		$	24,518		6.1	%
Central Appalachia		145,759			143,176			2,583		1.8	%
Northern Appalachia		116,037			78,727			37,310		47.4	%
Other and Corporate		19,112			21,351			(2,239	)	(10.5	)%
Elimination		(4,802	)		(2,266	)		(2,536	)	(3	)

Total Segment Adjusted EBITDA Expense (2)	$	705,669		$	646,033		$	59,636		9.2	%

(1)	Segment Adjusted EBITDA is defined as income before income taxes, cumulative effect of accounting change, minority interest, interest income, interest expense, depreciation, depletion and amortization, and general and administrative expense.

The following is a reconciliation of Segment Adjusted EBITDA to net income (in thousands):


	Year Ended December 31,
	2007			2006
Segment Adjusted EBITDA	$	301,468		$	281,645

General and administrative		(34,479	)		(30,884	)
Depreciation, depletion and amortization		(85,310	)		(66,489	)
Interest expense, net		(9,952	)		(9,175	)
Income taxes		(1,669	)		(2,443	)
Cumulative effect of accounting change		—			112
Minority interest		332			161

Net income	$	170,390		$	172,927

(2)

Segment Adjusted EBITDA Expense includes operating expenses, outside purchases and other income. Transportation expenses are excluded as these expenses are passed through to our customers, consequently we do not realize any margin on transportation revenues. Segment Adjusted EBITDA Expense is used as a supplemental financial measure by our management to assess the operating performance of our segments. In our evaluation of EBITDA, which is discussed above under “— How We Evaluate Our Performance,” Segment Adjusted EBITDA Expense is a key component of EBITDA in addition to coal sales and other sales and operating revenues. The exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA Expense allows management to focus solely on the evaluation of segment operating performance as it primarily relates to our operating expenses. Outside purchases are included in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside purchases.

The following is a reconciliation of Segment Adjusted EBITDA Expense to Operating expense (in thousands):


	Year Ended December 31,
	2007			2006
Segment Adjusted EBITDA Expense	$	705,669		$	646,033

Outside purchases		(21,969	)		(19,213	)
Other income		1,385			936

Operating expense	$	685,085		$	627,756

(3)	Percentage increase or decrease was greater than or equal to 100%.

Illinois Basin – Segment Adjusted EBITDA for 2007, as defined in reference (1) to the table above, increased 1.2%, to $208.7 million from 2006 Segment Adjusted EBITDA of $206.2 million. The increase of $2.5 million was primarily attributable to increased coal sales which rose by $25.8 million, or 4.4%, to $612.9 million during 2007 as compared to $587.1 million in 2006. Coal sales benefited from increased tons sold of 0.6 million tons (contributing $20.9 million of the increase in coal sales) reflecting expanded production capacity at the Hopkins mine and improved productivity at the Pattiki and Warrior mines. Additionally, increased coal sales in 2007 reflected higher average coal sales price per ton which increased $0.27 per ton to $34.10 per ton (contributing $4.9 million of the increase in coal sales). The price increase was primarily the result of higher pricing on long-term sales contracts. Other sales and operating revenues increased $1.2 million, primarily due to an increase in rent and service fees associated with increased synfuel volumes at our third-party coal synfuel facilities. Please read “Executive Overview” above for a discussion regarding the status of third-party coal synfuel facilities. Total Segment Adjusted EBITDA Expense, as defined in reference (2) to the above table, for 2007 increased 6.1% to $429.6 million from $405.0 million in 2006. On a per ton sold basis, 2007 Segment Adjusted EBITDA Expense rose to $23.90 per ton or 2.4% over the 2006 Segment Adjusted EBITDA Expense of $23.34 per ton. In addition to the increased tons sold, increased Segment Adjusted EBITDA Expense in 2007 compared to 2006 reflects the impact of cost increases described above under consolidated operating expenses.

Central Appalachia – Segment Adjusted EBITDA for 2007, as defined in reference (1) to the table above, increased $18.9 million, or 47.2%, to $58.9 million as compared to 2006 Segment Adjusted EBITDA of $40.0 million. The increase was primarily the result of the final settlement of the MC Mining Mine Fire, which resulted in a net gain from insurance settlement of approximately $11.5 million and a reduction in operating expenses of approximately $0.8 million (please read “– MC Mining Mine Fire” below) and higher average coal sales price per ton discussed above of $55.89 in 2007, an increase of $4.39 per ton or 8.5% over the 2006 average coal sales price per ton of $51.50 (contributing a $15.2 million increase in coal sales). Coal sales increased $10.2 million or 5.6% to $193.1 million for 2007 as compared to $182.9 million for 2006, reflecting higher average coal sales price per ton partially offset by a decrease of 2.7% in tons sold, or 97,000 tons (contributing a $5.0 million decrease in coal sales). Segment Adjusted EBITDA Expense, as defined in reference (2) to the above table, for 2007 increased 1.8% to $145.8 million. The increase in Segment

Adjusted EBITDA Expense per ton of $1.89 or 4.7% to $42.19 in 2007, as compared to 2006, was primarily a result of higher operating expenses associated with recently enacted federal and state regulations and increased purchased coal volumes, among other cost increases described above under consolidated operating expenses.

Northern Appalachia – Segment Adjusted EBITDA for 2007, as defined in reference (1) to the table above, increased $5.6 million, or 18.6%, to $35.5 million as compared to 2006 Segment Adjusted EBITDA of $29.9 million. The net increase in Segment Adjusted EBITDA reflects both an increase in the average sales price of $13.49 per ton to $44.64 per ton during 2007 as compared to $31.15 per ton during 2006 due to new coal sales contracts, as well as increased other sales and operating revenues of $2.2 million, partially offset by an increase in Segment Adjusted EBITDA Expense, as defined in reference (2) to the above table, of $12.16 per ton to $35.16 per ton during 2007 as compared to $23.00 per ton during 2006. These variances reflect the impact of higher coal sales contract prices, as well as, higher operating costs resulting from the transition of the Mettiki D-Mine longwall operation in Maryland to the new Mountain View longwall operation in West Virginia. Other impacts on Segment Adjusted EBITDA for 2007 as compared to 2006 include a 3.6% decrease in sold tonnage volume, increased other sales and operating revenues of $2.2 million, and the cost increases described above under consolidated operating expenses.

Other and Corporate – The decrease in Segment Adjusted EBITDA Expense, as defined in reference (2) to the above table, primarily reflects lower operating expenses in 2007 attributable to lower brokerage coal purchases associated with the ICG agreement referred to above under consolidated operating expenses, partially offset by increased expenses associated with higher outside services revenue, which includes MAC and Matrix Design.

Elimination – The increase is primarily comprised of the elimination of sales and operating expenses between MAC and MDG and our operating mines.

2006 Compared with 2005


	December 31,				December 31,
	2006		2005		2006		2005
	(in thousands)				(per ton sold)
Tons sold		24,351		22,849		N/A		N/A
Tons produced		23,738		22,290		N/A		N/A
Coal sales	$	895,823	$	768,958	$	36.79	$	33.65
Operating expenses and outside purchases	$	646,969	$	536,601	$	26.57	$	23.48

Coal sales. Coal sales increased 16.5% to $895.8 million for 2006 from $769.0 million for 2005. The increase of $126.8 million reflected increased sales volumes (contributing $50.5 million of the increase) and higher average coal sales prices (contributing $76.3 million of the increase). Tons sold increased 6.6%, or 1.5 million tons, to 24.4 million tons for 2006 from 22.8 million tons in 2005, as a result of increased tons produced. Tons produced increased 6.5% to 23.7 million tons for 2006 from 22.3 million tons in 2005, which primarily reflects the impact of production capacity expansion capital investments and increased third-party purchased coal volume. Average coal sales prices increased 9.3%, or $3.14 per ton sold in 2006 as compared to 2005, primarily attributable to higher pricing on long-term sales contracts, higher coal quality shipments and the 2006 coal spot market demand.

Operating expenses. Operating expenses increased 20.4% to $627.8 million in 2006 from $521.5 million in 2005. The increase of $106.3 million primarily resulted from increased operating expenses associated with additional coal sales of 1.5 million tons, including the following specific factors:

•

Labor and benefit expenses per ton increased 12.9% to $9.57 per ton in 2006 from $8.48 per ton in 2005. The increase of $1.09 per ton resulted from pay and bonus rate increases, adverse workers’ compensation claims developments, escalating health care costs, higher long-term disability costs and productivity reductions in 2006 during transition periods related to various mine development projects;

•

Materials and supplies and maintenance expenses per ton increased 17.0% and 8.5%, respectively, to $8.07 and $2.82 per ton in 2006 from $6.90 and $2.60 per ton, respectively, in 2005. The respective increases of $1.17 and $0.22 per ton resulted from industry-wide cost increases for the products and services used in the mining process (particularly consumables such as copper, steel and power) and higher costs per ton during transition periods in 2006 related to various mine development projects;

•

Contract mining costs increased $3.9 million, primarily reflecting increased production volume at two small third-party mining operations at Mettiki (MD);

•

Production taxes and royalties (which were incurred as a percentage of coal sales or based on coal volumes) increased $6.8 million;

•

Property insurance costs increased $3.8 million;

•

Increased expenses of $13.4 million in 2006 were associated with the purchase of tons under the settlement agreement we entered into with ICG in November 2005. Consistent with the guidance in the FASB’s EITF Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty Pontiki Coal’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 Coal’s sales price to ICG is reported as an operating expense in Other and Corporate Segment Adjusted EBITDA. Segment Adjusted EBITDA is defined as income before income taxes, cumulative effect of accounting change, minority interest, interest income, interest expense, depreciation, depletion and amortization, and general and administrative expense. For more information about the ICG settlement agreement, please read “Other” under “Item 8. Financial Statements and Supplementary Data – Note 19 Commitments and Contingencies”; and

•

The 2006 operating expenses were decreased by $9.0 million more than the decrease in 2005, 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 “Item 8, Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies – Mine Development Costs.”

Other sales and operating revenues. Other sales and operating revenues are principally comprised of rental and service fees from coal synfuel production facilities, Mt. Vernon transloading revenues and administrative service revenue from affiliates. Other sales and operating revenues increased 3.8% to $31.9 million in 2006 from $30.7 million in 2005. The increase of $1.2 million was primarily attributable to $0.9 million of administrative service revenues associated with the administrative service agreement with affiliates executed in 2006 and $0.7 million of additional transloading revenues attributable to increased transloading volumes at Mt. Vernon. These increases were partially offset by decreases in service fees from coal synfuel production facilities.

Outside purchases. Outside purchases increased $4.1 million to $19.2 million in 2006 from $15.1 million in 2005. The increase was principally attributable to coal supply agreements with third-party suppliers in the Central and Northern Appalachian operations ($3.3 million and $3.5 million, respectively), primarily to supplement production capacity during periods of mine transition and development, offset by reduced coal purchases in the Illinois Basin operations ($3.7 million).

General and administrative. General and administrative expenses for 2006 decreased to $30.9 million compared to $33.5 million for 2005. The decrease of $2.6 million was primarily related to lower unit-based incentive compensation expense associated with the Long-Term Incentive Plan (“LTIP”) in addition to the Short-Term Incentive Plan (“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.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased to $66.5 million in 2006 compared to $55.6 million in 2005. The increase of $10.9 million was primarily attributable to additional depreciation expense associated with increased capital expenditures incurred in certain production capacity expansion projects and infrastructure investments, including development of the Elk Creek mine at Hopkins County Coal, Pontiki’s development of the Van Lear seam and the transition to the Albridge Branch area of the Pond Creek seam.

Interest expense. Interest expense, net of capitalized interest, decreased to $12.2 million in 2006 from $14.6 million in 2005. The decrease of $2.4 million was principally attributable to the increased capitalization of interest expense in 2006 compared to 2005 related to capital projects and mine development costs, along with 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 2006 or 2005.

Interest income. Interest income of $3.0 million for 2006 was comparable with $2.8 million for 2005.

Transportation revenues and expenses. Transportation revenues and expenses increased 2.1% to $39.9 million in 2006 from $39.1 million for 2005. The increase of $0.8 million was primarily attributable to increased shipments to customers that reimburse us for transportation costs rather than arranging and paying for transportation directly with transportation providers. Transportation services are a pass-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 7.6% to $175.1 million for 2006 compared to $162.7 million for 2005. The increase was primarily attributable to increased sales volumes as a result of expanded production capacity, higher average coal sales prices and reduced general and administrative expenses, partially offset by higher operating expenses.

Income tax expense. Income tax expense decreased to $2.4 million for 2006 from $2.7 million for 2005, resulting from decreased volumes at the third-party coal synfuel facilities.

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, 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 and to manufacture and sell rock dust. White County Coal initially invested $1.0 million in exchange for a 50% equity interest in MAC. We consolidate MAC’s financial results in accordance with FIN No. 46R. Based on the guidance in FIN No. 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 $0.2 million for 2006 and is recorded as minority interest on our consolidated income statement.

Segment Information. Please read “Item 8. Financial Statements and Supplementary Data—Note 21. Segment Information” for more information concerning our reportable segments. Our 2006 Segment Adjusted EBITDA increased $18.0 million, or 6.8%, to $281.6 million from 2005 Segment Adjusted EBITDA of $263.6 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are as follows (in thousands):


	Year Ended December 31,					Increase (Decrease)
	2006			2005		Increase (Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	206,209		$	183,075	$	23,134		12.6	%
Central Appalachia		40,050			41,583		(1,533	)	(3.7	)%
Northern Appalachia		29,911			36,047		(6,136	)	(17.0	)%
Other and Corporate		5,475			2,924		2,551		87.2	%
Elimination		—			—		—		—

Total Segment Adjusted EBITDA (1)	$	281,645		$	263,629	$	18,016		6.8	%

Tons sold
Illinois Basin		17,354			16,264		1,090		6.7	%
Central Appalachia		3,552			3,249		303		9.3	%
Northern Appalachia		3,423			3,330		93		2.8	%
Other and Corporate		22			6		16		(3	)
Elimination		—			—		—		—

Total tons sold		24,351			22,849		1,502		6.6	%

Coal sales
Illinois Basin	$	587,087		$	504,916	$	82,171		16.3	%
Central Appalachia		182,922			153,615		29,307		19.1	%
Northern Appalachia		106,628			106,997		(369	)	(0.3	)%
Other and Corporate		19,186			3,430		15,756		(3	)
Elimination		—			—		—		—

Total coal sales	$	895,823		$	768,958	$	126,865		16.5	%

Other sales and operating revenues
Illinois Basin	$	24,168		$	24,493	$	(325	)	(1.3	)%
Central Appalachia		304			282		22		7.8	%
Northern Appalachia		2,010			2,163		(153	)	(7.1	)%
Other and Corporate		7,639			3,753		3,886		(3	)
Elimination		(2,266	)		—		(2,266	)	—

Total other sales and operating revenues	$	31,855		$	30,691	$	1,164		3.8	%

Segment Adjusted EBITDA Expense
Illinois Basin	$	405,045		$	346,335	$	58,710		17.0	%
Central Appalachia		143,176			112,313		30,863		27.5	%
Northern Appalachia		78,727			73,112		5,615		7.7	%
Other and Corporate		21,351			4,260		17,091		(3	)
Elimination		(2,266	)		—		(2,266	)	—

Total Segment Adjusted EBITDA Expense (2)	$	646,033		$	536,020	$	110,013		20.5	%

(1)	Segment Adjusted EBITDA is defined as income before income taxes, cumulative effect of accounting change, minority interest, interest income, interest expense, depreciation, depletion and amortization, and general and administrative expense.

The following is a reconciliation of Segment Adjusted EBITDA to net income (in thousands):


	Year Ended December 31,
	2006			2005
Segment Adjusted EBITDA	$	281,645		$	263,629

General and administrative		(30,884	)		(33,484	)
Depreciation, depletion and amortization		(66,489	)		(55,637	)
Interest expense, net		(9,175	)		(11,816	)
Income taxes		(2,443	)		(2,682	)
Cumulative effect of accounting change		112			—
Minority interest		161			—

Net income	$	172,927		$	160,010

(2)

The following is a reconciliation of Segment Adjusted EBITDA Expense to Operating expense (in thousands):


	Year Ended December 31,
	2006			2005
Segment Adjusted EBITDA Expense	$	646,033		$	536,020

Outside purchases		(19,213	)		(15,113	)
Other income		936			581

Operating expense	$	627,756		$	521,488

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

Illinois Basin – Segment Adjusted EBITDA for 2006, as defined in reference (1) to the table above, increased 12.6%, to $206.2 million from 2005 Segment Adjusted EBITDA of $183.1 million. The increase of $23.1 million was primarily attributable to increased coal sales which rose by $82.2 million, or 16.3%, to $587.1 million during 2006 as compared to $504.9 million in 2005. Increased coal sales in 2006 reflected higher average coal sales price per ton which increased $2.78 per ton to $33.83 per ton (contributing $48.2 million of the increase in coal sales) and increased tons sold of 1.1 million tons (contributing $34.0 million of the increase in coal sales). The price increase was the combined result of improved market demand and higher quality coal shipments. Total Segment Adjusted EBITDA Expense in 2006 increased 17.0% to $405.0 million from $346.3 million in 2005. On a per ton sold basis, 2006 Segment Adjusted EBITDA Expense rose to $23.34 per ton or 9.6% over the 2005 Segment Adjusted EBITDA Expense of $21.30 per ton. The increase in Segment Adjusted EBITDA Expense in 2006 compared to 2005 reflected the impact of cost increases described above under consolidated operating expenses. Illinois Basin costs were negatively impacted primarily by increased labor costs as certain operations expanded capacity potential, higher costs of roof control resulting from increased raw material pricing, mining conditions, increased regulatory requirements, and higher equipment maintenance costs, among others. Additionally, Illinois Basin costs increased due to the continued ramp-up to full production capacity at the Elk Creek mine, which emerged from development in the second quarter of 2006, as well as certain periods of adverse mining conditions encountered at the Pattiki mine.

Central Appalachia – Segment Adjusted EBITDA for 2006, as defined in reference (1) to the table above, decreased $1.5 million, or 3.7%, to $40.1 million as compared to 2005 Segment Adjusted EBITDA of $41.6 million. The decrease was primarily attributable to higher operating expenses, partially offset by increased coal sales of $29.3 million, reflecting higher average coal sales price per ton of $51.49 in 2006, which increased $4.22 per ton (contributing $15.0 million of the increase in coal sales), and increased tons sold in 2006 of 303,000 tons (which contributed $14.3 million of the increase in coal sales). Segment Adjusted EBITDA Expense in 2006 increased 27.5% to $143.2 million from $112.3 million in 2005. On a per ton basis, 2006 Segment Adjusted EBITDA Expense rose by $5.74, or 16.6%, to $40.30 per ton reflecting the impact of the cost increases described above under consolidated operating expenses and outside purchases, as well as the net impact of insurance recovery benefits of $10.7 million reported in 2005 related to the MC

Mining Fire Incident. The Central Appalachian operations have been negatively impacted by increased operating expenses described above under consolidated operating expenses. Additionally, the increased costs of the Central Appalachian operations reflect the continuing ramp-up of production in Pontiki Coal’s Van Lear seam and the transition to the Albridge Branch area of the Pond Creek seam.

Northern Appalachia – Segment Adjusted EBITDA for 2006, as defined in reference (1) to the table above, decreased $6.1 million, or 17.0%, to $29.9 million as compared to 2005 Segment Adjusted EBITDA of $36.0 million. This decrease is the combined result of a 3.0%, or $0.98 per sold ton decrease in coal sales price per ton from $32.13 per sold ton in 2005 to $31.15 per sold ton in 2006, and a 4.8% or $1.05 per sold ton increase in Segment Adjusted EBITDA Expense from $21.95 per sold ton in 2005 to $23.00 per sold ton in 2006. The lower average sales price was primarily attributable to a decrease in spot market demand and price and fewer tons sold in higher priced export markets during 2006. Segment Adjusted EBITDA Expense for 2006 increased 7.7% to $78.7 million as compared to $73.1 million in 2005, primarily as a result of increased purchased coal volume, higher environmental costs, increased roof control costs resulting from pricing, an increased ratio of panel development mining as compared to longwall mining, increased coal transportation expense associated with the transition from the Maryland longwall operation to the Mountain View longwall operation, higher West Virginia severance taxes and the loss of certain Maryland state tax benefits.

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 settlement agreement referred to above under consolidated operating expenses.

Elimination – The increase is primarily comprised of the elimination of sales and operating expenses between MDG and our operating mines.

MC Mining Mine Fire

On June 18, 2007, we agreed to a full and final resolution of our insurance claims relating to a mine fire that occurred on or about December 25, 2004 at our MC Mining Excel No. 3 mine. This resolution included settlement of all expenses, losses and claims we incurred for the aggregate amount of $31.6 million, inclusive of $8.2 million of various deductibles and co-insurance, netting to $23.4 million of insurance proceeds paid to us. In 2006 and 2005, we received partial advance payments on the claims totaling $16.2 million, part of which we recognized as an offset to operating expenses ($0.4 million and $10.7 million in the three months ended March 31, 2006 and the year ended December 31, 2005, respectively), with the remaining $5.1 million of partial payments previously included in other current liabilities pending final claim resolution. In June 2007, as a result of this final resolution, we received additional cash payments of $7.2 million and recognized a net gain from insurance settlement of approximately $11.5 million, as well as a reduction in operating expenses of approximately $0.8 million.

Ongoing Acquisition Activities

Consistent with our business strategy, from time to time we engage in discussions with potential sellers regarding possible acquisitions of certain assets and/or companies by us.

Liquidity and Capital Resources

Liquidity

We generally satisfy our working capital requirements and fund our capital expenditures and debt service obligations from cash generated from operations and borrowings under our revolving credit facility. We believe that the cash generated from operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled debt payments and distribution payments. Our ability to satisfy our obligations and planned expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions generally and in the coal industry specifically, some of which are beyond our control.

In recent years, we have earned a material amount of income by supplying three coal synfuel facilities with coal feedstock. For 2007, the incremental net income benefit from the combination of the various coal synfuel-related agreements was approximately $28.5 million, assuming that coal pricing would not have increased without the

availability of synfuel. We have previously entered into agreements with the owners of these coal synfuel production facilities: (1) SSO, related to its coal synfuel facility located at our Warrior mining complex in Hopkins County, Kentucky; (2) PCIN, related to its coal synfuel facility located at our Gibson mining complex in Gibson County, Indiana; and (3) Mt. Storm Coal Supply, related to its coal synfuel facility located at VEPCO’s Mt. Storm Power Station, which is adjacent to our Mettiki complex in Garrett County, Maryland. SSO, PCIN, and Mt. Storm Coal Supply are collectively referred to below as the Coal Synfuel Owners.

We received 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 expired on December 31, 2007. Pursuant to our agreements with the Coal Synfuel Owners, we were not obligated to make retroactive adjustments or reimbursements if synfuel credits were disallowed.

Due to the increase in wellhead price of domestic crude oil, the operational status of our synfuel operations during 2007 and 2006 was sporadic. During the periodic suspension of operations at the coal synfuel production facilities located at Warrior, Gibson and Mettiki, we sold coal directly to the Coal Synfuel Owners’ customers under “back-up” coal supply agreements, which automatically provided for the sale of our coal in the event these customers did not purchase coal synfuel.

Crude oil and natural gas prices have increased significantly since 2003. These increases have not had a material direct impact on our financial results since our direct purchases of crude oil based fuel and natural gas does not represent a significant percentage of our operating expenses. However, higher crude oil and natural gas prices have also resulted in increases to the cost of goods, services and equipment provided to us and therefore indirectly impacted our financial results. We can provide no assurance that we will be able to pass the impact of these direct or indirect cost increases through to our customers.

Cash Flows

Cash provided by operating activities was $244.0 million in 2007, compared to $250.9 million in 2006. The decrease in cash provided by operating activities was attributable principally to a decrease in net income combined with an unfavorable change in operating assets and liabilities. The principal difference in the change in operating assets and liabilities in 2007 as compared to 2006 relates to an increased use of cash in 2007 compared to 2006 associated with accounts payable.

Net cash used in investing activities was $178.7 million in 2007, compared to $137.7 million in 2006. The increased use of cash in 2007 is primarily attributable to an increase in capital expenditures associated with the Illinois Basin reserve acquisition and advances related to the Gibson County Coal rail project. Additionally, there was a net decrease in proceeds from marketable securities, which were substantially liquidated to fund increased capital expenditures during 2006 and timing differences in accounts payable and accrued liabilities related to capital expenditures and advances made on the Gibson County Coal rail project, partially offset by a decrease in capital expenditures. The decrease in capital expenditures in 2007 (excluding the Illinois Basin reserve acquisition) was primarily attributable to the completion of the Elk Creek and Mountain View mines during 2006. During 2007 we also benefited from increased proceeds from the sale of surplus plant, property and equipment.

Net cash used in financing activities was $101.0 million for 2007 compared to $108.5 million for 2006. The reduced use of cash is primarily attributable to net borrowings under our revolving credit facility of $28.0 million in 2007 used to finance the Illinois Basin reserve acquisition, partially offset by increased distributions paid to partners in 2007.

We have various commitments primarily related to long-term debt, including capital leases, operating lease commitments related to buildings and equipment, obligations for estimated asset retirement obligations costs, workers’ compensation and pneumoconiosis, capital project commitments and pension funding. We expect to fund these commitments with cash generated from operations and borrowings under our revolving credit facility. The following table provides details regarding our contractual cash obligations as of December 31, 2007 (in thousands):


Contractual Obligations	Total		Less than 1 year		2-3 years		4-5 years		After 5 years
Long-term debt	$	154,000	$	18,000	$	36,000	$	64,000	$	36,000
Future interest obligations on senior notes		41,882		10,471		16,454		10,470		4,487
Operating leases		12,852		4,247		7,467		1,138		—
Capital leases⁽¹⁾		2,470		485		969		750		266
Reclamation obligations⁽²⁾		121,994		2,000		2,158		4,142		113,694
Purchase obligations for capital projects		13,664		13,664		—		—		—
Coal purchase commitments		6,700		6,700		—		—		—
Workers’ compensation and pneumoconiosis benefit⁽²⁾		210,260		11,908		16,820		13,642		167,890

	$	563,822	$	67,475	$	79,868	$	94,142	$	322,337

(1)	Includes amounts classified as interest and maintenance cost.

(2)	Future commitments for reclamation obligations, workers’ compensation and pneumoconiosis are shown at undiscounted amounts.

We expect to contribute $2.5 million to the defined benefit pension plan (“Pension Plan”) during 2008. We estimate our income tax cash requirements to be approximately $1.0 million in 2008.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds. Liabilities related to these arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

We use a combination of surety bonds and letters of credit to secure our financial obligations for reclamation, workers’ compensation and other obligations as follows as of December 31, 2007 (dollars in thousands):


	Reclamation Obligation		Workers’ Compensation Obligation		Other		Total
Surety bonds	$	58,449	$	3,471	$	2,998	$	64,918
Letters of credit		—		44,440		10,698		55,138

Capital Expenditures

Capital expenditures decreased to $119.6 million in 2007 compared to $188.6 million in 2006. See discussion of “Cash Flows” above concerning the decrease in capital expenditures.

We currently project that our average annual maintenance capital expenditures will be approximately $2.85 per ton. Our anticipated total capital expenditures for 2008 are estimated in a range of $145.0 to $165.0 million. We will continue to have significant capital requirements over the long-term, which may require us to incur debt or seek additional equity capital. The availability of additional capital will depend upon prevailing market conditions, the market price of our common units and several other factors over which we have limited control, as well as our financial condition and results of operations. Based on our recent operating results, current cash position, anticipated future cash flows, and sources of financing that we expect will be available to us, we do not expect that we will experience any significant liquidity constraints in the foreseeable future.

Insurance

During September 2007, we completed our annual property and casualty insurance renewal with various insurance coverages effective as of October 1, 2007. Available capacity for underwriting property insurance continues to be limited as a result of insurance carrier losses in the mining industry. 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 of $20.0 million in excess of the $30.0 million primary layer. We do not participate in the third layer of $25.0 million in excess of $50.0 million. The 14.7% participation rate for this year’s renewal is consistent with our prior year participation. 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 60-day waiting period for business interruption and an additional $5.0 million aggregate deductible. 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.

Debt Obligations

Notes Offering and Credit Facility

Our Intermediate Partnership has $126.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in seven remaining equal annual installments of $18.0 million with interest payable semi-annually (“Senior Notes”). On September 25, 2007, our Intermediate Partnership entered into a $150.0 million revolving credit facility (“ARLP Credit Facility”), which expires in 2012. The ARLP Credit Facility amended the previous $100.0 million credit facility that would have expired in 2011. Borrowings under the ARLP Credit Facility bear interest based on a floating base rate plus an applicable margin, which is based on a leverage ratio of our Intermediate Partnership, as computed from time to time. For London Interbank Offered Rate (“LIBOR”) borrowings, the applicable margin under the ARLP Credit Facility ranges from 0.625% to 1.150% over LIBOR. As of December 31, 2007, the applicable margin was 0.75% and the interest rate on the ARLP Credit Facility was 5.21%. Letters of credit can be issued under the ARLP Credit Facility not to exceed $100.0 million. Outstanding letters of credit reduce amounts available under the ARLP Credit Facility. At December 31, 2007, we had $28.0 million of borrowings and $24.6 million of letters of credit outstanding with $97.4 million available for borrowing under the ARLP Credit Facility. The deferred cost associated with the amended $100.0 million credit facility were accounted for as prescribed by EITF No. 98-14, Debtor’s Accounting for Changes in Line-of-Credit or Revolving-Debt Arrangements, which states that if the borrowing capacity of a new arrangement is greater than or equal to the borrowing capacity of an old arrangement, the unamortized deferred costs associated with the old arrangement should be associated with the new arrangement and amortized over the life of the new arrangement.

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 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 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 December 31, 2007.

We maintain 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 certain asset retirement obligations and our obligations for workers’ compensation benefits. At December 31, 2007, we had $30.6 million in letters of credit outstanding under these agreements. Our special general partner guarantees $5.0 million of these outstanding letters of credit.

On March 19, 2007, MAC entered into a secured line of credit (“LOC”) which was scheduled to expire on March 19, 2008. In September 2007, MAC entered into a $1.5 million Revolving Credit Agreement (“Revolver”) with ARLP. Concurrent with the execution of the Revolver, MAC repaid all amounts outstanding under the LOC. Due to the consolidation of MAC in accordance with FIN 46R, the intercompany transactions associated with the Revolver are eliminated.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. From our summary of significant accounting policies included in “Item 8. Financial Statements and Supplementary Data,” we have identified the following accounting policies that require us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingencies. On an on-going basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

Revenue Recognition

Revenues from coal sales are recognized when title passes to the customer as the coal is shipped. Some coal supply agreements provide for price adjustments based on variations in quality characteristics of the coal shipped. In certain cases, a customer’s analysis of the coal quality is binding and the results of the analysis are received on a delayed basis. In these cases, we estimate the amount of the quality adjustment and adjust the estimate to actual when the information is provided by the customer. Historically such adjustments have not been material. Non-coal sales revenues primarily consist of rental and service fees associated with agreements to host and operate third-party coal synfuel facilities and to assist with the coal synfuel marketing and other related services. These non-coal sales revenues are recognized as the services are performed. Transportation revenues are recognized in connection with us incurring the corresponding costs of transporting coal to customers through third-party carriers for which we are directly reimbursed through customer billings.

Long-Lived Assets

We review the carrying value of long-lived assets and certain identifiable intangibles whenever events or changes in circumstances indicate that the carrying amount may not be recoverable based upon estimated undiscounted future cash flows. The amount of impairment is measured by the difference between the carrying value and the fair value of the asset. We have not recorded an impairment loss for any of the periods presented.

Mine Development Costs

Mine development costs are capitalized until production, other than production incidental to the mine development process, commences and are amortized over the estimated life of the mine. Mine development costs represent costs incurred in establishing access to mineral reserves and include costs associated with sinking or driving shafts and underground drifts, permanent excavations, roads and tunnels. The end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase. Amortization of capitalized mine development is computed based on the estimated life of the mine and commences when production, other than production incidental to the mine development process, begins.

Asset Retirement Obligations

SMCRA and similar state statutes require that mined property be restored in accordance with specified standards and an approved reclamation plan. We record a liability for the estimated cost of future mine asset retirement and closing procedures on a present value basis when incurred and a corresponding amount is capitalized by increasing the carrying amount of the related long-lived asset. Those costs relate to permanently sealing portals at underground mines and to reclaiming the final pits and support acreage at surface mines. Examples of these types of costs, common to both types of mining, include, but are not limited to, removing or covering refuse piles and settling ponds, water treatment obligations, and dismantling preparation plants, other facilities and roadway infrastructure. We had accrued liabilities of $56.9 million and $50.9 million for these costs at December 31, 2007 and 2006, respectively. The liability for asset

retirement and closing procedures is sensitive to changes in cost estimates and estimated mine lives. For additional information on our asset retirement obligations, please read “Item 8. Financial Statements and Supplementary Data. – Note 15. Asset Retirement Obligations.”

Workers’ Compensation and Pneumoconiosis (“Black Lung”) Benefits

We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. We generally provide for these claims through self-insurance programs. Workers’ compensation laws also compensate survivors or workers who suffer employment related deaths. The liability for traumatic injury claims is our estimate of the present value of current workers’ compensation benefits, based on our actuary estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including development patterns, mortality, medical costs and interest rates. We had accrued liabilities of $51.6 million and $45.7 million for these costs at December 31, 2007 and 2006, respectively. A one-percentage-point reduction in the discount rate would have increased the liability at December 31, 2007 approximately $3.1 million, which would have a corresponding increase in operating expenses.

Coal mining companies are subject to CMHSA, as amended, and various state statutes for the payment of medical and disability benefits to eligible recipients related to coal worker’s pneumoconiosis or “black lung”. We provide for these claims through self-insurance programs. Our black lung benefits liability is calculated using the service cost method based on the actuarial present value of the estimated black lung obligation. Our actuarial calculations are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents and interest rates. We had accrued liabilities of $30.0 million and $26.8 million for these benefits at December 31, 2007 and 2006, respectively. A one-percentage-point reduction in the discount rate would have increased the expense recognized for the year ended December 31, 2007 by approximately $1.0 million. Under the service cost method used to estimate our black lung benefits liability, actuarial gains or losses attributable to changes in actuarial assumptions, such as the discount rate, are amortized over the remaining service period of active miners.

Universal Shelf

In April 2002, we filed with the Securities and Exchange Commission a universal shelf registration statement allowing us to issue from time to time up to an aggregate of $200 million of debt or equity securities. At February 15, 2008, we had approximately $143.0 million available under this registration statement.

Related–Party Transactions

The Board of Directors of our managing general partner and its conflicts committee (“Conflicts Committee”) review each of our related-party transactions to determine that each such transaction reflects market-clearing terms and conditions customary in the coal industry. As a result of these reviews, the Board of Directors and the Conflicts Committee approved each of the transactions described below as fair and reasonable to us and our limited partners.

River View Coal, LLC Acquisition

In April 2006, we acquired 100% of the membership interest in River View for approximately $1.65 million from ARH, which at the time of our acquisition was owned by our current and former management, including majority shareholder Joseph W. Craft, III, President and Chief Executive Officer of our managing general partner. At the time of this acquisition, our managing general partner, was owned jointly by Alliance Management Holdings, LLC and AMH II, LLC, and on a combined basis were majority owned by Joseph W. Craft, III, who was also the sole director of each of them. Additionally, prior to our acquisition of River View, it had the right to purchase certain assets, including additional coal reserves, surface properties, facilities and permits from an unrelated party, for $4.15 million plus an overriding royalty on all coal mined and sold by River View from certain of the leased properties included in the assets. In a separate transaction in April 2006 immediately subsequent to our acquisition of River View, River View purchased these assets from the unrelated party and assumed reclamation liabilities of $2.9 million. River View controls, through coal leases or direct ownership, approximately 117.1 million tons of high-sulfur coal reserves in the No. 7, No. 9 and No. 11 coal seams, located in Union County, Kentucky. As a result of these acquisitions, we recorded assets of $8.7 million, offset by the fair value of the initial asset retirement obligation of approximately $2.9 million.

Tunnel Ridge, LLC Acquisition

In January 2005, we acquired 100% of the membership interests in Tunnel Ridge for approximately $0.5 million and the assumption of reclamation liabilities from ARH, which at the time of our acquisition was owned by our current and former management, including majority shareholder Mr. Craft. Tunnel Ridge controls an estimated 70.5 million tons of high-sulfur coal in the Pittsburgh No. 8 coal seam underlying approximately 9,400 acres of land located in Ohio County, West Virginia and Washington County, Pennsylvania through a coal lease agreement with our special general partner, which is owned indirectly by Mr. Craft,. Under the terms of the coal lease, beginning on January 1, 2005, Tunnel Ridge has paid and will continue to pay our special general partner an advance minimum royalty of $3.0 million per year. The advance royalty payments are fully recoupable against earned royalties. Tunnel Ridge also controls surface land and other tangible assets under a separate lease agreement with SGP.

Because the River View and Tunnel Ridge acquisitions were between entities under common control, they were accounted for at historical cost.

Administrative Services

In connection with the closing of the AHGP IPO, ARLP entered into an Administrative Services Agreement between our managing general partner, our Intermediate Partnership, AHGP and AGP, and ARH II, the indirect parent of SGP. Under the Administrative Services Agreement, certain employees, including some executive officers, provided administrative services to our managing general partner, AHGP, AGP, ARH II and their respective affiliates. We are 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 this agreement of $0.3 million and $0.3 million for the year ended December 31, 2007 and the period from May 15, 2006 to December 31, 2006, respectively, from AHGP and $0.4 million and $0.6 million from ARH II for the years ended December 31, 2007 and 2006, respectively. Concurrently in 2006, AHGP and AGP joined as parties to our Omnibus Agreement which addresses areas of non-competition between us and ARH, ARH II, SGP and our managing general partner.

Our partnership agreement provides that our managing general partner and its affiliates be reimbursed for all direct and indirect expenses incurred or payments made on behalf of us, including, but not limited to, management’s salaries and related benefits (including incentive compensation), and accounting, budgeting, planning, treasury, public relations, land administration, environmental, permitting, payroll, benefits, disability, workers’ compensation management, legal and information technology services. Our managing general partner may determine in its sole discretion the expenses that are allocable to us. Total costs billed by our managing general partner and its affiliates to us were approximately $0.9 million, $4.2 million and $14.1 million for the years ended December 31, 2007, 2006 and 2005, respectively. The decrease from 2006 to 2007 and 2005 to 2006 was attributable to certain employees and the sponsorship of the LTIP, STIP and Supplemental Executive Retirement Plan (“SERP”) being transferred to Alliance Coal effective May 15, 2006 in connection with the closing of AHGP’s IPO. On May 15, 2006, our executive officers became employees of record of Alliance Coal, and we no longer reimburse our managing general partner for compensation expenses associated with them. The impact of the change in plan sponsorship resulted in a reduction in the billing to us from our managing general partner directly offset by a corresponding increase in LTIP, STIP and SERP expense of our Alliance Coal subsidiary. The amounts billed to us from our managing general partner include $2.9 million and $10.6 million for the years ended December 31, 2006 and 2005, respectively, for the LTIP, STIP and SERP.

Managing General Partner Contribution

During December 2007, an affiliated entity controlled by Joseph W. Craft III, contributed 50,980 common units of AHGP valued at approximately $1.1 million at the time of contribution and $0.8 million of cash to AHGP for the purpose of funding certain expenses associated with our employee compensation programs. Upon AHGP’s receipt of this contribution it immediately contributed the same to its subsidiary MGP, our managing general partner, which in turn contributed the same to our subsidiary Alliance Coal. As provided under our partnership agreement we made a special allocation of certain general and administrative expenses equal to the amount of contribution to our managing general partner.

SGP Land, LLC

On May 2, 2007, SGP Land, LLC (“SGP Land”), a subsidiary of our special general partner, entered into a time sharing agreement with Alliance Coal, our operating subsidiary, concerning the use of two airplanes owned by SGP Land. In accordance with the provisions of the time sharing agreement, we reimbursed SGP Land $0.3 million for the year ended December 31, 2007 for use of the airplanes.

In 2000, Webster County Coal entered into a mineral lease and sublease with SGP Land, requiring annual minimum royalty payments of $2.7 million, payable in advance through 2013 or until $37.8 million of cumulative annual minimum and/or earned royalty payments have been paid. Webster County Coal paid royalties of $2.7 million, $3.0 million and $3.4 million for the years ended December 31, 2007, 2006 and 2005, respectively. As of December 31, 2007, Webster County Coal has recouped, against earned royalties otherwise due, all but $3.2 million of the advance minimum royalty payments made under the lease.

In 2001, Warrior entered into a mineral lease and sublease with SGP Land. Under the terms of the lease, Warrior paid in arrears an annual minimum royalty of $2.3 million until $15.9 million of cumulative annual minimum and/or earned royalty payments were paid. The annual minimum royalty periods expired on September 30, 2007. In 2006, Warrior’s cumulative total of annual minimum royalties and/or earned royalty payments exceeded $15.9 million therefore the annual minimum royalty payment of $2.3 million was no longer required. Warrior paid royalties of $1.3 million, $5.1 million and $3.6 million for the years ended December 31, 2007, 2006 and 2005, respectively. As of December 31, 2007, Warrior has recouped, against earned royalties otherwise due, all advance minimum royalty payments made in accordance with these lease terms.

In 2005, Hopkins County Coal entered into a mineral lease and sublease with SGP Land encompassing the Elk Creek reserves, and the parties also entered into a Royalty Agreement (collectively, the “Coal Lease Agreements”) in connection therewith. The Coal Lease Agreements extend through December 2015, with the right to renew for successive one-year periods for as long as Hopkins County Coal is mining within the coal field, as such term is defined in the Coal Lease Agreements. The Coal Lease Agreements provide for five annual minimum royalty payments of $0.7 million beginning in December 2005. The annual minimum royalty payments, together with cumulative option fees of $3.4 million previously paid prior to December 2005 by Hopkins County Coal, are fully recoupable against future earned royalty payments. Hopkins County Coal paid advance minimum royalties and/or option fees of $0.7 million during each of the years ended December 31, 2007, 2006 and 2005, respectively. As of December 31, 2007, $4.4 million of advance minimum royalties and/or option fees paid under the Coal Lease Agreements is available for recoupment, and management expects that it will be recouped against future production.

Under the terms of the mineral lease and sublease agreements described above, Webster County Coal, Warrior, and Hopkins County Coal also reimburse SGP Land for its base lease obligations. We reimbursed SGP Land $6.1 million, $5.0 million and $6.4 million for the years ended December 31, 2007, 2006 and 2005, respectively, for the base lease obligations. As of December 31, 2007, Webster County Coal, Warrior, and Hopkins County Coal have recouped, against earned royalties otherwise due base lessors by SGP Land, all advance minimum royalty payments paid by SGP Land to the base lessors in accordance with the terms of the base leases (and reimbursed by Webster County Coal, Warrior, and Hopkins County Coal), except for $0.4 million.

On January 28, 2008, effective January 1, 2008, we acquired, through our subsidiary Alliance Resource Properties, additional rights to approximately 48.2 million tons of coal reserves located in western Kentucky from SGP Land. The purchase price was $13.3 million. At the time of our acquisition, these reserves were leased by SGP Land to our subsidiaries, Webster County Coal, Warrior and Hopkins County Coal through the mineral leases and sublease agreements described above. Those mineral leases and sublease agreements between SGP Land and our subsidiaries were assigned to Alliance Resource Properties by SGP Land in this transaction. The recoupable balances of advance minimum royalties and other payments at the time of this acquisition, other than $0.4 million to the base lessors, will be eliminated in our consolidated financial statements.

In 2001, SGP Land, as successor in interest to an unaffiliated third-party, entered into an amended mineral lease with MC Mining. Under the terms of the lease, MC Mining has paid and will continue to pay an annual minimum royalty of $0.3 million until $6.0 million of cumulative annual minimum and/or earned royalty payments have been paid. MC Mining paid royalties of $0.3 million, $0.3 million and $0.6 million during the years ended December 31, 2007, 2006 and 2005, respectively (the 2004 annual minimum royalty obligation of $0.3 million was paid in January 2005 rather than in December 2004). As of December 31, 2007, $1.2 million of advance minimum royalties paid under the lease is available for recoupment, and management expects that it will be recouped against future production.

SGP

As noted above, in January 2005, we acquired Tunnel Ridge from ARH. In connection with this acquisition, we assumed a coal lease with the SGP. Under the terms of the lease, Tunnel Ridge has paid and will continue to pay an annual minimum royalty of $3.0 million until the earlier of January 1, 2033 or the exhaustion of the mineable and merchantable leased coal. Tunnel Ridge paid advance minimum royalties of $3.0 million during each of 2007, 2006 and 2005. As of December 31, 2007, $9.0 million of advance minimum royalties paid under the lease is available for recoupment, and management expects will be recouped against future production.

Tunnel Ridge also controls surface land and other tangible assets under a separate lease agreement with the SGP. Under the terms of the lease agreement, Tunnel Ridge has paid and will continue to pay the SGP an annual lease payment of $0.2 million. The lease agreement has an initial term of four years, which may be extended to be coextensive with the term of the coal lease. Lease expense was $0.2 million for each of the years ended December 31, 2007, 2006 and 2005.

We have a noncancelable operating lease arrangement with the SGP for the coal preparation plant and ancillary facilities at the Gibson County Coal mining complex. Based on the terms of the lease, we will make monthly payments of approximately $0.2 million through January 2011. Lease expense incurred for each of the three years in the period ended December 31, 2007 was $2.6 million.

We previously entered into and have maintained agreements with two banks to provide letters of credit in an aggregate amount of $31.0 million. At December 31, 2007, we had $30.6 million in outstanding letters of credit under these agreements. The SGP guarantees $5.0 million of these outstanding letters of credit. Historically, we have compensated the SGP for a guarantee fee equal to 0.30% per annum of the face amount of the letters of credit outstanding. During 2003 the SGP agreed to waive the guarantee fee in exchange for a parent guarantee from the Intermediate Partnership and Alliance Coal on the mineral leases and subleases with Webster County Coal and Warrior described above. Since the guarantee is made on behalf of entities within the consolidated partnership, the guarantee has no fair value under FIN No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantees of Indebtedness of Others, and does not impact our consolidated financial statements.

Accruals of Other Liabilities

We had accruals for other liabilities, including current obligations, totaling $150.8 million and $146.2 million at December 31, 2007 and 2006. These accruals were chiefly comprised of workers’ compensation benefits, black lung benefits, and costs associated with asset retirement obligations. These obligations are self-insured. The accruals of these items were based on estimates of future expenditures based on current legislation, related regulations and other developments. Thus, from time to time, our results of operations may be significantly affected by changes to these liabilities. Please see “Item 8. Financial Statements and Supplementary Data.—Note 15. Asset Retirement Obligations and Note 16. Accrued Workers’ Compensation and Pneumoconiosis (“Black Lung”) Benefits.”

Pension Plan

We maintain a Pension Plan, which covers employees at certain of our mining operations.

Our pension expense was $3.3 million and $3.2 million for the years ended December 31, 2007 and 2006. Our pension expense is based upon a number of actuarial assumptions, including an expected long-term rate of return on our Pension Plan assets of 7.75% and 8.0% and discount rates of 5.55% and 5.60% for the years ended December 31, 2007 and 2006, respectively. Our actual return on plan assets was 8.6% and 12.2% for the years ended December 31, 2007 and 2006, respectively. Additionally, we base our determination of pension expense on an unsmoothed market-related valuation of assets equal to the fair value of assets, which immediately recognizes all investment gains or losses.

The expected long-term rate of return assumption is based on broad equity and bond indices. At December 31, 2007, our expected long-term rate of return assumption was 8.35% determined by the above factors and based on an asset allocation assumption of 60.0% with domestic equity securities, with an expected long-term rate of return of 10.6%, 10% invested in international equities with an expected long-term rate of return of 6.9% and 30.0% with fixed

income securities, with an expected long-term rate of return of 5.8%. We, along with our Pension Plan trustee, regularly review our actual asset allocation in accordance with our investment guidelines and periodically rebalances our investments to our targeted allocation when considered appropriate. The investment committee annually reviews our asset allocation with the compensation committee of our managing general partner (“Compensation Committee”).

The discount rate that we utilize for determining our future pension obligation is based on a review of currently available high-quality fixed-income investments that receive one of the two highest ratings given by a recognized rating agency. We have historically used the average monthly yield for December of an A-rated utility bond index as the primary benchmark for establishing the discount rate. At December 31, 2007 the discount rate was determined using high quality bond yield curves adjusted to reflect the plan’s estimated payout. The discount rate determined on this basis increased from 5.55% at December 31, 2006 to 6.65% at December 31, 2007.

We estimate that our Pension Plan expense and cash contributions will be approximately $1.9 million and $2.5 million, respectively, in 2008. Future actual pension expense and contributions will depend on future investment performance, changes in future discount rates and various other factors related to the employees participating in the Pension Plan.

Lowering the expected long-term rate of return assumption by 1.0% (from 7.75% to 6.75%) at December 31, 2006 would have increased our pension expense for the year ended December 31, 2007 by approximately $0.3 million. Lowering the discount rate assumption by 0.5% (from 5.55% to 5.05%) at December 31, 2006 would have increased our pension expense for the year ended December 31, 2007 by approximately $0.7 million.

Inflation

Generally, inflation in the U.S. has been relatively low in recent years. However, over the course of the last three years, our results have been significantly impacted by price inflation as it relates to many of the components of our operating expenses such as fuel, steel, maintenance expense and labor. If the prices for which we sell our coal do not increase in step with rising costs, our margins will be reduced.

New Accounting Standards

New Accounting Standards Adopted

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.

In June 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. 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. Our adoption of FIN No. 48 on January 1, 2007 did not have a material impact on our consolidated financial statements.

New Accounting Standards Issued and Not Yet Adopted

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. 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 with the exception of nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value on a nonrecurring basis for which the requirements of SFAS No. 157 have been deferred by the FASB for one year. We are currently evaluating the requirements of SFAS No. 157 and do not expect the adoption of SFAS No. 157 to have a material impact on our consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 allows entities to choose to measure financial instruments and certain other eligible items at fair value which are not otherwise currently required to be measured at fair value. Under SFAS No. 159, the decision to measure items at fair value is made at specified election dates on an irrevocable instrument-by-instrument basis. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the requirements of SFAS No. 159 and do not expect the adoption of SFAS No. 159 to have a material impact on our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141R, Business Combinations, and SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements. SFAS Nos. 141R and 160 require most identifiable assets, liabilities, noncontrolling interests and goodwill acquired in a business combination to be recorded at “full fair value” and require noncontrolling interests (previously referred to as minority interests) to be reported as a component of equity, which changes the accounting for transactions with noncontrolling interest holders. Both statements are effective for periods beginning on or after December 15, 2008 and earlier adoption is prohibited. SFAS No. 141R will be applied to business combinations occurring after the effective date and SFAS No. 160 will be applied prospectively to all noncontrolling interests, including any that arose before the effective date. We are currently evaluating the requirements of SFAS Nos. 141R and 160 and have not yet determined the impact on our consolidated financial statements.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We have significant long-term coal supply agreements. Virtually all of the 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. For additional discussion of coal supply agreements, please see “Item 1. Business. – Coal Marketing and Sales” and “Item 8. Financial Statements and Supplementary Data. – Note 20. Concentration of Credit Risk and Major Customers.”

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. Historically, our earnings have not been materially affected by changes in interest rates. Borrowings outstanding under the ARLP Credit Facility were $28.0 million at December 31, 2007.

The table below provides information about our market sensitive financial instruments and constitutes a “forward-looking statement.” The fair values of long-term debt are estimated using discounted cash flow analyses, based upon our current incremental borrowing rates for similar types of borrowing arrangements as of December 31, 2007 and 2006. The carrying amounts and fair values of financial instruments are as follows (in thousands):


Expected Maturity Dates as of December 31, 2007	2008		2009		2010		2011		2012		Thereafter		Total		Fair Value December 31, 2007
Senior Notes fixed rate	$	18,000	$	18,000	$	18,000	$	18,000	$	18,000	$	36,000	$	126,000	$	136,559
Weighted Average interest rate		8.31%		8.31%		8.31%		8.31%		8.31%		8.31%

Expected Maturity Dates as of December 31, 2006	2007		2008		2009		2010		2011		Thereafter		Total		Fair Value December 31, 2006
Senior Notes fixed rate	$	18,000	$	18,000	$	18,000	$	18,000	$	18,000	$	54,000	$	144,000	$	156,179
Weighted Average interest rate		8.31%		8.31%		8.31%		8.31%		8.31%		8.31%

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of the Managing

General Partner and the Partners of

Alliance Resource Partners, L.P.:

We have audited the accompanying consolidated balance sheets of Alliance Resource Partners, L.P. and subsidiaries (the “Partnership”) as of December 31, 2007 and 2006, and the related consolidated statements of income, cash flows and Partners’ capital (deficit) and comprehensive income (loss) for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Alliance Resource Partners, L.P. and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 29, 2008 expressed an unqualified opinion on the Partnership’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Tulsa, Oklahoma

February 29, 2008

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2007 AND 2006

(In thousands, except unit data)


	December 31,
	2007			2006
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	1,118		$	36,789
Trade receivables		92,667			96,558
Other receivables		3,399			3,378
Due from affiliates		139			25
Marketable securities		—			260
Inventories		26,100			20,224
Advance royalties		4,452			4,629
Prepaid expenses and other assets		9,099			8,225

Total current assets		136,974			170,088

PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost		948,210			819,991
Less accumulated depreciation, depletion and amortization		(427,572	)		(383,284	)

Total property, plant and equipment, net		520,638			436,707

OTHER ASSETS:
Advance royalties		25,974			22,135
Other long-term assets		18,137			6,032

Total other assets		44,111			28,167

TOTAL ASSETS	$	701,723		$	634,962


LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	46,392		$	57,879
Due to affiliates		1,343			1,414
Accrued taxes other than income taxes		11,091			14,618
Accrued payroll and related expenses		15,180			14,698
Accrued interest		3,826			4,264
Workers’ compensation and pneumoconiosis benefits		8,124			7,704
Current capital lease obligation		377			339
Other current liabilities		6,754			13,786
Current maturities, long-term debt		18,000			18,000

Total current liabilities		111,087			132,702

LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		136,000			126,000
Pneumoconiosis benefits		29,392			26,315
Accrued pension benefit		—			6,191
Workers’ compensation		44,150			38,488
Asset retirement obligations		54,903			47,825
Due to affiliates		1,295			994
Long-term capital lease obligation		1,135			1,512
Minority interest		507			839
Other liabilities		6,037			5,616

Total long-term liabilities		273,419			253,780

Total liabilities		384,506			386,482

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
Limited Partners - Common Unitholders 36,550,659 and 36,419,847 units outstanding, respectively		607,777			549,005
General Partners’ deficit		(290,669	)		(293,569	)
Accumulated other comprehensive income (loss)		109			(6,956	)

Total Partners’ capital		317,217			248,480

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	701,723		$	634,962

See notes to consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

(In thousands, except unit and per unit data)



	Year Ended December 31,
	2007			2006			2005
SALES AND OPERATING REVENUES:
Coal sales	$	960,354		$	895,823		$	768,958
Transportation revenues		37,688			39,879			39,069
Other sales and operating revenues		35,292			31,855			30,691

Total revenues		1,033,334			967,557			838,718

EXPENSES:
Operating expenses		685,085			627,756			521,488
Transportation expenses		37,688			39,879			39,069
Outside purchases		21,969			19,213			15,113
General and administrative		34,479			30,884			33,484
Depreciation, depletion and amortization		85,310			66,489			55,637
Net gain from insurance settlement		(11,491	)		—			—

Total operating expenses		853,040			784,221			664,791

INCOME FROM OPERATIONS		180,294			183,336			173,927
Interest expense (net of interest capitalized of $1,237, $1,558 and $566, respectively)		(11,656	)		(12,177	)		(14,617	)
Interest income		1,704			3,002			2,801
Other income		1,385			936			581

INCOME BEFORE INCOME TAXES, CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND MINORITY INTEREST		171,727			175,097			162,692
INCOME TAX EXPENSE		1,669			2,443			2,682

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND MINORITY INTEREST		170,058			172,654			160,010
CUMULATIVE EFFECT OF ACCOUNTING CHANGE		—			112			—
MINORITY INTEREST		332			161			—

NET INCOME	$	170,390		$	172,927		$	160,010

GENERAL PARTNERS’ INTEREST IN NET INCOME	$	31,310		$	24,594		$	12,409

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	139,080		$	148,333		$	147,601

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	3.07		$	3.06		$	2.89

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	3.05		$	3.03		$	2.84

DISTRIBUTIONS PAID PER COMMON UNIT	$	2.20		$	1.92		$	1.58

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC		36,548,150			36,425,350			36,288,527

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING – DILUTED		36,800,212			36,810,383			36,977,061

See notes to consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

(In thousands)



	Year Ended December 31,
	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	170,390		$	172,927		$	160,010
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		85,310			66,489			55,637
Non-cash compensation expense		3,925			4,112			8,193
Asset retirement obligations		2,419			2,101			1,918
Coal inventory adjustment to market		21			319			573
Net (gain)/loss on sale of property, plant and equipment		(3,189	)		(1,188	)		179
Gain from insurance recoveries for property damage		(2,357	)		—			—
Gain from insurance settlement proceeds received in a prior period		(5,088	)		—			—
Loss on retirement of damaged vertical belt equipment		—			—			1,298
Minority interest		(332	)		(161	)		—
Cumulative effect of accounting change		—			(112	)		—
Other		811			1,119			580
Changes in operating assets and liabilities:
Trade receivables		3,891			(2,051	)		(37,528	)
Other receivables		1,236			(1,048	)		(693	)
Inventories		(6,484	)		(3,851	)		(4,004	)
Prepaid expenses and other assets		(874	)		757			(4,584	)
Advance royalties		(2,724	)		(6,484	)		(4,396	)
Accounts payable		(6,623	)		1,677			13,115
Due to affiliates		116			(1,762	)		(3,265	)
Accrued taxes other than income taxes		(3,527	)		1,441			2,435
Accrued payroll and related benefits		482			1,659			736
Pneumoconiosis benefits		3,230			3,022			3,460
Workers’ compensation		5,929			8,402			4,715
Other		(2,550	)		3,555			(4,761	)

Total net adjustments		73,622			77,996			33,608

Net cash provided by operating activities		244,012			250,923			193,618

CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(119,590	)		(188,630	)		(119,881	)
Changes in accounts payable and accrued liabilities		(7,094	)		2,776			9,364
Proceeds from sale of property, plant and equipment		6,770			1,401			198
Proceeds from insurance settlement for replacement assets		2,511			—			—
Purchase of marketable securities		—			(19,447	)		(63,448	)
Proceeds from marketable securities		260			68,497			63,589
Payment for acquisition of coal reserves and other assets		(53,309	)		—			—
Payments for acquisition of businesses		—			(2,289	)		—
Advances on Gibson rail project		(8,212	)		—			—

Net cash used in investing activities		(178,664	)		(137,692	)		(110,178	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on long-term debt		(18,000	)		(18,000	)		(18,000	)
Borrowings under revolving credit facilities		195,650			—			—
Payments under revolving credit facilities		(167,650	)		—			—
Payments on capital lease obligation		(339	)		—			—
Payment of debt issuance costs		(264	)		(690	)		—
Equity contribution received by Mid-America Carbonates, LLC		—			1,000			—
Contributions by General Partners		904			2			143
Distributions paid to Partners		(111,320	)		(90,808	)		(64,706	)

Net cash used in financing activities		(101,019	)		(108,496	)		(82,563	)

NET CHANGE IN CASH AND CASH EQUIVALENTS		(35,671	)		4,735			877
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		36,789			32,054			31,177

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,118		$	36,789		$	32,054

See notes to consolidated financial statements, including Note 14 for supplemental cash flow information.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL (DEFICIT) AND ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

(In thousands, except unit data)



	Number of Limited Partner Units		Limited Partners’ Capital			General Partners’ Capital (Deficit)			Unrealized Gain (Loss)			Accumulated Other Comprehensive Income (Loss)			Total Partners’ Capital
Balance at January 1, 2005	36,260,880		$	363,658		$	(303,295	)	$	(54	)	$	(5,122	)	$	55,187
Comprehensive income:
Net income	—			147,601			12,409			—			—			160,010
Unrealized loss	—			—			—			(14	)		—			(14	)
Minimum pension liability	—			—			—			—			(1,831	)		(1,831	)

Total comprehensive income	—			147,601			12,409			(14	)		(1,831	)		158,165
Issuance of units to Long-Term Incentive Plan participants upon vesting	165,426			6,988			—			—			—			6,988
General Partners contribution	—			—			143			—			—			143
Distribution to Partners	—			(57,179	)		(7,527	)		—			—			(64,706	)


Balance at December 31, 2005	36,426,306			461,068			(298,270	)		(68	)		(6,953	)		155,777
Comprehensive income:
Net income	—			148,333			24,594			—			—			172,927
Unrealized gain	—			—			—			68			—			68
Other comprehensive income (loss)	—			—			—			—			(3	)		(3	)

Total comprehensive income (loss)	—			148,333			24,594			68			(3	)		172,992
Common unit – based compensation under Long-Term Incentive Plan	—			10,517			—			—			—			10,517
General Partner contribution	—			—			2			—			—			2
Retirement of common units contributed by our Managing General Partner	(6,459	)		(222	)		222			—			—			—
Distributions on common unit based compensation	—			(753	)		—			—			—			(753	)
Distribution to Partners	—			(69,938	)		(20,117	)		—			—			(90,055	)

Balance at December 31, 2006	36,419,847			549,005			(293,569	)					(6,956	)		248,480
Comprehensive income:
Net income	—			139,080			31,310			—			—			170,390
Other comprehensive income	—			—			—			—			7,065			7,065

Total comprehensive income	—			139,080			31,310			—			7,065			177,455
Issuance of units to Long-Term Incentive Plan participants upon vesting	130,812			(2,227	)		—			—			—			(2,227	)
Common unit – based compensation under Long-Term Incentive Plan	—			2,820			—			—			—			2,820
General Partner contributions	—			—			2,009			—			—			2,009
Distributions on common unit based compensation	—			(489	)		—			—			—			(489	)
Distribution to Partners	—			(80,412	)		(30,419	)		—			—			(110,831	)

Balance at December 31, 2007	36,550,659		$	607,777		$	(290,669	)	$	—		$	109		$	317,217

See notes to consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

1.	ORGANIZATION AND PRESENTATION

Significant Relationships Referenced in Notes to Consolidated Financial Statements

•

References to “ARLP” mean 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, the managing general partner of Alliance Resource Partners, L.P., also referred to as our managing general partner.

•

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

•

References to “Alliance Coal” mean Alliance Coal, LLC, the holding company for the operations of Alliance Resource Operating Partners, L.P., also referred 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, the general partner of Alliance Holdings GP, L.P.

Organization

ARLP is a Delaware limited partnership listed on the NASDAQ Global Select Market under the ticker symbol “ARLP.” ARLP was formed in May 1999, to acquire upon completion of ARLP’s initial public offering on August 19, 1999, certain coal production and marketing assets of Alliance Resource Holdings, Inc., a Delaware corporation (“ARH”), consisting of substantially all of ARH’s operating subsidiaries, but excluding ARH. ARH was previously owned by our current and former management. In June 2006, our special general partner, SGP, and its parent, ARH, became wholly-owned, directly and indirectly, by Joseph W. Craft, III, the President and Chief Executive Officer of our managing general partner. SGP, a Delaware limited liability company, holds a 0.01% general partner interest in each of ARLP and the Intermediate Partnership. We lease certain assets, including coal reserves and certain surface facilities, owned by SGP (Note 18).

We are managed by our managing general partner, MGP, a Delaware limited liability company, which holds a 0.99% and a 1.0001% managing general partner interest in ARLP and the Intermediate Partnership, respectively and a 0.001% managing member interest in Alliance Coal. AHGP is a Delaware limited partnership that was formed to become the owner and controlling member of MGP. AHGP completed its initial public offering (“AHGP IPO”) on May 15, 2006. AHGP owns directly and indirectly 100% of the members’ interest of MGP, the incentive distribution rights in ARLP and 15,544,169 common units of ARLP.

The Delaware limited partnership, limited liability companies and corporation that comprise our subsidiaries are as follows: Intermediate Partnership, Alliance Coal, Alliance Design Group, LLC, Alliance Land, LLC, Alliance Properties, LLC, Alliance Resource Properties, LLC, (“Alliance Resource Properties”), Alliance Service, Inc. (“Alliance Service”), Backbone Mountain, LLC, Excel Mining, LLC (“Excel”), Gibson County Coal, LLC (“Gibson County Coal”), Hopkins County Coal, LLC (“Hopkins County Coal”), Matrix Design Group, LLC (“Matrix Design”), MC Mining, LLC (“MC Mining”), Mettiki Coal, LLC (“Mettiki (MD)”), Mettiki Coal (WV), LLC (“Mettiki (WV)”), Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”), Penn Ridge Coal, LLC (“Penn Ridge”), Pontiki Coal, LLC (“Pontiki Coal”), River View Coal, LLC (“River View”), Tunnel Ridge, LLC (“Tunnel Ridge”), Warrior Coal, LLC (“Warrior”), Webster County Coal, LLC (“Webster County Coal”), and White County Coal, LLC (“White County Coal”).

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.

The accompanying consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of December 31, 2007 and 2006, results of our operations, cash flows and changes in partners’ capital (deficit) and comprehensive income (loss) for each of the three years in the period ended December 31, 2007. All material intercompany transactions and accounts of the ARLP Partnership have been eliminated.

2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Estimates—The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements. Actual results could differ from those estimates.

Fair Value of Financial Instruments—The carrying amounts for accounts receivable, marketable securities, and accounts payable approximate fair value because of the short maturity of those instruments. At December 31, 2007 and 2006, the estimated fair value of long-term debt, including current maturities, was approximately $136.6 million and $156.2 million, respectively (Note 8). The estimated 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.

Cash and Cash Equivalents—Cash and cash equivalents include cash on hand and on deposit, including highly liquid investments with maturities of three months or less. We had restricted cash and cash equivalents of $2.0 million and $1.9 million at December 31, 2007 and 2006, respectively, which are included in other assets in our consolidated balance sheets. The restricted cash and cash equivalents are held in escrow and secure reclamation bonds.

Cash Management—We presented book overdrafts of $6.7 million and $11.3 million at December 31, 2007 and 2006, respectively, in accounts payable in the consolidated balance sheets.

Marketable Securities—We had no marketable securities at December 31, 2007. At December 31, 2006, our marketable securities are classified as available for sale and consisted of $0.3 million of Federal home loan discount notes reported at fair value with unrealized gains and losses reflected as a component of Partners’ capital until realized.

Inventories—Coal inventories are stated at the lower of cost or market on a first-in, first-out basis. Supply inventories are stated at the lower of cost or market on an average cost basis, less a reserve for obsolete and surplus items.

Property, Plant and Equipment—Expenditures which extend the useful lives of existing plant and equipment assets are capitalized. Maintenance and repairs that do not extend the useful life or increase productivity of the asset are charged to operating expense as incurred. Exploration expenditures are charged to operating expense as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves. Depreciation and amortization are computed principally on the straight-line method based upon the estimated useful lives of the assets or the estimated life of each mine, whichever is less, ranging from 2 to 15 years. Depreciable lives for mining equipment and processing facilities range from 2 to 15 years. Depreciable lives for land and land improvements and depletable lives for mineral rights range from 2 to 15 years. Depreciable lives for buildings, office equipment and improvements range from 2 to 15 years. Gains or losses arising from retirements are included in current operations. Depletion of mineral rights is provided on the basis of tonnage mined in relation to estimated recoverable tonnage. At December 31, 2007 and 2006, land and mineral rights include $12.2 million and $14.1 million, respectively, representing the carrying value of coal reserves attributable to properties where we are not currently engaged in mining operations or leasing to third-parties, and therefore, the coal reserves are not currently being depleted. We believe that the carrying value of these reserves will be recovered.

Mine Development Costs—Mine development costs are capitalized until production, other than production incidental to the mine development process, commences and are amortized over the estimated life of the mine. Mine development costs represent costs incurred in establishing access to mineral reserves and include costs associated with sinking or driving shafts and underground drifts, permanent excavations, roads and tunnels. The end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase. Amortization of capitalized mine development is computed based on the estimated life of the mine and commences when production, other than production incidental to the mine development process, begins.

Long-Lived Assets—We review the carrying value of long-lived assets and certain identifiable intangibles whenever events or changes in circumstances indicate that the carrying amount may not be recoverable based upon estimated undiscounted future cash flows. The amount of impairment is measured by the difference between the carrying value and the fair value of the asset. We have not recorded an impairment loss for any of the periods presented.

Intangible Assets—Costs allocated to contracts with covenants not to compete (“Non-Compete Agreements”) are amortized on a straight-line basis over the life of the Non-Compete Agreement. Amortization expense associated with Non-Compete Agreements was $0.3 million, $38,000 and $13,000 for the years ending December 31, 2007, 2006 and 2005, respectively. Our Non-Compete Agreements are included in other assets on our consolidated balance sheets at December 31, 2007 and 2006. Our Non-Compete Agreements at December 31, 2007 are summarized as follows (in thousands):


	2007			2006
Non-Compete Agreements, original cost	$	4,153		$	507
Accumulated amortization		(372	)		(75	)

Non-Compete Agreements, net	$	3,781		$	432

Amortization expense related to Non-Compete Agreements is estimated to be $0.5 million per year in 2008-2010 and $0.4 million per year in 2011-2012.

Advance Royalties—Rights to coal mineral leases are often acquired and/or maintained through advance royalty payments. Where royalty payments represent prepayments recoupable against future production, they are recorded as an asset, with amounts expected to be recouped within one year classified as a current asset. As mining occurs on these leases, the royalty prepayments are charged to operating expenses. We assess the recoverability of royalty prepayments based on estimated future production. Royalty prepayments estimated to be nonrecoverable are expensed.

Asset Retirement Obligations—We record a liability for the estimated cost of future mine asset retirement and closing procedures on a present value basis when incurred and a corresponding amount is capitalized by increasing the carrying amount of the related long-lived asset. Those costs relate to permanently sealing portals at underground mines and to reclaiming the final pits and support acreage at surface mines. Examples of these types of costs, common to both types of mining, include, but are not limited to, removing or covering refuse piles and settling ponds, water treatment obligations, and dismantling preparation plants, other facilities and roadway infrastructure. Amortization of the related asset is recorded on a straight-line method based upon the estimated life of the mine (Note 15).

Workers’ Compensation and Pneumoconiosis (“Black Lung”) Benefits—We are generally self-insured for workers’ compensation benefits, including black lung benefits. We accrue a workers’ compensation liability for the estimated present value of workers’ compensation and black lung benefits based on our actuarial determined calculations (Note 16).

Income Taxes—We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities accrues to the unitholders. Although publicly traded partnerships as a general rule will be taxed as corporations, we qualify for an exemption because at least 90% of our income consists of qualifying income. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. Individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in our consolidated financial statements. Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes in our partnership is not available to us. Our subsidiary, Alliance Service is subject to federal and state income taxes. Our tax counsel has provided an opinion that ARLP, the Intermediate Partnership and Alliance Coal will each be treated as a partnership. However, as is customary, no ruling has been or will be requested from the IRS regarding our classification as a partnership for federal income tax purposes.

Revenue Recognition—Revenues from coal sales are recognized when title passes to the customer as the coal is shipped. Some coal supply agreements provide for price adjustments based on variations in quality characteristics of the coal shipped. In certain cases, a customer’s analysis of the coal quality is binding and the results of the analysis are received on a delayed basis. In these cases, we estimate the amount of the quality adjustment and adjust the estimate to actual when the information is provided by the customer. Historically such adjustments have not been material. Non-coal sales revenues primarily consist of rental and service fees associated with agreements to host and operate third-party coal synfuel facilities and to assist with the coal synfuel marketing and other related services. These non-coal sales revenues are recognized as the services are performed. Transportation revenues are recognized in connection with us incurring the corresponding costs of transporting coal to customers through third-party carriers for which we are directly reimbursed through customer billings. We had no allowance for doubtful accounts for trade receivables at December 31, 2007 and 2006, respectively.

Common Unit-Based Compensation—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. Under this method, compensation cost is recognized in the financial statements beginning with the effective date, of all share-based payments granted after that date, and based on the requirements of SFAS No. 123, Accounting for Stock-Based Compensation, for all unvested awards granted prior to the effective date of SFAS No. 123R.

Prior to the adoption of SFAS No. 123R, we accounted for compensation expense attributable to the non-vested restricted common units granted under the Long-Term Incentive Plan (“LTIP”) using the intrinsic value method prescribed in Accounting Principles Board Opinion (“APB”) No. 25, Accounting for Stock Issued to Employees and the related Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) 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 (Note 13).

Consistent with the 2005 disclosure requirements of SFAS No. 148, Accounting for Stock-Based Compensation Transition and Disclosure, an amendment of SFAS No. 123, the following table demonstrates that compensation cost for the non-vested restricted units granted under the LTIP is the same under the intrinsic value method and the provisions of SFAS No. 123 (in thousands, except per unit data):


	Year Ended December 31, 2005
	Year Ended December 31, 2005
Net income, as reported	$	160,010

Add: compensation expense related to LTIP units included in reported net income		8,193

Deduct: compensation expense related to LTIP units determined under fair value method for all awards		(8,193	)

Net income, pro forma		160,010

General partners’ interest in net income, pro forma		12,409

Limited partners’ interest in net income, pro forma	$	147,601

Earnings per limited partner unit:
Basic, as reported	$	2.89
Basic, pro forma	$	2.89
Diluted, as reported	$	2.84
Diluted, pro forma	$	2.84

Net Income Per Unit—Basic net income per limited partner unit is determined by dividing Limited Partners’ interest in net income, by the weighted average number of outstanding common units and subordinated units. In periods when our aggregate net income exceeds the aggregate distributions to our limited and general partners, Emerging Issues Task Force (“EITF”) Issue No. 03-6, Participating Securities and the Two-Class Method under FASB Statement No. 128, requires us to present earnings per unit as if all of the earnings for the periods were distributed (Note 11). Diluted net income per unit is based on the combined weighted average number of Common Units and common unit equivalents outstanding, which primarily include restricted units granted under the LTIP (Note 13).

New Accounting Standards Adopted—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 13).

In June 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. 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. Since we are not a taxable entity for federal and state income tax purposes, our adoption of FIN No. 48 on January 1, 2007 did not have a material impact on our consolidated financial statements.

New Accounting Standards Issued and Not Yet Adopted—In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. 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 with the exception of nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value on a nonrecurring basis for which the requirements of SFAS No. 157 have been deferred by the FASB for one year. We are currently evaluating the requirements of SFAS No. 157 and do not expect the adoption of SFAS No. 157 to have a material impact on our consolidated financial statements.

No. 159 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the requirements of SFAS No. 159 and do not expect the adoption of SFAS No. 159 to have a material impact on our consolidated financial statements.

3.	ACQUISITIONS

Illinois Basin Reserve Acquisition

In June 2007, our subsidiary, Alliance Resource Properties acquired the rights to approximately 78.4 million tons of high-sulfur coal reserves in Webster and Hopkins County, Kentucky from Island Creek Coal Company, a subsidiary of Consol Energy, Inc. The purchase price of $53.3 million cash paid at closing was primarily allocated to owned and leased coal rights. We financed the purchase using a combination of existing cash on hand and borrowings under our revolving credit facility. We intend to mine these reserves from our adjacent Dotiki and Warrior mining complexes utilizing continuous mining units employing room-and-pillar mining techniques. As a result of the purchase, we reclassified 8.4 million tons of high-sulfur, non-reserve coal deposits as reserves. This acquisition represented an approximate 14% increase in our reserves at the acquisition date.

River View Coal, LLC

In April 2006, we acquired 100% of the membership interest in River View for approximately $1.65 million from ARH, which at the time of our acquisition was owned by our current and former management, including majority shareholder Joseph W. Craft, III, President and Chief Executive Officer of our managing general partner. At the time of this acquisition, our managing general partner, was owned jointly by Alliance Management Holdings, LLC and AMH II, LLC, and on a combined basis were majority owned by Joseph W. Craft, III, who was also the sole director of each of them. Additionally, prior to our acquisition of River View, it had the right to purchase certain assets, including additional coal reserves, surface properties, facilities and permits from an unrelated party, for $4.15 million plus an overriding royalty on all coal mined and sold by River View from certain of the leased properties included in the assets. In a separate transaction in April 2006, immediately subsequent to our acquisition of River View, River View purchased these assets from the unrelated party and assumed reclamation liabilities of $2.9 million. River View controls, through coal leases or direct ownership, approximately 117.1 million tons of high-sulfur coal reserves in the No. 7, No. 9 and No. 11 coal seams, located in Union County, Kentucky. As a result of these acquisitions, we recorded assets of $8.7 million, offset by the fair value of the initial asset retirement obligation of approximately $2.9 million.

Tunnel Ridge, LLC

In January 2005, we acquired 100% of the membership interests in Tunnel Ridge for approximately $0.5 million and the assumption of reclamation liabilities from ARH, which at the time of our acquisition was owned by our current and former management, including majority shareholder Mr. Craft. Tunnel Ridge controls an estimated 70.5 million tons of high-sulfur coal in the Pittsburgh No. 8 coal seam underlying approximately 9,400 acres of land located in Ohio County, West Virginia and Washington County, Pennsylvania, through a coal lease agreement with our special general partner, which is owned indirectly by Mr. Craft. Under the terms of the coal lease, beginning on January 1, 2005, Tunnel Ridge has paid and will continue to pay our special general partner an advance minimum royalty of $3.0 million per year. The advance royalty payments are fully recoupable against earned royalties (Note 18). Tunnel Ridge also controls surface land and other tangible assets under a separate lease agreement with SGP.

The River View and Tunnel Ridge transactions described above were related-party transactions and, as such, were reviewed by the board of directors of our managing general partner (“Board of Directors”) and its conflicts committee

(“Conflicts Committee”). Based upon these reviews, the Conflicts Committee determined that these transactions reflected market-clearing terms and conditions customary in the coal industry. As a result, the Board of Directors and its Conflicts Committee approved the River View and Tunnel Ridge transactions as fair and reasonable to us and our limited partners. Because River View and Tunnel Ridge acquisitions were between entities under common control, they were accounted for at historical cost.

4.	MC MINING MINE FIRE

5.	INVENTORIES

Inventories consist of the following at December 31, (in thousands):


	2007		2006
Coal	$	12,660	$	8,410
Supplies (net of reserve for obsolescence of $1,233 and $646, respectively)		13,440		11,814

Total inventory	$	26,100	$	20,224

6.	PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consist of the following at December 31, (in thousands):


	2007			2006
Mining equipment and processing facilities	$	627,712		$	572,935
Land and mineral rights		91,240			39,323
Buildings, office equipment and improvements		109,624			74,979
Construction in progress		13,341			41,916
Mine development costs		106,293			90,838

Property, plant and equipment, at cost		948,210			819,991
Less accumulated depreciation, depletion and amortization		(427,572	)		(383,284	)

Total property, plant and equipment, net	$	520,638		$	436,707

Equipment leased by us under lease agreements which are determined to be capital leases are stated at an amount equal to the present value of the minimum lease payments during the lease term, less accumulated amortization. Equipment under capital leases totaling $1.9 million included in mining equipment and processing facilities, is amortized on the straight-line method over the shorter of its useful life or the related lease term. The provision for amortization of leased properties is included in depreciation, depletion and amortization expense. Accumulated amortization related to our capital lease was $0.3 million and $0.1 million as of December 31, 2007 and 2006, respectively, and amortization expense was $0.2 million and $0.1 million for the years ended December 31, 2007 and 2006, respectively.

7.	GIBSON RAIL ADVANCES

In 2007, our subsidiary, Gibson County Coal entered into contracts with CSX Transportation, Inc. (“CSX”) and Norfolk Southern Railway Company (“NS”), pursuant to which Gibson County Coal constructed a rail loop and the railroads constructed connections and siding facilities, in order to provide Gibson County Coal access to CSX and NS railways. Although these connections and siding facilities are assets of the respective rail companies, Gibson County Coal advanced $8.2 million on a combined basis to CSX and NS during 2007 toward the cost of construction of their infrastructure, which is recorded in other receivables and other long-term assets in our consolidated balance sheet at December 31, 2007. These advances will be repaid to Gibson County Coal by rebates from CSX and NS as coal is shipped on their respective railways. In addition, Gibson County Coal will also qualify for additional rebates from both CSX and NS. The additional rebates will be credited to operating expenses in the consolidated income statement as earned under the terms of each agreement.

8.	LONG-TERM DEBT

Long-term debt consists of the following at December 31, (in thousands):


	2007			2006
Senior notes	$	126,000		$	144,000
Credit Facility		28,000			—

		154,000			144,000
Less current maturities		(18,000	)		(18,000	)

Total long-term debt	$	136,000		$	126,000

Aggregate maturities of long-term debt are payable as follows (in thousands):


Year Ending December 31,
2008	$	18,000
2009		18,000
2010		18,000
2011		18,000
2012		46,000
Thereafter		36,000

	$	154,000

9.	DISTRIBUTIONS OF AVAILABLE CASH

We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partners. Available cash is generally defined as all cash and cash equivalents on hand at the end of each quarter less reserves established by our managing general partner in its reasonable discretion for future cash requirements. These reserves are retained to provide for the conduct of our business, the payment of debt principal and interest and to provide funds for future distributions.

As quarterly distributions of available cash exceed the minimum quarterly distribution (“MQD”) and target distributions levels as established in our partnership agreement, our managing general partner receives distributions based on specified increasing percentages of the available cash that exceed the MQD and the target distribution levels. Our partnership agreement defines the MQD as $0.25 per unit ($1.00 per unit on an annual basis). The target distribution levels are based on the amounts of available cash from our operating surplus distributed for a given quarter that exceed the MQD and common unit arrearages, if any.

Under the quarterly incentive distribution rights provisions of our partnership agreement, 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. For the years ended December 31, 2007, 2006 and 2005, we allocated to our managing general partner incentive distributions of $30.4 million, $21.6 million and $9.4 million, respectively. The following table summarizes the quarterly per unit distribution paid during the respective quarter.


	Year
	2007		2006		2005
First Quarter	$	0.5400	$	0.4600	$	0.3750
Second Quarter	$	0.5400	$	0.4600	$	0.3750
Third Quarter	$	0.5600	$	0.5000	$	0.4125
Fourth Quarter	$	0.5600	$	0.5000	$	0.4125

On January 24, 2008, we declared a quarterly distribution of $0.585 per unit, totaling approximately $30.3 million (which includes our managing general partner’s incentive distributions), on all our common units outstanding, which was paid on February 14, 2008, to all unitholders of record on February 7, 2008.

10.

INCOME TAXES

Our subsidiary, Alliance Service, is subject to federal and state income taxes. Alliance Service’s income consists primarily of rental and service fees provided to an independent coal synfuel producer at Warrior. In September 2006, Alliance Service purchased assets from Matrix Design Group, Inc. through Matrix Design, a newly formed wholly-owned subsidiary. Alliance Service has minor temporary differences between Matrix Design’s financial reporting basis and the tax basis of its assets and liabilities. Our adoption of FIN No. 48 on January 1, 2007 did not have a material impact on the consolidated financial statements and does not impact our financial position at December 31, 2007. Components of income tax expense are as follows (in thousands):


	Year Ended December 31,
	2007			2006			2005
Current:
Federal	$	1,467		$	2,070		$	2,115
State		276			399			567

		1,743			2,469			2,682
Deferred:
Federal		(61	)		(21	)		—
State		(13	)		(5	)		—

		(74	)		(26	)		—

Income tax expense	$	1,669		$	2,443		$	2,682

Reconciliations from the provision for income taxes at the U.S. federal statutory tax rate to the effective tax rate for the provision for income taxes are as follows (in thousands):


	Year Ended December 31,
	2007			2006			2005
Income taxes at statutory rate	$	59,921		$	61,101		$	56,942
Less: Income taxes at statutory rate on Partnership income not subject to income taxes		(58,420	)		(58,923	)		(54,527	)
Increase/(decrease) resulting from:
State taxes, net of federal income tax benefit		183			318			346
Other		(15	)		(53	)		(79	)

Income tax expense	$	1,669		$	2,443		$	2,682

11.

NET INCOME PER LIMITED PARTNER UNIT

In March 2004, the FASB issued EITF Issue 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 period 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 our 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 periods, EITF No. 03-6 does not have any impact on our earnings per unit calculation.

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


	Year Ended December 31,
	2007			2006			2005
Net income	$	170,390		$	172,927		$	160,010
Adjustments:
General partner’s priority distributions		(30,390	)		(21,567	)		(9,397	)
General partners’ 2% equity ownership		(2,838	)		(3,027	)		(3,012	)
General partners’ special allocation of certain general and administrative expenses		1,918			—			—

Limited partners’ interest in net income		139,080			148,333			147,601
Additional earnings allocation to general partners’		(27,009	)		(36,937	)		(42,740	)

Net income available to limited partners under EITF No. 03-6	$	112,071		$	111,396		$	104,861

Weighted average limited partner units – basic		36,548			36,425			36,289

Basic net income per limited partner unit	$	3.07		$	3.06		$	2.89

Weighted average limited partner units – basic		36,548			36,425			36,289
Units contingently issuable:
Restricted units for LTIP		135			231			550
Directors’ compensation units		33			42			37
Supplemental Executive Retirement Plan		84			112			101

Weighted average limited partner units, assuming dilutive effect of restricted units		36,800			36,810			36,977

Diluted net income per limited partner unit	$	3.05		$	3.03		$	2.84

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 our partnership agreement, which are declared and paid following the close of each quarter (Note 9). During 2007 our managing general partner made a capital contribution of $1.9 million to fund certain expenses associated with our employee compensation programs. Because this contribution benefited our limited partners as they were not burdened with the employee compensation expenses funded by this capital contribution, a special allocation of certain general and administrative expenses equal to the amount of our managing general partner’s contribution was made to our managing general partner. 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 partners for the additional pro forma priority income attributable to the application of EITF No. 03-6.

12.

EMPLOYEE BENEFIT PLANS

Defined Contribution Plans—Our employees currently participate in a defined contribution profit sharing and savings plan that we sponsor. This plan covers substantially all full-time employees. Plan participants may elect to make voluntary contributions to this plan up to a specified amount of their compensation. We make matching contributions based on a percent of an employee’s eligible compensation and for certain subsidiaries, make an additional nonmatching contribution, based on an employee’s eligible compensation. Additionally, we contribute a defined percentage of eligible compensation for certain employees not covered by the defined benefit plan described below. Our expense for this plan was approximately $5.6 million, $4.6 million and $3.8 million for the years ended December 31, 2007, 2006 and 2005, respectively.

Defined Benefit Plans—Employees at certain of our mining operations participate in a defined benefit plan (the “Pension Plan”) that we sponsor. The benefit formula is a fixed dollar unit based on years of service.

The following sets forth changes in benefit obligations and plan assets for the years ended December 31, 2007 and 2006 and the funded status of the Pension Plan reconciled with the amounts reported in our consolidated financial statements at December 31, 2007 and 2006, respectively (dollars in thousands):


	2007			2006
Change in benefit obligations:
Benefit obligations at beginning of year	$	41,229		$	35,107
Service cost		3,435			3,224
Interest cost		2,267			1,949
Actuarial (gain)/loss		(6,616	)		1,466
Benefits paid		(667	)		(517	)

Benefit obligation at end of year		39,648			41,229

Change in plan assets:
Fair value of plan assets at beginning of year		35,038			27,519
Employer contribution		4,400			4,600
Actual return on plan assets		2,876			3,436
Benefits paid		(667	)		(517	)

Fair value of plan assets at end of year		41,647			35,038

Funded status at the end of year	$	1,999		$	(6,191	)

Amounts recognized in balance sheet:
Non-current asset	$	1,999		$	—
Non-current liability		—			(6,191	)

	$	1,999		$	(6,191	)

Amounts recognized in accumulated other comprehensive income consists of:
Net actuarial gain (loss)	$	109		$	(6,956	)

Weighted-average assumptions as of December 31,
Discount rate		6.65	%		5.55	%
Expected rate of return on plan assets		8.35	%		7.75	%

Weighted-average assumptions used to determine net periodic benefit cost for the year ended December 31,
Discount rate		5.55	%		5.60	%
Expected return on plan assets		7.75	%		8.00	%

Weighted-average asset allocations as of December 31,
Equity securities		71	%		87	%
Fixed income securities		24	%		12	%
Cash and cash equivalents		5	%		1	%

		100	%		100	%


	2007			2006			2005
Components of net periodic benefit cost:
Service cost	$	3,435		$	3,224		$	3,007
Interest cost		2,268			1,949			1,660
Expected return on plan assets		(2,687	)		(2,285	)		(1,916	)
Prior service cost		—			42			48
Net loss		258			313			207

Net periodic benefit cost	$	3,274		$	3,243		$	3,006


Other changes in plan assets and benefit obligation recognized in accumulated other comprehensive income	2007
Net actuarial (gain) loss	$	(6,807	)
Reversal of amortization item:
Net actuarial (gain) loss		(258	)

Total recognized in accumulated other comprehensive income		(7,065	)
Net periodic benefit cost		3,274

Total recognized in net periodic benefit cost and accumulated other comprehensive income	$	(3,791	)

Estimated future benefit payments as of December 31, 2007 are as follows (in thousands):


Year Ending December 31,
2008	$	755
2009		1,142
2010		1,360
2011		1,620
2012		1,900
2013-2017		14,746

	$	21,523

The actuarial gain component of the change in benefit obligations for 2007 and the actuarial loss in 2006 was primarily attributable to changes in the discount rate assumptions. Other than the reclassification of accrued pension benefits from current to long-term liabilities at December 31, 2006, the adoption of SFAS No. 158 in 2006 did not have a material impact on our consolidated financial statements. We expect to contribute $2.5 million to the Pension Plan in 2008. There is no estimated net actuarial (gain) loss, prior service cost, and transition obligation for the Pension Plan that will be amortized from accumulated other comprehensive income (loss) into net periodic benefit cost during the 2008 fiscal year.

As permitted under FASB No. 87, Employer’s Accounting for Pensions, the amortization of any prior service cost is determined using a straight-line amortization of the cost over the average remaining service period of employees expected to receive benefits under the Pension Plan.

The compensation committee (“Compensation Committee”) of the Board of Directors maintains a Funding and Investment Policy Statement (“Policy Statement”) for the Pension Plan. The Policy Statement provides that the assets of the Pension Plan be invested in a prudent manner based on the stated purpose of the Pension Plan and diversified among a broad range of investments including domestic equity securities and international equity securities, domestic fixed income securities and cash equivalents. The Pension Plan shall be funded by employer contributions in amounts determined in accordance with generally accepted actuarial standards.

The investment objectives as established by the Policy Statement are, first, to increase the value of the assets under the Pension Plan and, second, to control the level of risk or volatility of investment returns associated with Pension Plan investments. The investments shall be managed with the goal of ensuring that Pension Plan assets provide sufficient resources to meet or exceed benefit obligations as determined under the terms and conditions of the Pension Plan.

The Compensation Committee has selected an investment manager to implement the selection and on-going evaluation of Pension Plan investments. The investments shall be selected from the following assets classes including mutual funds, collective funds, or the direct investment in individual stocks, bonds or cash equivalent investments, including: (a) money market accounts, (b) U.S. Government bonds, (c) corporate bonds, (d) large, mid, and small capitalization stocks, and (e) international stocks. The Policy Statement imposes the following limitations, subject to exceptions authorized by the Compensation Committee under unusual market conditions: (i) the maximum investment in any one stock should not exceed 10% of the total stock portfolio, (ii) the maximum investment in any one industry should not exceed 30% of the total stock portfolio, and (iii) the average credit quality of the bond portfolio should be at least AA with a maximum amount of non-investment grade debt of 10%.

The Policy Statement’s current asset allocation guidelines are as follows:


	Percentage of Total Portfolio
	Minimum		Target		Maximum
Domestic stocks	50	%	70	%	90	%
Foreign stocks	0	%	10	%	20	%
Fixed income/cash	5	%	20	%	40	%

The expected long-term rate of return assumption is based on broad equity and bond indices. The Pension Plan’s expected long-term rate of return of 8.35% is determined by the above factors and an asset allocation assumption of 60.0% invested in domestic equity securities with an expected long-term rate of return of 10.6%, 10% invested in international equities with an expected long-term rate of return of 6.9% and 30.0% invested in fixed income securities with an expected long-term rate of return of 5.8%. The Pension Plan was established effective January 1, 1997 and our initial contribution to the Pension Plan was made in 1998.

13.

COMPENSATION PLANS

We have the LTIP for certain of our 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. The aggregate number of units reserved for issuance under the LTIP was 1,200,000. Sponsorship of the LTIP was transferred to Alliance Coal effective May 15, 2006.

During 2007, 2006 and 2005, we issued grants of 93,475 units, 90,700 units and 114,390 units, respectively, which vest on January 1, 2010, January 1, 2009 and January 1, 2008, respectively, subject to the satisfaction of certain financial tests that management currently believes will be satisfied. As of December 31, 2007, 43,385 of these outstanding LTIP grants have been forfeited. On January 29, 2008, the Compensation Committee determined that the vesting requirements for the 2005 grants of 92,730 restricted units (which is net of 21,660 forfeitures) had been satisfied as of January 1, 2008. As a result of this vesting, on February 21, 2008, we issued 62,799 common units to the LTIP participants. The remaining units were settled in cash to satisfy the individual tax obligations of the LTIP participants. On January 29, 2008, the Compensation Committee authorized additional grants up to 100,000 restricted units of which 92,100 have been issued and which will vest January 1, 2011, subject to the satisfaction of certain financial tests. After consideration of the January 1, 2008 vesting and subsequent issuance of 62,799 common units and the grants of 92,100 units on January 29, 2008, 124,161 units remain available for issuance in the future, assuming that all grants currently issued and outstanding for 2006, 2007 and 2008 are settled with common units and no future forfeitures occur.

For the years ended December 31, 2007, 2006 and 2005, our LTIP expense was $2.9 million, $4.1 million and $8.2 million, respectively. The total obligation associated with the LTIP as of December 31, 2007 and 2006 was $6.0 million and $10.5 million, respectively, and is included in partners’ capital-limited partners contained in our consolidated balance sheets.

The fair value of the 2007 and 2006 grants is based upon the intrinsic value at the date of grant which was $35.84 and $37.79, respectively on a weighted average basis. The intrinsic value of the 2005 grants of $37.20 essentially equals the fair value at January 1, 2006 and, therefore, no incremental compensation expense 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 expense 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 tax withholding requirements. As provided under the distribution equivalent rights provision of the LTIP, all non-vested grants include contingent rights to receive quarterly cash distributions in an amount equal to the cash distribution we make to unitholders during the vesting period.

A summary of non-vested LTIP grants as of and for the year ended December 31, 2007 is as follows:


Non-vested grants at January 1, 2007	395,320
Granted	93,475
Vested	(196,340	)
Forfeited	(37,275	)

Non-vested grants at December 31, 2007	255,180

As of December 31, 2007, there was $3.0 million in total unrecognized compensation expense related to the non-vested LTIP grants that are expected to vest. That expense is expected to be recognized over a weighted-average period of 1.6 years. As of December 31, 2007, the intrinsic value of the non-vested LTIP grants was $9.3 million.

We have the Supplemental Executive Retirement Plan (the “SERP”) to provide deferred compensation benefits for certain officers and key employees. All allocations made to participants under the SERP are made in the form of “phantom” units. The SERP is administered by the Compensation Committee. Sponsorship of the SERP was transferred to Alliance Coal effective May 15, 2006.

For the years ended December 31, 2007, 2006 and 2005, our SERP expense was $0.4 million, $0.1 million and $0.4 million, respectively. During 2007 we made cash distributions from the SERP totaling $1.5 million to three former executive officers that retired. The total accrued liability associated with the SERP plan was $3.1 million and $4.1 million as of December 31, 2007 and 2006, respectively and is included in other current liabilities ($1.5 million for December 31, 2006 only) and other long-term liabilities in the consolidated balance sheets.

14.

SUPPLEMENTAL CASH FLOW INFORMATION


	Year Ended December 31,
	2007		2006		2005
	(in thousands)
CASH PAID FOR:
Interest	$	13,034	$	13,760	$	15,160

Income taxes	$	2,175	$	2,400	$	3,025

NON-CASH ACTIVITY:
Accounts payable for purchase of property, plant and equipment	$	5,046	$	12,140	$	9,364

Non-cash contribution by General Partner	$	1,105	$	—	$	—

Asset acquired by capital lease	$	—	$	1,862	$	—

Market value of common units issued to Long-Term Incentive Plan participants upon vesting	$	—	$	—	$	6,988

15.

ASSET RETIREMENT OBLIGATIONS

The majority of our operations are governed by various state statutes and the Federal Surface Mining Control and Reclamation Act of 1977, which establish reclamation and mine closing standards. These regulations, among other requirements, require restoration of property in accordance with specified standards and an approved reclamation plan. We account for our asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations, which requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred. We have estimated the costs and timing of future asset retirement obligations escalated for inflation, then discounted at a risk free rate ranging from 4.22% to 6.0% and recorded the present value of those estimates.

Discounting resulted in reducing the accrual for asset retirement obligations by $65.1 million and $47.5 million at December 31, 2007 and 2006, respectively. Estimated payments of asset retirement obligations as of December 31, 2007 are as follows (in thousands):


Year Ending December 31,
2008	$	2,000
2009		1,470
2010		688
2011		2,043
2012		2,099
Thereafter		113,694

Aggregate undiscounted asset retirement obligations		121,994
Effect of discounting		(65,091	)

Total asset retirement obligations		56,903
Less: current portion		(2,000	)

Asset retirement obligations	$	54,903

The following table presents the activity affecting the asset retirement and mine closing liability (in thousands):


	Year Ended December 31,
	2007			2006			2005
Beginning balance	$	50,895		$	41,313		$	34,018
Accretion expense		2,419			2,101			1,918
Payments		(617	)		(336	)		(189	)
Allocation of liability associated with acquisition, mine development and change in assumptions		4,206			7,817			5,566

Ending balance	$	56,903		$	50,895		$	41,313

For the year ended December 31, 2007, the allocation of liability associated with acquisition, mine development and change in assumptions of $4.2 million was primarily attributable to revisions in the cost estimates for existing water treatment obligations associated with Mettiki (MD) of $2.4 million and to the expansion of permitted refuse disposal areas at Gibson County Coal and Pontiki Coal of $1.4 million and $1.7 million, respectively, as well as general increases in estimated costs of reclamation work, offset by liability decreases at certain other operations resulting from mine life extensions due to coal reserve acquisitions. For the year ended December 31, 2006, the allocation of liability associated with acquisition, mine development and change in assumptions of $7.8 million was primarily attributable to the River View acquisition of $2.9 million and new water treatment obligations and revisions in the cost estimates for existing water treatment obligations associated with Mettiki (WV) and Mettiki (MD) of $5.2 million.

16.

ACCRUED WORKERS’ COMPENSATION AND PNEUMOCONIOSIS (“BLACK LUNG”) BENEFITS

Certain of our mine operating entities are liable under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay black lung benefits to eligible employees and former employees and their dependents. In addition, we are liable for workers’ compensation benefits for traumatic injuries. Both black lung and traumatic claims are covered through self-insured programs.

Our black lung benefits liability is calculated using the service cost method that considers the calculation of the actuarial present value of the estimated black lung obligation. Our actuarial calculations are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents and interest rates. Actuarial gains or losses are amortized over the remaining service period of active miners.

We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers’ compensation laws also compensate survivors or workers who suffer employment related deaths. Our liability for traumatic injury claims is the estimated present value of current workers’ compensation benefits, based on our actuarial estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including development patterns, mortality, medical costs and interest rates. The discount rate used to calculate the estimated present value of future obligations for black lung was 6.38% and 4.80% at December 31, 2007 and 2006, respectively, and for workers’ compensation was 5.95% and 4.80% at December 31, 2007 and 2006, respectively.

The black lung and workers’ compensation expense consists of the following components for the year ended December 31, 2007, 2006 and 2005 (in thousands):


	2007		2006		2005
Black lung benefits:
Service cost	$	2,027	$	1,497	$	1,977
Interest cost		1,504		1,241		1,203
Net amortization		70		584		470

Total black lung		3,601		3,322		3,650
Workers’ compensation expense		17,192		21,242		15,406

Total expense	$	20,793	$	24,564	$	19,056

The following is a reconciliation of the changes in black lung benefit obligations at December 31, 2007 and 2006 (in thousands):


	2007			2006
Benefit obligations at beginning of year	$	26,816		$	23,795
Service cost		2,027			1,497
Interest cost		1,504			1,241
Actuarial loss		70			584
Benefits and expense paid		(370	)		(301	)

Benefit obligations at end of year	$	30,047		$	26,816

Summarized below is information about the amounts recognized in the accompanying consolidated balance sheets for black lung and workers’ compensation benefits at December 31, 2007 and 2006 (in thousands):


	2007			2006
Black lung claims	$	30,047		$	26,816
Workers’ compensation claims		51,619			45,691

Total obligations		81,666			72,507
Less current portion		(8,124	)		(7,704	)

Noncurrent obligations	$	73,542		$	64,803

Both the black lung and workers’ compensation obligations were unfunded at December 31, 2007 and 2006.

As of December 31, 2007 and 2006, we had $47.9 million and $15.3 million, respectively, in surety bonds and letters of credit outstanding to secure workers’ compensation obligations.

The U.S. Department of Labor has issued revised regulations that alter the claims process for federal black lung benefit recipients. Both the coal and insurance industries challenged certain provisions of the revised regulations through litigation, but the regulations were upheld, with some exceptions as to the retroactive application of the regulations. The revised regulations may result in an increase in the incidence and recovery of black lung claims.

17.

MINORITY INTEREST

In March 2006, 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 and to manufacture and sell rock dust. White County Coal initially invested $1.0 million in exchange for a 50% equity interest in MAC. We consolidate MAC’s financial results in accordance with FIN No. 46R, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. Based on the guidance in FIN No. 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 $0.5 million and $0.8 million as of December 31, 2007 and 2006, respectively, which is recorded as minority interest on our consolidated balance sheet.

18.

RELATED-PARTY TRANSACTIONS

The Board of Directors of our managing general partner and its Conflicts Committee review each of our related-party transactions to determine that each such transaction reflects market-clearing terms and conditions customary in the coal industry. As a result of these reviews, the Board of Directors and the Conflicts Committee approved each of the transactions described below as fair and reasonable to us and our limited partners.

Administrative Services—In connection with the closing of the AHGP IPO, ARLP entered into an administrative services agreement, (“Administrative Services Agreement”), between our managing general partner, our Intermediate Partnership, AHGP and its general partner AGP, and Alliance Resource Holdings II, Inc. (“ARH II”), the indirect parent of SGP. Under the Administrative Services Agreement, certain employees, including some executive officers, provided administrative services to our managing general partner, AHGP, AGP, ARH II and their respective affiliates. We are 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 this agreement of $0.3 million and $0.3 million for the year ended December 31, 2007 and the period from May 15, 2006 to December 31, 2006, respectively, from AHGP and $0.4 million and $0.6 million from ARH II for the years ended December 31, 2007 and 2006, respectively. Concurrently in 2006, AHGP and AGP joined as parties to our Omnibus Agreement which addresses areas of non-competition between us and ARH, ARH II, SGP and our managing general partner.

Our partnership agreement provides that our managing general partner and its affiliates be reimbursed for all direct and indirect expenses incurred or payments made on behalf of us, including, but not limited to, management’s salaries and related benefits (including incentive compensation), and accounting, budgeting, planning, treasury, public relations, land administration, environmental, permitting, payroll, benefits, disability, workers’ compensation management, legal and information technology services. Our managing general partner may determine in its sole discretion the expenses that are allocable to us. Total costs billed by our managing general partner and its affiliates to us were approximately $0.9 million, $4.2 million and $14.1 million for the years ended December 31, 2007, 2006 and 2005, respectively. The decrease from 2006 to 2007 and 2005 to 2006 was attributable to certain employees and the sponsorship of the LTIP, Short-Term Incentive Plan (“STIP”) and SERP being transferred to Alliance Coal effective May 15, 2006 in connection with the closing of AHGP’s IPO. On May 15, 2006, our executive officers became employees of record of Alliance Coal, and we no longer reimburse our managing general partner for compensation expenses associated with them. The impact of the change in plan sponsorship resulted in a reduction in the billing to us from our managing general partner directly offset by a corresponding increase in LTIP, STIP and SERP expense of our Alliance Coal subsidiary. The amounts billed to us from our managing general partner include $2.9 million and $10.6 million for the years ended December 31, 2006 and 2005, respectively, for the LTIP, STIP and SERP.

Managing General Partner Contribution—During December 2007, an affiliated entity controlled by Joseph W. Craft III, contributed 50,980 common units of AHGP valued at approximately $1.1 million at the time of contribution and $0.8 million of cash to AHGP for the purpose of funding certain expenses associated with our employee compensation programs. Upon AHGP’s receipt of this contribution it immediately contributed the same to its subsidiary MGP, our managing general partner, which in turn contributed the same to our subsidiary Alliance Coal. As provided under our partnership agreement we made a special allocation of certain general and administrative expenses equal to the amount of contribution to our managing general partner (Note 11).

SGP Land, LLC—On May 2, 2007, SGP Land, LLC (“SGP Land”), a subsidiary of our special general partner, entered into a time sharing agreement with Alliance Coal, our operating subsidiary, concerning the use of two airplanes owned by SGP Land. In accordance with the provisions of the time sharing agreement, we reimbursed SGP Land $0.3 million for the year ended December 31, 2007 for use of the airplanes.

SGP—In January 2005, we acquired Tunnel Ridge from ARH (Note 3). In connection with this acquisition, we assumed a coal lease with the SGP. Under the terms of the lease, Tunnel Ridge has paid and will continue to pay an annual minimum royalty of $3.0 million until the earlier of January 1, 2033 or the exhaustion of the mineable and merchantable leased coal. Tunnel Ridge paid advance minimum royalties of $3.0 million during each of 2007, 2006 and 2005. As of December 31, 2007, $9.0 million of advance minimum royalties paid under the lease is available for recoupment and management expects will be recouped against future production.

We previously entered into and have maintained agreements with two banks to provide letters of credit in an aggregate amount of $31.0 million (Note 8). At December 31, 2007, we had $30.6 million in outstanding letters of credit under these agreements. The SGP guarantees $5.0 million of these outstanding letters of credit. Historically, the Partnership has compensated the SGP for a guarantee fee equal to 0.30% per annum of the face amount of the letters of credit outstanding. During 2003 the SGP agreed to waive the guarantee fee in exchange for a parent guarantee from the Intermediate Partnership and Alliance Coal on the mineral leases and subleases with Webster County Coal and Warrior described above. Since the guarantee is made on behalf of entities within the consolidated partnership, the guarantee has no fair value under FIN No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantees of Indebtedness of Others, and does not impact our consolidated financial statements.

ARH—In April 2006, we acquired 100% of the membership interest in River View from ARH (Note 3).

19.

COMMITMENTS AND CONTINGENCIES

Commitments—We lease buildings and equipment under operating lease agreements that provide for the payment of both minimum and contingent rentals. We also have a noncancelable lease with SGP (Note 18) and a noncancelable lease for equipment under a capital lease obligation. Future minimum lease payments are as follows (in thousands):


Year Ending December 31,	Capital Lease			Other Operating Leases
Year Ending December 31,	Capital Lease			Affiliate		Others		Total
2008	$	460		$	2,835	$	1,412	$	4,247
2009		412			2,595		1,173		3,768
2010		364			2,595		1,104		3,699
2011		315			216		615		831
2012		111			—		307		307
Thereafter		63			—		—		—

Total future minimum lease payments	$	1,725		$	8,241	$	4,611	$	12,852

Less: amount representing interest		(213	)

Present value of future minimum lease payments		1,512
Less: current portion		(377	)

Long-term capital lease obligation	$	1,135

Rental expense (including rental expense incurred under operating lease agreements) was $5.4 million, $5.8 million and $6.4 million for the years ended December 31, 2007, 2006 and 2005, respectively.

Our subsidiary, Mettiki (WV), entered into a capital lease agreement with Joy Technologies Inc., d/b/a Joy Mining Machinery, a Delaware corporation, on May 22, 2006, with an in-service date of November 20, 2006. The lease is a 5-year noncancelable lease with monthly rental payments of $40,390 and has one renewal period for 2 years with monthly rental payments of $22,140. The effective interest rate on the capital lease is 6.195%.

Contractual Commitments—In connection with planned capital projects, we have contractual commitments of approximately $13.7 million at December 31, 2007. As of December 31, 2007, we had commitments to purchase, from external production sources, coal at an estimated cost up to $6.7 million in 2008.

General Litigation—Various lawsuits, claims and regulatory proceedings incidental to our business are pending against the ARLP Partnership. We record an accrual for a potential loss related to these matters when, in management’s opinion, such loss is probable and reasonably estimable. Based on known facts and circumstances, we believe the ultimate outcome of these outstanding lawsuits, claims and regulatory proceedings will not have a material adverse effect on our financial condition, results of operations or liquidity. However, if the results of these matters were different from management’s current opinion and in amounts greater than our accruals, then they could have a material adverse effect.

Other –During September 2007, we completed our annual property and casualty insurance renewal with various insurance coverages effective as of October 1, 2007. Available capacity for underwriting property insurance continues to be limited as a result of insurance carrier losses in the mining industry. 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 of $20.0 million in excess of the $30.0 million primary layer. We do not participate in the third layer of $25.0 million in excess of $50.0 million. The 14.7% participation rate for this year’s renewal is consistent with our prior year participation. 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 60-day waiting period for business interruption and an additional $5.0 million aggregate deductible. 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.

In March 2004, XL Specialty Insurance Company (“XL”) filed a lawsuit in state district court in Oklahoma alleging that we and ARH had failed to pay premiums for several surety bonds issued for us by XL. At trial in July 2006, XL sought approximately $0.9 million in damages and interest, and the district court ruled against us. In November 2007, while our appeal to the Oklahoma Supreme Court was pending, we reached a settlement with XL consistent with our previously recorded accruals.

In November 2005, we settled a contract dispute with ICG, LLC (“ICG”). Under this settlement, which was effective August 1, 2005, Pontiki Coal, one of our subsidiaries, shipped coal in approximately ratable monthly quantities until the remaining obligation of 1,681,303 tons under a coal supply agreement with ICG was complete. This shipment obligation was completed in April 2007. As part of this settlement, we also executed a new coal sales agreement with ICG whereby Alliance Coal agreed to purchase approximately 887,000 tons of coal from ICG. Approximately 236,000, 588,000 and 63,000 tons were purchased and sold at a profit during the years ended December 31, 2007, 2006 and 2005, respectively. Consequently, we have fully satisfied our coal sales agreement with ICG.

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.

20.

CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

We have significant long-term coal supply agreements, some of which contain prospective price adjustment provisions designed to reflect changes in market conditions, labor and other production costs and, in the infrequent circumstance when the coal is sold other than free on board the mine, changes in transportation rates. Total revenues from major customers, including transportation revenues, which exceed ten percent of total revenues, are as follows (in thousands):


	Segment (Note 21)	Year Ended December 31,
	Segment (Note 21)	2007		2006		2005
Customer A	Illinois Basin	$	144,063	$	143,795	$	133,672
Customer B	Northern Appalachia		132,229		75,718		83,255
Customer C	Illinois Basin		115,796		74,413		76,959

Trade accounts receivable from these customers totaled approximately $26.5 million and $32.1 million at December 31, 2007 and 2006, respectively. Our bad debt experience has historically been insignificant. Financial conditions of our customers could result in a material change to our bad debt expense in future periods. The coal supply agreements with Customers A and B expired in 2007 and have been replaced with various new contracts with expiration dates ranging from 2010 to 2023. The coal supply agreement with Customer C expires in 2016.

21.

SEGMENT INFORMATION

We operate in the eastern United States as a producer and marketer of coal to major utilities and industrial users. We have four reportable segments: the Illinois Basin, Central Appalachia, Northern Appalachia and Other and Corporate. The first three segments correspond to the three major coal producing regions in the eastern United States. Coal quality, coal seam height, mining and transportation methods and regulatory issues are similar within each of these three segments.

The Illinois Basin segment is comprised of Webster County Coal’s Dotiki mine, Gibson County Coal’s Gibson North mine and Gibson South property, Hopkins County Coal’s Elk Creek mine, White County Coal’s Pattiki mine, Warrior Coal’s Cardinal mine, the River View property and Alliance Resource Properties (Note 3). In 2007, mine development began at the River View property. We are in the process of permitting the Gibson South property for future mine development.

The Central Appalachian segment is comprised of Pontiki Coal’s Pond Creek and Van Lear mines, and MC Mining’s Excel No. 3 mine.

The Northern Appalachian segment is comprised of Mettiki Coal’s D-Mine and Mettiki Coal (WV)’s Mountain View mine, two small mining operations that we sub-contract operations to third-parties, and the Tunnel Ridge and Penn Ridge coal properties. In late 2006, we completed the transition of longwall operations from the D-Mine to the Mountain View mine. We are in the process of permitting the Tunnel Ridge and Penn Ridge properties for future mine development.

Other and Corporate includes marketing and administrative expenses, the Mt. Vernon dock activities, coal brokerage activity, MAC and Matrix Design. Operating segment results for the years ended December 31, 2007, 2006 and 2005 are presented below.


	Illinois Basin		Central Appalachia		Northern Appalachia		Other and Corporate			Elimination (1)			Consolidated
	(in thousands)
Operating segment results for the year ended December 31, 2007 were as follows:

Total revenues (2)	$	662,643	$	194,635	$	163,351	$	17,507		$	(4,802	)	$	1,033,334
Selected production expenses (3)		364,471		128,075		97,660		18,706			(4,802	)		604,110
Segment Adjusted EBITDA (4)		208,658		58,937		35,478		(1,605	)		—			301,468
Total assets		450,047		105,826		128,557		17,366			(73	)		701,723
Capital expenditures (5)		87,118		13,313		16,024		3,135			—			119,590

Operating segment results for the year ended December 31, 2006 were as follows:

Total revenues (2)	$	634,602	$	185,966	$	121,962	$	27,293		$	(2,266	)	$	967,557
Selected production expenses (3)		344,267		124,083		67,353		20,763			(2,266	)		554,200
Segment Adjusted EBITDA (4)		206,209		40,050		29,911		5,475			—			281,645
Total assets		354,320		101,775		121,620		57,247			—			634,962
Capital expenditures		112,365		22,579		43,035		10,651			—			188,630

Operating segment results for the year ended December 31, 2005 were as follows:

Total revenues (2)	$	553,908	$	157,203	$	120,423	$	7,184		$	—		$	838,718
Selected production expenses (3)		289,720		94,909		62,425		3,606			—			450,660
Segment Adjusted EBITDA (4)		183,075		41,583		36,047		2,924			—			263,629
Total assets		274,437		91,853		73,789		92,608			—			532,687
Capital expenditures		70,353		23,451		24,435		1,642			—			119,881

(1)	The elimination column represents the elimination of intercompany transactions and is primarily comprised of sales from MAC and Matrix Design.

(2)	Revenues included in the Other and Corporate column are attributable to Mt. Vernon transloading revenues, brokerage coal sales, Matrix Design and MAC rock dust revenues.

(3)

Selected production expenses are comprised of operating expenses and outside purchases (as reflected in our consolidated statements of income), excluding production taxes and royalties that are incurred as a percentage of coal sales or volumes. Selected production expenses are reconciled to operating expenses and outside purchases below (in thousands).


	Year Ended December 31,
	2007		2006		2005
Selected production expenses	$	604,110	$	554,200	$	450,660
Production taxes and royalties		102,944		92,769		85,941

Combined operating expenses and outside purchases	$	707,054	$	646,969	$	536,601

(4)

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


	Year Ended December 31,
	2007			2006			2005
Consolidated Segment Adjusted EBITDA	$	301,468		$	281,645		$	263,629
General and administrative		(34,479	)		(30,884	)		(33,484	)
Depreciation, depletion and amortization		(85,310	)		(66,489	)		(55,637	)
Interest expense, net		(9,952	)		(9,175	)		(11,816	)
Income taxes		(1,669	)		(2,443	)		(2,682	)
Cumulative effect of accounting change		—			112			—
Minority interest		332			161			—

Net income	$	170,390		$	172,927		$	160,010

(5)	Capital expenditures do not include acquisitions of coal reserves and other assets in the Illinois Basin of $53.3 million or business acquisitions separately reported in our consolidated statements of cash flows.

22.

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

A summary of our quarterly operating results for 2007 and 2006 is as follows (in thousands, except unit and per unit data):


	Quarter Ended
	March 31, 2007		June 30, 2007		September 30, 2007		December 31, 2007
Revenues	$	257,071	$	263,309	$	260,526	$	252,428
Income from operations		47,415		48,928		41,815		42,136
Income before income taxes, cumulative effect of accounting change and minority interest		46,032		46,822		39,172		39,701
Net income		45,540		46,237		38,685		39,928

Basic net income per limited partner unit	$	0.79	$	0.80	$	0.70	$	0.77
Diluted net income per limited partner unit	$	0.79	$	0.80	$	0.70	$	0.76

Weighted average number of units outstanding – basic		36,540,485		36,550,659		36,550,659		36,550,659
Weighted average number of units outstanding – diluted		36,765,573		36,794,912		36,801,186		36,825,948


	Quarter Ended
	March 31, 2006		June 30, 2006		September 30, 2006		December 31, 2006
Revenues	$	238,320	$	221,304	$	244,740	$	263,193
Income from operations		50,870		43,387		40,881		48,198
Income before income taxes, cumulative effect of accounting change and minority interest		48,896		41,054		38,939		46,208
Net income		48,249		40,550		38,640		45,488

Basic net income per limited partner unit	$	0.83	$	0.73	$	0.70	$	0.80
Diluted net income per limited partner unit	$	0.83	$	0.72	$	0.69	$	0.79

Weighted average number of units outstanding – basic		36,426,306		36,426,306		36,426,306		36,422,515
Weighted average number of units outstanding – diluted		36,765,016		36,797,407		36,824,613		36,852,765

Income from operations in the above table, for quarters prior to June 30, 2006, represents income from operations before interest expense.

23.

SUBSEQUENT EVENTS

Other than those events described in Notes 9, 13, and 18, there were no other subsequent events.

SCHEDULE II

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

Balance At
Beginning
of Year

Additions
Charged to
Income

Deductions

Balance At
End of Year

(in thousands)

2007

Allowance for doubtful accounts

—

2006

Allowance for doubtful accounts

—

2005

Allowance for doubtful accounts

—

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANT ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures. We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the U.S. Securities and Exchange Commission (“SEC”), is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosures. 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 the report. This evaluation was performed by our management, with the participation of our Chief Executive Officer and Chief Financial Officer. Based on this evaluation of our disclosure controls and procedures as of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective.

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls or our internal controls over financial reporting (“Internal Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the ARLP Partnership have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that simple errors or mistakes can occur. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based, in part, upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our disclosure controls and internal controls and make modifications as necessary; our intent in this regard is that the disclosure controls and the internal controls will be maintained as systems change and conditions warrant.

Management’s Annual Report on Internal Control over Financial Reporting. Management of the ARLP Partnership is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. The ARLP Partnership’s internal control over financial reporting is designed to provide reasonable assurance to our management and Board of Directors of our managing general partner regarding the preparation and fair presentation of published financial statements. Our controls are designed to provide reasonable assurance that the ARLP Partnership’s assets are protected from unauthorized use and that transactions are executed in accordance with established authorizations and properly recorded. The internal controls are supported by written policies and are complemented by a staff of competent business process owners and an internal auditor supported by competent and qualified external resources used to assist in testing the operating effectiveness of the ARLP Partnership’s internal control over financial reporting. Management concluded that the design and operations of our internal controls over financial reporting at December 31, 2007 are effective and provide reasonable assurance the books and records accurately reflect the transactions of the ARLP Partnership.

Because of our inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control – Integrated Framework. Based on our assessment, Management concluded that, as of December 31, 2007, the ARLP Partnership’s internal control over financial reporting is effective based on those criteria, and we believe that we have no material internal control weaknesses in our financial reporting process.

Changes in Internal Controls Over Financial Reporting. There has been no change in our internal controls over financial reporting (as defined in Rule 13a-15(f) or Rule 15d-15(f) that occurred in the three months ended December 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of the Managing

General Partner and the Partners of

Alliance Resource Partners, L.P.:

We have audited the internal control over financial reporting of Alliance Resource Partners, L.P. and subsidiaries (the “Partnership”) as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets as of December 31, 2007 and 2006 and the related consolidated statements of income, cash flows and Partners’ capital (deficit) and comprehensive income (loss) for each of the three years in the period ended December 31, 2007, and financial statement schedule as of and for the year ended December 31, 2007 of the Partnership and our report dated February 29, 2008 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ Deloitte & Touche, LLP

Tulsa, Oklahoma

February 29, 2008

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE MANAGING GENERAL PARTNER

As is commonly the case with publicly-traded limited partnerships, we are managed and operated by our managing general partner. The following table shows information for current and certain former executive officers and members of the Board of Directors of our managing general partner. Executive officers and directors are elected until death, resignation, retirement, disqualification, or removal.


Name	Age	Position With Our Managing General Partner
Joseph W. Craft III	57	President, Chief Executive Officer and Director

Brian L. Cantrell	48	Senior Vice President and Chief Financial Officer

R. Eberley Davis ¹	50	Senior Vice President, General Counsel and Secretary

Robert G. Sachse ²	59	Executive Vice President – Marketing

Charles R. Wesley	53	Senior Vice President – Operations

Thomas M. Wynne	51	Vice President – Operations

Merribel S. Ayres	56	Director and Member of the Compensation Committee

Michael J. Hall	63	Director and Member of the Audit* Committee

John P. Neafsey ³	68	Chairman of the Board and Member of Audit, Compensation and Conflicts* Committees

John H. Robinson ⁴	57	Director and Member of Audit and Compensation* Committees

Wilson M. Torrence	66	Director and Member of the Conflicts Committee

John J. MacWilliams ⁵	52	Director

Preston R. Miller, Jr. ⁶	59	Director and Member of the Compensation Committee

*	Indicates Chairman of Committee

¹	Effective February 12, 2007, Mr. Davis was appointed as Senior Vice President, General Counsel and Secretary of our managing general partner by the Board of Directors of our managing general partner.

²	Effective November 1, 2006, Mr. Sachse assumed responsibilities for our coal marketing, sales and transportation functions. Effective January 5, 2007, Mr. Sachse retired from the Board of Directors of our managing general partner.

³	Effective January 5, 2007, Mr. Neafsey was elected chairman of the Conflicts Committee.

⁴	Effective January 5, 2007, Mr. Robinson was elected chairman of the Compensation Committee and resigned from his positions as chairman and a member of the Conflicts Committee.

⁵	Effective January 5, 2007, Mr. MacWilliams retired from the Board of Directors of our managing general partner.

⁶	Effective January 5, 2007, Mr. Miller retired from the Board of Directors of our managing general partner. Prior to his retirement from the Board of Directors, Mr. Miller served as chairman of the Compensation Committee.

Joseph W. Craft III has been President, Chief Executive Officer and a Director since August 1999 and has indirect majority ownership of our managing general partner. Mr. Craft also serves as President, Chief Executive Officer and a

Director of AHGP. Previously Mr. Craft served as President of MAPCO Coal Inc. since 1986. During that period, he also was Senior Vice President of MAPCO Inc. and had been previously that company’s General Counsel and Chief Financial Officer. Before joining MAPCO, Mr. Craft was an attorney at Falcon Coal Corporation and Diamond Shamrock Coal Corporation. He is past Chairman of the National Coal Council, a Board and Executive Committee Member of the National Mining Association, a Director of the Center for Energy and Economic Development, a Director of BOK Financial Corporation and a member of the Board of Trustees for the University of Tulsa. Mr. Craft holds a Bachelor of Science degree in Accounting and a Juris Doctorate degree from the University of Kentucky. Mr. Craft also is a graduate of the Senior Executive Program of the Alfred P. Sloan School of Management at Massachusetts Institute of Technology.

Brian L. Cantrell was named Senior Vice President and Chief Financial Officer in October 2003. Mr. Cantrell also serves as Senior Vice President and Chief Financial Officer of AHGP. Prior to his current position, Mr. Cantrell was President of AFN Communications, LLC from November 2001 to October 2003 where he had previously served as Executive Vice President and Chief Financial Officer after joining AFN in September 2000. Mr. Cantrell’s previous positions include Chief Financial Officer, Treasurer and Director with Brighton Energy, LLC from August 1997 to September 2000; Vice President – Finance of KCS Medallion Resources, Inc.; and Vice President – Finance, Secretary and Treasurer of Intercoast Oil and Gas Company. Mr. Cantrell is a Certified Public Accountant and holds a Masters of Accountancy and Bachelor of Accountancy from the University of Oklahoma.

R. Eberley Davis has been our Senior Vice President, General Counsel and Secretary since February 2007. Mr. Davis also serves as Senior Vice President, General Counsel and Secretary of AHGP. Mr. Davis has over 24 years experience in the coal and energy industries. From 2003 to February 2007, Mr. Davis practiced law in the Lexington, Kentucky office of Stoll Keenon Ogden PLLC. Prior to joining Stoll Keenon Ogden, Mr. Davis was Vice President, General Counsel and Secretary of Massey Energy Company for one year. Mr. Davis also served in various positions, including Vice President and General Counsel, for Lodestar Energy, Inc. from 1993 to 2002. Mr. Davis is an alumnus of the University of Kentucky, where he received a Bachelor of Arts degree in Economics and his Juris Doctorate degree. He also holds an Masters of Business Administration degree from the University of Kentucky. Mr. Davis is a Trustee of the Energy and Mineral Law Foundation, and a member of the American, Kentucky and Fayette County Bar Associations.

Robert G. Sachse has been Executive Vice President since August 2000. Effective November 1, 2006, Mr. Sachse assumed the responsibilities for our coal marketing, sales and transportation functions. Mr. Sachse was also Vice Chairman of our managing general partner from August 2000 to January 2007. Prior to his current position, Mr. Sachse was Executive Vice President and Chief Operating Officer of MAPCO Inc. from 1996 to 1998 when MAPCO merged with The Williams Companies. Following the merger, Mr. Sachse had a two year non-compete consulting agreement with The Williams Companies. Mr. Sachse held various positions while with MAPCO Coal Inc. from 1982 to 1991, and was promoted to President of MAPCO Natural Gas Liquids in 1992. Mr. Sachse holds a Bachelor of Science degree in Business Administration from Trinity University and a Juris Doctorate degree from the University of Tulsa.

Charles R. Wesley has been Senior Vice President – Operations since August 1996. He joined the company in 1974 when he began working for Webster County Coal Corporation as an engineering co-op student. In 1992, Mr. Wesley was named Vice President – Operations for Mettiki Coal Corporation. He has served the industry as past President of the West Kentucky Mining Institute and National Mine Rescue Association Post 11, and he has served on the Board of the Kentucky Mining Institute. Mr. Wesley holds a Bachelor of Science degree in Mining Engineering from the University of Kentucky.

Thomas M. Wynne has been Vice President-Operations since July 1998. He joined the company in 1981 and has held various positions. Mr. Wynne holds a Bachelor of Science degree in Mining Engineering from the University of Pittsburgh and a Masters of Business Administration degree from West Virginia University.

Merribel S. Ayres became a Director in January 2007. Ms. Ayres is President of Lighthouse Consulting Group, a privately held firm that provides government affairs and communication expertise, as well as management consulting and business development services, focusing primarily on energy and environmental policy. From 1988 to 1996, Ms. Ayres served as Chief Executive Officer of the National Independent Energy Producers, a Washington, DC, trade association representing the competitive power supply industry. Ms. Ayres is a member of the Aspen Institute Energy Policy Forum and the Deans’ Alumni Leadership Counsel of Harvard University’s Kennedy School of Government. Ms. Ayres holds a Bachelor of Arts in English Literature from Bryn Mawr College, a post-graduate degree from Trinity College in Dublin, Ireland, and received advanced leadership training at Harvard University’s Kennedy School of Government. In addition, Ms. Ayres is a Director of the United States Energy Association (“USEA”), and serves on the Board of

Directors of CMS Energy Corporation (NYSE:CMS), a Michigan-based company that has as its primary business operations an electric and natural gas utility, natural gas pipeline systems, and independent power generation. Ms. Ayres is a member of the Compensation Committee.

Michael J. Hall became a Director in March 2003. Mr. Hall is Chairman of the Board of Directors of Matrix Service Company (“Matrix”). Previously, Mr. Hall served as President and Chief Executive Officer of Matrix from March, 2005 until he retired in November, 2006. Mr. Hall also served as Vice President – Finance and Chief Financial Officer, Secretary and Treasurer of Matrix from September, 1998 to May, 2004. Mr. Hall became a director of Matrix in October 1998, and was elected chairman of its board in November, 2006. Matrix is a company which provides general industrial construction and repair and maintenance services principally to the petroleum, petrochemical, power, bulk storage terminal, pipeline and industrial gas industries. Prior to working for Matrix, Mr. Hall was Vice President and Chief Financial Officer of Pexco Holdings, Inc., Vice President – Finance and Chief Financial Officer for Worldwide Sports & Recreation, Inc. an affiliated company of Pexco, and worked for T.D. Williamson, Inc., as Senior Vice President, Chief Financial and Administrative Officer, and Director of Operations – Europe, Africa and Middle East Region. Mr. Hall is Chairman of the Board of Directors of Integrated Electrical Services, Inc. and a member of its audit, human resources and compensation, and nominating/governance committees and has served as a director and chairman of the board since May 2006. He also serves as Chairman of the Board of Directors of American Performance Funds and is a member of its audit and nominating committees and has served as an independent trustee since July 1990. Mr. Hall holds a Bachelor of Science degree in Accounting from Boston College and a Masters of Business Administration from Stanford University. Mr. Hall is chairman of the Audit Committee of the Board of Directors. Since March, 2006, Mr. Hall has also been a Director and chairman of the audit committee of AHGP.

John P. Neafsey has served as Chairman of the Board of Directors since June 1996. Mr. Neafsey is President of JN Associates, an investment consulting firm formed in 1993. Mr. Neafsey served as President and CEO of Greenwich Capital Markets from 1990 to 1993 and a Director since its founding in 1983. Positions that Mr. Neafsey held during a 23-year career at The Sun Company include Director; Executive Vice President responsible for Canadian operations, Sun Coal Company and Helios Capital Corporation; Chief Financial Officer; and other executive positions with numerous subsidiary companies. He is or has been active in a number of organizations, including the following: Director and Chairman of the audit committee for The West Pharmaceutical Services Company and Chairman and a member of the audit committee of Constar, Inc., Trustee Emeritus and Presidential Counselor, Cornell University, and Overseer of Cornell-Weill Medical Center. Mr. Neafsey holds Bachelor and Masters of Science degrees in Engineering and a Masters of Business Administration degree from Cornell University. Mr. Neafsey is chairman of the Conflicts Committee and a member of the Audit and Compensation Committees.

John H. Robinson became a Director in December 1999. Mr. Robinson is Chairman of Hamilton Ventures, LLC. From 2003 to 2004, he was Chairman of EPC Global, Ltd., an engineering staffing company. From 2000 to 2002, he was Executive Director of Amey plc, a British business process outsourcing company. Mr. Robinson served as Vice Chairman of Black & Veatch, Inc. from 1998 to 2000. He began his career at Black & Veatch in 1973 and was a General Partner and Managing Partner prior to becoming Vice Chairman when the firm incorporated. Mr. Robinson is a Director of Coeur d’Alene Mining Corporation and a member of its audit and compensation committees. He is also a Director of the Federal Home Loan Bank of Des Moines and a member of its risk management, business operations and housing, and human resources and compensation committees. Mr. Robinson is also a Director of Comark Building Systems, Inc. and Olsson Associates. Mr. Robinson holds Bachelor and Masters of Science degrees in Engineering from the University of Kansas and is a graduate of the Owner-President-Management Program at the Harvard Business School. He is chairman of the Compensation Committee and a member of the Audit Committee.

Wilson M. Torrence became a Director in January 2007. Mr. Torrence retired from Fluor Corporation in 2006 as a Senior Vice President of Project Development and Investments and is currently performing investment and business consulting services for clients in various energy related businesses. Mr. Torrence was employed at Fluor from 1989 to 2006 where, among other roles, he was responsible for the global Project Development, Investment and Structured Finance Group and served as Chairman of Fluor’s Investment Committee. In that position, Mr. Torrence had executive responsibility for Fluor’s global activities in developing and arranging third-party financing for some of Fluor’s clients’ construction projects. Prior to joining Fluor in 1989, Mr. Torrence was President and CEO of Combustion Engineering Corporation’s Waste to Energy Division and, during that time, also served as Chairman of the Institute of Resource Recovery, a Washington-based industry advocacy organization. Mr. Torrence began his career at Mobil Oil Corporation, where he held several executive positions, including Assistant Treasurer of Mobil’s International Marketing and Refining Division and Chief Financial Officer of Mobil Land Development Company. More recently, from October 2006 to March 2007, Mr. Torrence served as Chief Financial Officer and as a Director of Cleantech America, LLC, a

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private company involved in development of central station solar generating plants. Mr. Torrence holds Bachelor and Masters degrees in Business Administration from Virginia Tech University. Mr. Torrence is a member of the Conflicts Committee.

John J. MacWilliams retired from the Board of Directors of our managing general partner in January 2007. Mr. MacWilliams is a Partner of The Tremont Group, LLC, a private equity investment firm founded in January 2003, located in Newton, MA, which has a specialized expertise in the energy industry. Mr. MacWilliams is also a General Partner of The Beacon Group, LP, which he joined in 1993, and has served as a Director since June 1996. As part of The Beacon Group, he co-manages two private equity funds focusing on the energy industry. Mr. MacWilliams’ previous positions include serving as a General Partner of JP Morgan Partners, Executive Director of Goldman Sachs International in London, Vice President for Goldman Sachs & Co.’s Investment Banking Division in New York, and as an attorney at Davis Polk & Wardwell in New York. He also is a Director of Compagnie Generale de Geophysique. Mr. MacWilliams holds a Bachelor of Arts degree from Stanford University, Masters of Science degree from Massachusetts Institute of Technology, and a Juris Doctorate degree from Harvard Law School.

Preston R. Miller, Jr. retired from the Board of Directors of our managing general partner in January 2007. Mr. Miller is a Partner of The Tremont Group, LLC, a private equity investment firm founded in January 2003, located in Newton, MA, which has a specialized expertise in the energy industry. Mr. Miller is a General Partner of The Beacon Group, LP, which he joined in 1993 and has served as a Director since June 1996. As a part of The Beacon Group, he co-manages a private equity fund focusing on the energy industry. Mr. Miller’s previous positions include serving as a General Partner of JP Morgan Partners from June 2000 through December 2002, and was with Goldman Sachs & Co from January 1979 through January 1993, most recently as Vice President in the Structured Finance Group in New York City, where he had global responsibility for coverage of the independent power industry, asset-backed power generation, and oil and gas financing. He also has a background in credit analysis, and was head of a revenue bond rating group at Standard & Poor’s Corp. Mr. Miller holds a Bachelor of Arts degree from Yale University and a Masters of Public Administration degree from Harvard University.

Audit Committee

The Audit Committee is comprised of three non-employee members of the Board of Directors (currently, Mr. Hall, Mr. Neafsey and Mr. Robinson). After reviewing the qualifications of the current members of the Audit Committee, and any relationships they may have with us that might affect their independence, the Board of Directors has determined that all current Audit Committee members are “independent” as that concept is defined in Section 10A of the Exchange Act, all current Audit Committee members are “independent” as that concept is defined in the applicable rules of NASDAQ Stock Market, LLC, all current Audit Committee members are financially literate, and Mr. Hall and Mr. Neafsey qualify as Audit Committee financial experts under the applicable rules promulgated pursuant to the Exchange Act.

Report of the Audit Committee

The Audit Committee of MGP oversees our financial reporting process on behalf of the Board of Directors. Management has primary responsibility for the financial statements and the reporting process including the systems of internal controls. The Audit Committee has responsibility for the appointment, compensation and oversight of the work of our independent registered public accounting firm and assists the Board of Directors by conducting its own review of our:

•

filings with the Securities and Exchange Commission (the “SEC”) pursuant to the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”) (i.e., Forms 10-K, 10-Q, and 8-K);

•

press releases and other communications by us to the public concerning earnings, financial condition and results of operations, including changes in distribution policies or practices affecting the holders of our units;

•

systems of internal controls regarding finance and accounting that management and the Board of Directors have established; and

•

auditing, accounting and financial reporting processes generally.

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In fulfilling its oversight and other responsibilities, the Audit Committee met eight times during 2007. The Audit Committee’s activities included, but were not limited to, (a) the selection of the independent registered public accounting firm, (b) meeting periodically in executive session with the independent registered public accounting firm, (c) the review of the Quarterly Reports on Form 10-Q for the three months ended March 31, June 30, and September 30, 2007, (d) performing a self-assessment of the committee itself, (e) reviewing the Audit Committee charter, and (f) reviewing the overall scope, plans and findings of our internal auditor. Based on the results of the annual self-assessment, the Audit Committee believes that it satisfied the requirements of its charter. The Audit Committee also reviewed and discussed with management and the independent registered public accounting firm this Annual Report on Form 10-K, including the audited financial statements.

Our independent registered public accounting firm, Deloitte & Touche LLP, is responsible for expressing an opinion on the conformity of the audited financial statements with generally accepted accounting principles. The Audit Committee reviewed with Deloitte & Touche LLP its judgment as to the quality, not just the acceptability, of our accounting principles and such other matters as are required to be discussed with the Audit Committee under generally accepted auditing standards.

The Audit Committee discussed with Deloitte & Touche LLP the matters required to be discussed by SAS 114, The Auditor’s Communication with Those Charged with Governance, as may be modified or supplemented. The committee received written disclosures and the letter from Deloitte & Touche LLP required by Independence Standards Board No. 1., Independence Discussions with Audit Committees, as may be modified or supplemented, and has discussed with Deloitte & Touche LLP, its independence from management and the ARLP Partnership.

Based on the reviews and discussions referred to above, the Audit Committee recommended to the Board of Directors that the audited financial statements be included in the Annual Report on Form 10-K for the year ended December 31, 2007 for filing with the SEC.

Members of the Audit Committee:

Michael J. Hall, Chairman

John P. Neafsey

John H. Robinson

Code of Ethics

We have adopted a Code of Ethics with which our chief executive officer and our senior financial officers (including our principal financial officer, and our principal accounting officer or controller), are expected to comply. The Code of Ethics is publicly available on our website under Investor Information at www.arlp.com and is available in print to any unitholder who requests it. Such requests should be directed to Investor Relations at (918) 295-7674. If any substantive amendments are made to the Code of Ethics or if there is a grant of a waiver, including any implicit waiver, from a provision of the code to our chief executive officer, chief financial officer, chief accounting officer or controller, we will disclose the nature of such amendment or waiver on our website or in a report on Form 8-K.

Communications with the Board

Unitholders or other interested parties can contact any director or committee of the board by writing to them c/o Senior Vice President, General Counsel and Secretary, P. O. Box 22027, Tulsa, Oklahoma 74121-2027. Comments or complaints relating to our accounting, internal accounting controls or auditing matters will also be referred to members of the Audit Committee. The Audit Committee has procedures for (a) receipt, retention and treatment of complaints received by us regarding accounting, internal accounting controls, or auditing matters and (b) the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities and Exchange Act of 1934, as amended, requires directors, executive officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC initial reports of ownership and reports or changes in ownership of such equity securities. Such persons are also required to furnish us with copies of all Section 16(a) forms they file. Based solely upon a review of the copies of the forms furnished to us, or written representations from certain reporting persons, we believe that during 2007 none of our

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officers and directors were delinquent with respect to any of the filing requirements under Rule 16(a) other than Mr. Robert G. Sachse who did not timely file a Form 4 related to his gift of 600 units in May, but has since filed a Form 4 with respect to this transaction.

Reimbursement of Expenses of our Managing General Partner and its Affiliates

Our managing general partner does not receive any management fee or other compensation in connection with its management of us. Prior to May 15, 2006, substantially all of our executive officers were employees of record of our managing general partner. During that time, our managing general partner was reimbursed by us for all expenses incurred on our behalf, including the costs of employee, officer and director compensation and benefits properly allocable to us, as well as all other expenses necessary or appropriate to the conduct of our business, and properly allocable to us. Please see “Item 13. – Certain Relationships and Related Transactions, and Director Independence – Administrative Services.”

ITEM 11.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Introduction

The compensation of the executive officers of our managing general partner, MGP (who are employees of our operating subsidiary, Alliance Coal), is set by the Compensation Committee of the Board of Directors. Some of the executive officers of MGP devote a portion of their time to the business of one or more related parties and, to the extent they do so, the base salary of those executive officers is reimbursed to Alliance Coal by those related parties pursuant to an administrative services agreement. Please see “Item 13. – Certain Relationships and Related Transactions, and Director Independence – Administrative Services.”

Compensation Objectives and Philosophy

The compensation program of our managing general partner is designed to achieve two key objectives: (i) provide a competitive compensation opportunity to allow us to recruit and retain key management talent, and (ii) motivate and reward executive officers for creating sustainable, capital-efficient growth in distributable cash flow to maximize our distributions to our unitholders. In making decisions regarding executive compensation, the Compensation Committee compares current compensation levels with those of other companies in the coal industry that compare favorably to us with regard to financial and operating indicators by which we have historically measured our performance. The Compensation Committee uses its discretion to determine a total compensation package of base salary and short-term and long-term incentives that is competitive with this peer group. Based upon its review of our overall executive compensation program, the Compensation Committee believes the executive compensation program is appropriately applied to our managing general partner’s executive officers and is necessary to attract and retain the executive officers who are essential to our continued development and success, to compensate those executive officers for their contributions and to enhance unitholder value. Moreover, the Compensation Committee believes the total compensation opportunities provided to our managing general partner’s executive officers create alignment with our long-term interests and those of our unitholders.

Setting Executive Compensation

Role of the Compensation Committee

The Compensation Committee administers our managing general partner’s executive compensation program. The Compensation Committee oversees our compensation and benefit plans and policies, administers our incentive bonus and equity participation plans, and reviews and approves annually all compensation decisions relating to our executive officers, including (i) the President and Chief Executive Officer, our principal executive officer, (ii) the Senior Vice President and Chief Financial Officer, our principal financial officer, and (iii) the three most highly compensated executive officers for 2007, each of whom is named in the Summary Compensation Table (collectively, the “Named Executive Officers”). The Compensation Committee is empowered by the Board of Directors and by the Compensation Committee’s charter to make all decisions regarding compensation for the Named Executive Officers without ratification or other action by the Board of Directors.

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The Compensation Committee is composed of three directors who have been determined to be “independent” by the Board of Directors in accordance with applicable NASDAQ Stock Market, LLC and SEC regulations. The Compensation Committee has the authority to secure services for executive compensation matters, legal advice, or other expert services, both from within and outside the company. The Compensation Committee has not delegated any authority to act on its behalf.

Role of Executive Officers

Each year, the President and Chief Executive Officer submits recommendations to the Compensation Committee for adjustments to the salary, bonuses and long-term equity incentive awards payable to Named Executive Officers, excluding himself. As executive officers are promoted or hired during the year, the President and Chief Executive Officer makes compensation recommendations to the Compensation Committee and works closely with the Compensation Committee to ensure that all compensation arrangements for executive officers are consistent with the existing compensation philosophy of our managing general partner and are approved by the Compensation Committee. The President and Chief Executive Officer also confers with the Compensation Committee regarding each executive officer’s performance, experience, demonstrated leadership, job knowledge and management skills. At the direction of the Compensation Committee, the President and Chief Executive Officer and the Senior Vice President, General Counsel and Secretary attend certain meetings and work sessions of the Compensation Committee.

Use of Peer Group Comparisons

The Compensation Committee believes that it is important to review and compare our performance with that of peer companies in the coal industry. In setting executive compensation for 2007, the Compensation Committee reviewed compensation information regarding other companies in the coal industry set forth in the Cammocks, Inc. Coal Industry Survey. The Compensation Committee also reviewed publicly available information regarding the compensation of executive officers of Massey Energy Company, Alpha Natural Resources Inc., Foundation Coal Holdings Inc., International Coal Group Inc., James River Coal Company, Penn Virginia Resource Partners, L.P., Natural Resource Partners, L.P. and Westmoreland Coal Company. These companies were identified as comparable with regard to revenue, number of mines, type of mines (e.g., we compare primarily to coal companies with underground mines) and other financial and operating indicators by which we have historically measured our performance, or as master limited partnerships that participate in the coal industry through ownership of coal reserves and other property.

Role of Compensation Consultants

Historically, the Compensation Committee has relied on its review of peer group information and third-party market survey data such as Cammocks Coal Industry Survey and the Tulsa Area Survey to understand the executive compensation market. In July 2007, the Compensation Committee engaged Mercer Human Resource Consulting as an outside compensation consultant to assist the Compensation Committee in collecting peer group compensation information and in assessing the competitiveness of our compensation program for 2008.

Compensation Program Components

Overview

The components of the executive officer compensation package include:

•

base salary;

•

annual incentive bonus awards under the STIP;

•

annual awards of restricted common units under the LTIP and of “phantom” units under the SERP.

In addition, all of the executive officers are entitled to customary benefits available to all of our employees, including group medical, dental, and life insurance and participation in our profit sharing and savings plan. We do not have employment agreements with any of our Named Executive Officers.

The Compensation Committee intends for each executive officer’s base salary to be at the middle of the competitive market place and for annual incentive bonus awards under the STIP and equity participation through the LTIP and the SERP to give an executive the opportunity, based upon our overall performance, to achieve total compensation at the top quartile of the competitive market place.

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Base Salary

When reviewing base salaries, the Compensation Committee’s policy is to consider the individual’s performance, our past performance and the individual’s contribution to that performance, the individual’s level of responsibility, the position’s complexity and its importance to us in relation to other executive positions, and competitive pay practices. In general, base salaries are targeted at the middle of the competitive market place. As discussed above, the Compensation Committee considers comparative compensation data of companies in our peer group and the assessment of the executive’s performance, experience, demonstrated leadership, job knowledge and management skills by the President and Chief Executive Officer of our managing general partner. Base salaries are reviewed annually to ensure continuing consistency with market levels, and adjustments to base salaries reflect movement in the competitive market as well as individual performance.

Annual Incentive Bonus Awards

The STIP is designed to assist us in attracting, retaining and motivating qualified personnel by rewarding management, including the Named Executive Officers, and selected other salaried employees with cash awards for our achieving an annual financial performance target. The annual performance target, which historically has been EBITDA-derived, is recommended by the President and Chief Executive Officer of our managing general partner and approved by the Compensation Committee prior to or during January of each year. EBITDA is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization and minority interest, but the Compensation Committee has discretion to normalize the calculation of EBITDA by adding and removing items from the calculation to ensure that the performance target reflects the pure operating results of the core mining business. For 2007, the Compensation Committee approved a minimum financial performance target of $180.9 million in EBITDA, normalized by excluding any charges for LTIP expense, benefits related to synfuel, and benefits of any insurance recovery associated with the MC Mining Mine Fire incident up to $8 million, and we achieved the target.

The aggregate cash available for awards under the STIP each year is dependent on our actual financial results for the year compared to the annual performance target, and it increases in relationship to our adjusted EBITDA exceeding the minimum threshold. Payments for executive officers each year are determined by and in the discretion of the Compensation Committee, which is able to amend the STIP at any time. Cash awards are payable in the first quarter of the following calendar year. Termination of employment of an executive officer for any reason prior to payment of a cash award will result in forfeiture of any right to the award, unless and to the extent waived by the Compensation Committee in its discretion.

Equity Participation

Equity compensation pursuant to the LTIP is a key component of our executive compensation program. Our LTIP is sponsored by Alliance Coal. Under the LTIP, annual grant levels for designated participants (including the Named Executive Officers) are recommended by our managing general partner’s President and Chief Executive Officer, subject to the review and approval of the Compensation Committee.

The grants are made of either (a) restricted units or (b) options to purchase common units. To date, the Compensation Committee has not granted any unit options under the LTIP. Restricted units granted under the LTIP vest at the end of a stated period from the grant date (which is currently approximately three years for all outstanding restricted units), provided we achieve an aggregate performance target for that period. The performance target typically is based on a normalized EBITDA measure, similar to the STIP measure, with actual aggregate performance for the vesting period compared to aggregate budgeted performance for the period. Historically, we have issued grants under the LTIP at the beginning of each year, with the exceptions of new employees who begin employment with us at some other time and job promotions that may occur at some other time.

Our managing general partner’s policy is to issue common units pursuant to the LTIP to serve as a means of incentive compensation for performance and not primarily as an opportunity for equity participation with respect to our common units. Therefore, no consideration will be payable by the plan participants upon receipt of the common units. 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 us in the open market at a price equal to the then prevailing price, or will be units already owned or newly issued by us, or any combination of the foregoing. If we issue new common units upon payment of the restricted units or unit options instead of purchasing them, the total number of common units outstanding will increase.

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Restricted Units. Restricted units will vest at the end of a period of time as determined by the Compensation Committee, which is currently approximately three years after the grant date for all outstanding restricted units, provided we achieve the aggregate performance target for that period. However, if a grantee’s employment is terminated for any reason prior to the vesting of any restricted units, those restricted units will be automatically forfeited, unless the Compensation Committee, in its sole discretion, determines otherwise. All grants under the LTIP are of “phantom units” and are settled, upon satisfaction of the applicable vesting requirements, in common units reduced by a cash settlement component equal to the minimum statutory income tax withholding requirement for each individual participant based upon the fair market value of the common units as of the date of payment. Pursuant to the distribution equivalent rights provision of the LTIP, all grants of restricted units include the contingent right to receive quarterly cash distributions in an amount equal to the cash distributions we make to unit holders during the vesting period.

Unit Options. We have not made any grants of unit options. The Compensation Committee, in the future, may decide to make unit option grants to employees and directors on terms determined by the Compensation Committee. When granted, unit options will have an exercise price set by the Compensation Committee which may be above, below or equal to the fair market value of a common unit on the date of grant. If a grantee’s employment is terminated for any reason prior to the vesting of any unit options, those unit options will be automatically forfeited, unless the Compensation Committee, in its sole discretion, provides otherwise.

Grant Timing. The Compensation Committee does not time, nor has the Compensation Committee in the past timed, the grant of long-term equity incentive awards in coordination with the release of material non-public information. Instead, long-term equity incentive awards are granted only at the time or times dictated by our normal compensation process as developed by the Compensation Committee.

Effect of a Change in Control. Upon a change in control as defined in the LTIP, all awards of restricted units and options under the LTIP shall automatically vest and become payable or exercisable, as the case may be, in full. In this regard, all restricted periods shall terminate and all performance criteria, if any, shall be deemed to have been achieved at the maximum level. The LTIP defines a change in control as one of the following: (1) any sale, lease, exchange or other transfer of all or substantially all of our assets or our managing general partner’s assets to any person; (2) the consolidation or merger of our managing general partner with or into another person pursuant to a transaction in which the outstanding voting interests of our managing general partner is changed into or exchanged for cash, securities or other property, other than any such transaction where (a) the outstanding voting interests of our managing general partner is changed into or exchanged for voting stock or interests of the surviving corporation or its parent and (b) the holders of the voting interests of our managing general partner immediately prior to such transaction own, directly or indirectly, not less than a majority of the voting stock or interests of the surviving corporation or its parent immediately after such transaction; or (3) a person or group being or becoming the beneficial owner of more than 50% of all voting interests of our managing general partner then outstanding.

Amendments and Termination. Our Board of Directors or the Compensation Committee may, in its discretion, terminate the LTIP at any time with respect to any common units for which a grant has not previously been made. Except as required by the rules of the exchange on which the common units may be listed at that time, our Board of Directors or the Compensation Committee may alter or amend the LTIP in any manner from time to time; provided, however, that no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the affected participant. In addition, our Board of Directors or the Compensation Committee may, in its discretion, establish such additional compensation and incentive arrangements as it deems appropriate to motivate and reward our employees.

Supplemental Executive Retirement Plan

We maintain the SERP to help attract and motivate key employees, including the Named Executive Officers. Participation in the SERP aligns the interest of each Named Executive Officer with the interests of our unitholders because all allocations made to participants under the SERP are made in the form of “phantom” units that track the value of our common units. Under the terms of the SERP, participants are entitled to receive on December 31 of each year an allocation equal to his or her percentage allocation multiplied by the sum of base salary and cash received under the STIP and LTIP that year. The contribution made to the SERP each year for a participant is reduced by any supplemental contribution that was made to our defined contribution profit sharing and savings plan for the participant that year. A participant’s

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cumulative notional phantom unit account balance earns the equivalent of common unit distributions. The calculated distributions are added to the notional account balance in the form of additional phantom units. All amounts granted under the SERP vest immediately and are paid out upon the participant’s termination or death in cash equal to then current price of common units multiplied by the number of phantom units held under the SERP. The Compensation Committee approves the participants and their percentage allocations, and is able to amend or terminate the plan at any time.

Upon any recapitalization, reorganization, reclassification, split of common units, distribution or dividend of securities on common units, our consolidation or merger, or sale of all or substantially all of our assets or other similar transaction which is effected in such a way that holders of common units are entitled to receive (either directly or upon subsequent liquidation) cash, securities or assets with respect to or in exchange for common units, the Compensation Committee shall, in its sole discretion (and upon the advice of financial advisors as may be retained by the Compensation Committee), immediately adjust the notional balance of phantom units in each Named Executive Officer’s SERP account to equitably credit the fair value of the change in the common units and/or the distributions (of cash, securities or other assets) received or economic enhancement realized by the holders of the common units.

An executive officer who participates in the SERP shall be entitled to receive an allocation under the SERP for the year in which his employment is terminated on the occurrence of any of the following events:

(1)

the executive officer’s employment is terminated other than for cause;

(2)

the executive officer terminates employment for good reason;

(3)

a change of control of us or our managing general partner occurs and, as a result, an executive officer’s employment is terminated (whether voluntary or involuntary);

(4)

death of the executive officer;

(5)

attaining retirement age of 65 years for any executive officer; and

(6)

incurring a total and permanent disability, which shall be deemed to occur if an executive officer is eligible to receive benefits under the terms of the long-term disability program maintained by us.

This allocation for the relevant year in which an executive officer’s termination occurs shall equal the executive officer’s eligible compensation for such year (including any severance amount, if applicable) multiplied by his percentage allocation under the SERP, reduced by any supplemental contribution that was made to our defined contribution profit sharing and savings plan for the participant that year.

CEO Executive Compensation

Mr. Craft has not received an increase in base salary since 2002, and he did not receive a STIP bonus or LTIP award in 2006 or 2007. Mr. Craft and related trusts own over 50% of the outstanding equity of AHGP, which owns our managing general partner, the incentive distribution rights in ARLP and 42.5% of the outstanding common units of ARLP as of December 31, 2007. Thus Mr. Craft’s interests are directly aligned with those of our unitholders.

Compensation Committee Report

The Compensation Committee of our managing general partner (collectively, our “Committee”) has submitted the following report for inclusion in this Annual Report on Form 10-K:

Our Committee has reviewed and discussed the Compensation Discussion and Analysis contained in this Annual Report on Form 10-K with management. Based on our Committee’s review of and the discussions with management with respect to the Compensation Discussion and Analysis, our Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

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The foregoing report is provided by the following directors, who constitute all the members of the Committee:

Members of the Compensation Committee:

Merribel S. Ayres

John P. Neafsey

John H. Robinson, Chairman

Notwithstanding anything to the contrary set forth in any of our previous filings under the Securities Act or the Exchange Act, that incorporate future filings, including this Annual Report on Form 10-K, in whole or in part, the foregoing Compensation Committee Report shall not be deemed to be filed with the SEC or incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference.

Summary Compensation Table for 2007


Name and Principal Position	Year	Salary (2)		Bonus (3)		Unit Awards(4)		Option Awards (1)		Non-Equity Incentive Plan Compensation (5)		Change in Pension Value and Nonqualified Deferred Compensation Earnings (1)		All Other Compensation (6)		Total
Joseph W. Craft III,	2007	$	334,828	$	—	$	372,000	$	—	$	—	$	—	$	205,989	$	912,817
President, Chief Executive Officer and Director	2006		334,828		—		1,066,400		—		—		—		302,821		1,704,049

Brian L. Cantrell,	2007		210,000		—		183,028		—		100,000		—		64,208		557,236
Senior Vice President-Chief Financial Officer	2006		202,115		—		241,573		—		125,000		—		68,825		637,513

Robert G. Sachse,	2007		250,000		185,000		150,483		—		110,000		—		92,326		787,809
Executive Vice President-Marketing

Charles R. Wesley,	2007		236,280		—		232,818		—		—		—		116,265		585,363
Senior Vice President-Operations (7)	2006		236,280		—		482,859				—				161,731		880,870

Thomas M. Wynne,	2007		176,854		—		170,375		—		107,500		—		57,128		511,857
Vice President-Operations

(1)	Column is not applicable.

(2)

Some of the Named Executive Officers devote a portion of their time to the business of one or more related parties and, to the extent they do so, the base salary of those executive officers is reimbursed to Alliance Coal by those related parties pursuant to an administrative services agreement. Please see “Item 1. Business—Employees—Administrative Services Agreement.” For 2007, the percentage of base salary reimbursed to Alliance Coal was 5% for Mr. Craft, 5% for Mr. Sachse, and 15% for Mr. Cantrell. For 2006, the percentage of base salary reimbursed to Alliance Coal was 14% for Mr. Craft, 34% for Mr. Sachse, and 22% for Mr. Cantrell.

(3)	Represents a retention bonus paid to Mr. Sachse in 2007.

(4)

The 2007 amounts represent the compensation expense recognized in 2007 in accordance with SFAS No. 123R associated with LTIP grants made in 2007, 2006 and 2005. The 2006 amounts represent the compensation expense recognized in 2006 in accordance with SFAS No. 123R associated with LTIP grants made in 2006, 2005 and 2004. Please see “Item 8. Financial Statements and Supplementary Data – Note 13. Compensation Plans” for an explanation of the valuation assumptions we use in applying SFAS No. 123R. Also, please see “Item 11. Compensation Discussion and Analysis — Compensation Program Components — Equity Participation.”

(5)

Represents the STIP bonus earned for the respective year. STIP payments are made in the first quarter of the year following the year earned. Other than this bonus, there were no other applicable bonuses earned or deferred associated with year 2007. Please see “Item 11. Compensation Discussion and Analysis — Compensation Program Components — Annual Incentive Bonus Awards.”

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(6)

For Mr. Sachse, the amount includes perquisites and other personal benefits totaling $11,473, comprising club dues of $7,473 and tax preparation fees of $4,000. Otherwise, for all Named Executive Officers, the amounts represent the sum of the (a) SERP phantom unit contributions valued at the market closing price on the date the phantom unit was granted, (b) distribution equivalent rights received on non vested LTIP restricted units and (c) profit sharing savings plan employer contribution. For 2007, the amounts were for Mr. Craft, $121,989, $66,000 and $18,000, respectively; for Mr. Cantrell, $14,963, $33,990 and $15,255, respectively; for Mr. Sachse, $36,343, $26,510 and $18,000, respectively; for Mr. Wesley, $57,730, $40,535 and $18,000, respectively; and for Mr. Wynne, $12,737, $31,020 and $13,371, respectively. For 2006, the amounts were for Mr. Craft, $120,101, $165,120 and $17,600, respectively; for Mr. Cantrell, $16,360, $37,728 and $14,737, respectively; and for Mr. Wesley, $68,819, $75,312 and $17,600, respectively. No Named Executive Officer other than Mr. Sachse, received perquisites or personal benefits with a total value in excess of $10,000.

(7)

Mr. Wesley has not received an increase in base salary since 2005, and he did not receive a STIP bonus in 2006 or 2007 and did not receive an LTIP award in 2007. Mr. Wesley and a related trust own nearly 6% of the outstanding equity of AHGP, which owns our managing general partner, the incentive distribution rights in ARLP and 42.5% of the outstanding common units of ARLP as of December 31, 2007. Thus Mr. Wesley’s interests are directly aligned with those of our unitholders.

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Grants of Plan-Based Awards Table for 2007


Name	Grant Date	Approved Date	Estimated Future Payouts Under Non-Equity Incentive Plan Awards			Estimated Future Payouts Under Equity Incentive Plan Awards			All Other Unit Awards: Number of	All Other Option Awards: Number of Securities Underlying	Exercise or Base Price of Options	Grant Date Fair Value of Unit
Name	Grant Date	Approved Date	Threshold (1)	Target (1)	Maximum (1)	Threshold (4)	Target (2)	Maximum (4)	Units (3)	Options (1)	Awards (1)	Awards (5)
Joseph W. Craft, III	January 1, 2007	January 24, 2007					—		—			$	—
	February 14, 2007	(6)					—		677				23,891
	May 15, 2007	(6)					—		603				24,530
	August 14, 2007	(6)					—		703				23,565
	November 14, 2007	(6)					—		666				26,500
	December 31, 2007	(6)					—		648				23,503

							—		3,297				121,989

Brian L. Cantrell	January 1, 2007	January 24, 2007					5,800		—				206,712
	February 14, 2007	(6)					—		15				529
	May 15, 2007	(6)					—		14				570
	August 14, 2007	(6)					—		16				536
	November 14, 2007	(6)					—		15				597
	December 31, 2007	(6)					—		351				12,731

							5,800		411				221,675

Robert G. Sachse	January 1, 2007	January 24, 2007					5,800		—				206,712
	February 14, 2007	(6)					—		—				—
	May 15, 2007	(6)					—		—				—
	August 14, 2007	(6)					—		—				—
	November 14, 2007	(6)					—		—				—
	December 31, 2007	(6)					—		1,002				36,343

							5,800		1,022				243,055

Charles R. Wesley	January 1, 2007	January 24, 2007					—		—				—
	February 14, 2007	(6)					—		323				11,399
	May 15, 2007	(6)					—		288				11,716
	August 14, 2007	(6)					—		336				11,263
	November 14, 2007	(6)					—		318				12,653
	December 31, 2007	(6)					—		295				10,700

							—		1,560				57,731

Thomas M. Wynne	January 1, 2007	January 24, 2007					3,700		—				131,868
	February 14, 2007	(6)					—		33				1,165
	May 15, 2007	(6)					—		29				1,180
	August 14, 2007	(6)					—		34				1,140
	November 14, 2007	(6)					—		32				1,273
	December 31, 2007	(6)					—		220				7,979

							3,700		348				144,605

(1)	Column not applicable.

(2)	Represents LTIP phantom unit grants. Please see “Item 11. Compensation Discussion and Analysis — Compensation Program Components — Equity Participation.”

(3)	Represents the number of phantom units added to the participant’s SERP notional account balance. Please see “Item 11. Compensation Discussion and Analysis – Compensation Program Components — Supplemental Executive Retirement Plan.”

(4)

The number of units granted is not subject to minimum thresholds, targets or maximum payout conditions. However, the vesting of these grants is subject to meeting certain financial tests. Please see “Item 11. Compensation Discussion and Analysis — Compensation Program Components — Equity Participation.”

(5)

For LTIP phantom unit grants, represents the number of units valued at $35.64, the unit price applicable under SFAS No. 123R for 2007 grants. For SERP phantom unit grants, represents the number of phantom units granted valued at the market closing price on the date the phantom unit was granted. Phantom units granted under SERP vest on the date granted.

(6)

In accordance with the provisions of the SERP, participant’s cumulative notional phantom unit account balance earns the equivalent of a phantom common unit distribution when ARLP pays a distribution. These contributions are in accordance with the SERP plan document, which has been approved by the Compensation Committee. Therefore, these contributions are not separately approved by the Compensation Committee.

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Narrative Discussion Relating to the Summary Compensation Table and Grants of Plan-Based Awards Table

Annual Incentive Bonus Awards

Under the STIP, our Named Executive Officers are eligible for cash awards for our achieving an annual financial performance target. The annual performance target, which historically has been EBITDA-derived, is recommended by the President and Chief Executive Officer of our managing general partner and approved by the Compensation Committee prior to or during January of each year. EBITDA is calculated as net income before net interest expense, income taxes and depreciation, depletion and amortization, but the Compensation Committee has discretion to normalize the calculation of EBITDA by adding and removing items from the calculation to ensure that the performance target reflects the pure operating results of the core mining business. The aggregate cash available for awards under the STIP each year is dependent on our actual financial results for the year compared to the annual performance target, and the cash available increases in relationship to our adjusted EBITDA exceeding the minimum threshold. Please see “Item 11. Compensation Discussion and Analysis — Compensation Program Components – Annual Incentive Bonus Awards.”

Long Term Incentive Plan

Under the LTIP, annual grant levels for designated participants (including the Named Executive Officers) are recommended by our managing general partner’s President and Chief Executive Officer, subject to the review and approval of the Compensation Committee. The grants are made of either (a) restricted units or (b) options to purchase common units. To date, the Compensation Committee has not granted any unit options under the LTIP. Restricted units granted under the LTIP vest at the end of a stated period from the grant date (which is currently approximately three years for all outstanding restricted units), provided we achieve an aggregate performance target for that period. The performance target typically is based on a normalized EBITDA measure, similar to the STIP measure, with actual aggregate performance for the vesting period compared to aggregate budgeted performance for the period. Please see “Item 11. Compensation Discussion and Analysis — Compensation Program Components — Equity Participation.”

Supplemental Executive Retirement Plan

Under the terms of the SERP, participants are entitled to receive on December 31 of each year an allocation equal to their percentage allocation multiplied by the sum of base salary and cash received under the STIP and LTIP that year. The contribution made to the SERP each year for a participant is reduced by any supplemental contribution that was made to our defined contribution profit sharing and savings plan for the participant that year. A participant’s cumulative notional phantom unit account balance earns the equivalent of common unit distributions. The calculated distributions are added to the notional account balance in the form of additional phantom units. All amounts granted under the SERP vest immediately and are paid out upon the participant’s termination or death in cash equal to then current price of common units multiplied by the number of phantom units held under the SERP. Please see “Item 11. Compensation Discussion and Analysis — Compensation Program Components — Supplemental Executive Retirement Plan.”

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Salary and Bonus in Proportion to Total Compensation

The following table shows the proportion of salary and bonus to total compensation during 2007:


Name	Year	Salary and Bonus ($)		Total Compensation ($)		Salary and Bonus as a % of Total Compensation (1)
Joseph W. Craft III	2007	$	334,828	$	912,817	36.7	%
	2006		334,828		1,704,049	19.6	%

Brian L. Cantrell	2007		210,000		557,236	37.7	%
	2006		202,115		637,513	31.7	%

Robert G. Sachse	2007		435,000		787,809	55.2	%

Charles R. Wesley	2007		236,280		585,363	40.4	%
	2006		236,280		880,870	26.8	%

Thomas M. Wynne	2007		176,854		511,857	34.6	%

(1)	Percentages reflect base salary and bonus compared to total compensation from the Summary Compensation Table.

Outstanding Equity Awards at Fiscal Year-End 2007 Table


Name	Date	Number of Securities Underlying Unexercised Options Exercisable (1)	Number of Securities Underlying Unexercised Options Unexerciseable (1)	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (1)	Option Exercise Price (1)	Option Exercise Date (1)	Number of Units That Have Vested (1)	Market Value of Units That Have Not Vested (1)	Equity Incentive Plan Awards: Number of Unearned Units or Other Rights That Have Not Vested (2)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested (3)
Joseph W. Craft III	2007								—	$	—
	2006								—		—
	2005								30,000		1,088,100

									30,000		1,088,100

Brian L. Cantrell	2007								5,800		210,366
	2006								4,300		155,961
	2005								5,350		194,045

									15,450		560,372

Robert G. Sachse	2007								5,800		210,366
	2006								4,400		159,588
	2005								1,850		67,100

									12,050		437,054

Charles R. Wesley	2007								—		—
	2006								7,275		263,864
	2005								11,150		404,411

									18,425		668,275

Thomas M. Wynne	2007								3,700		134,199
	2006								4,400		159,588
	2005								6,000		217,620

									14,100		511,407

(1)	Column is not applicable.

(2)

Represents LTIP non-vested phantom units awards, which vest approximately three years after the grant date. Units granted in 2007, 2006 and 2005 vest on January 1, 2010, January 1, 2009 and January 1, 2008, respectively. Please see “Item 11. Compensation Discussion and Analysis — Compensation Program Components — Equity Participation.”

(3)	The units are valued at $36.27, the closing price on December 31, 2007, the final market trading day of 2007.

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Pension Benefits Table for 2007


Name	Plan Name	Year	Number of Years Credited Service (1)	Present Value of Accumulated Benefit (2)		Payments During Last Fiscal Year
Joseph W. Craft III	SERP	2007		$	1,711,291	$	—
Brian L. Cantrell	SERP	2007			50,125		—
Robert G. Sachse	SERP	2007			36,343		—
Charles R. Wesley	SERP	2007			816,256		—
Thomas M. Wynne	SERP	2007			88,354		—

(1)	Column not applicable.

(2)

Represents the participant’s cumulative notional account balance of phantom units valued at $36.27, the closing price on December 31, 2007, the final market trading day of 2007. Please see “Item 11. Compensation Discussion and Analysis — Compensation Policy and Program Components — Supplemental Executive Retirement Plan.”

Narrative Discussion Relating to the Pension Benefits Table for 2007

Supplemental Executive Retirement Plan

Under the terms of the SERP, participants are entitled to receive on December 31 of each year an allocation equal to his or her percentage allocation multiplied by the sum of base salary and cash received under the STIP and LTIP that year. The contribution made to the SERP each year for a participant is reduced by any supplemental contribution that was made to our defined contribution profit sharing and savings plan for the participant that year. A participant’s cumulative notional phantom unit account balance earns the equivalent of common unit distributions. The calculated distributions are added to the notional account balance in the form of additional phantom units. All amounts granted under the SERP vest immediately and are paid out upon the participant’s termination or death in cash equal to then current price of common units multiplied by the number of phantom units held under the SERP. Please see “Item 11. Compensation Discussion and Analysis — Compensation Program Components — Supplemental Executive Retirement Plan.”

Directors Compensation for 2007

The compensation of the directors of our managing general partner, MGP, is set by the Board of Directors upon recommendation of the Compensation Committee. Mr. Craft, our only employee director, receives no director compensation. The directors of MGP devote 100% of their time as directors of MGP to the business of the ARLP Partnership.

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Summary Compensation Table for 2007


Name	Fees earned or Paid in Cash ($)		Unit Awards ($) (2)(4)		Option Awards ($)(1)		Non-Equity Incentive Plan Compensation ($)(1)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(1)		All Other Compensation ($)(3)		Total ($)
Merribel S. Ayres	$	90,000	$	—	$	—	$	—	$	—	$	10,000	$	100,000
Michael J. Hall		90,000		42,437		—		—		—		12,370		144,807
John J. MacWilliams (5)		—		—		—		—		—		95,555		95,555
Preston R. Miller (5)		—		—		—		—		—		95,555		95,555
John P. Neafsey		—		166,354		—		—		—		12,370		178,724
John H. Robinson		90,000		77,457		—		—		—		12,370		179,827
Wilson M. Torrence		—		94,252		—		—		—		—		94,252

(1)	Column is not applicable.

(2)

Amounts represent the compensation expense recognized in 2007 in accordance with SFAS No. 123R associated with LTIP grants made in 2006 and 2005 as well as amounts earned for the annual retainer under the Directors Plan. Please see “Item 8. Financial Statements and Supplementary Data – Note 13. Compensation Plans” for an explanation of our valuation assumptions used in applying SFAS No. 123R. Under our managing general partner’s Directors’ Plan, each non-employee director was paid an annual retainer of $90,000 in 2007. Each non-employee director is eligible to participate in a deferred compensation plan that is administered by the Compensation Committee. Please see discussion of the “Directors’ Plan” immediately following these notes. Messrs. Neafsey and Torrence elected to defer their compensation in 2007.

(3)

For all but Ms. Ayres, amount represents distribution equivalent rights payments received by the directors during 2007 on non-vested LTIP restricted units. Each of Messrs. Hall, Neafsey and Robinson’s Other Compensation also includes $5,000 in matching charitable contributions made by us. We match individual contributions of $25 or more to educational institutions and not-for-profit organizations on a one-to-one basis up to $5,000 per individual, per calendar year. For Ms. Ayres, the amount represents fees we paid her firm, Lighthouse Consulting Group, LLC, for governmental affairs advisory services relating to our business and properties in Pennsylvania.

(4)	At December 31, 2007, each director had the following number of ARLP common units outstanding under the deferred compensation plan:


Name		Directors Deferred Compensation Plan (in Units)
Merribel S. Ayres		—
Michael J. Hall		—
John P. Neafsey		16,603
John H. Robinson		16,515
Wilson M. Torrence		2,576

(5)

Messrs. MacWilliams and Miller resigned from the Board of Directors effective January 8, 2007. The amounts included in “All Other Compensation” for Messrs. MacWilliams and Miller represent the distributions from their respective notional account balances for annual retainers they had elected to defer under the Directors Compensation Program for prior years service as a director, as well as distribution equivalent rights payments received during 2007 on non-vested LTIP restricted units. By determination of the Compensation Committee, the non-vested LTIP restricted units held by Messrs. MacWilliams and Miller were not forfeited by their resignations.

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The ARLP’s managing general partner’s Directors’ Compensation Program (“Directors’ Plan”) consists of two parts: (1) the payment of directors’ annual retainers and (2) deferrals of the annual retainers in phantom units by electing directors. Under the Directors’ Plan, each non-employee director was compensated with an annual retainer of $90,000 during 2007. The annual retainer is payable in cash on a quarterly basis in advance. Prior to the beginning of each plan year, each non-employee director may elect to defer all or a portion of his compensation until he ceases to be a member of the Board of Directors or a designated payment date. A new election must be made for each plan year. For compensation deferred by a director, a notional account is established and credited with the number of “phantom” units determined by dividing the pro rata annual retainer payable on such date by the closing sales price per common unit averaged over the immediately preceding ten trading days. In addition, when distributions are made with respect to ARLP common units, the notional account is credited with “phantom” units that are equal in amount to the distributions made with respect to ARLP common units. The deferred compensation plan is administered by the Compensation Committee, and the Board of Directors may change or terminate the deferred compensation plan at any time; provided, however, that accrued benefits under the deferred benefit plan cannot be impaired.

Upon a participating director’s termination or designated payment date, we shall pay to such director (or to his or her beneficiary in case of the director’s death) (a) that number of ARLP common units equal to the number of phantom units then credited to the account, (b) an amount of cash equal to the then fair market value of the phantom units credited to his or her account, or (c) any combination thereof as determined by the Compensation Committee in its discretion.

Upon any recapitalization, reorganization, reclassification, split of common units, distribution or dividend of securities on ARLP common units, our consolidation or merger, or sale of all or substantially all of our assets or other similar transaction which is effected in such a way that holders of common units are entitled to receive (either directly or upon subsequent liquidation) cash, securities or assets with respect to or in exchange for ARLP common units, the Compensation Committee shall, in its sole discretion (and upon the advice of financial advisors as may be retained by the Compensation Committee), immediately adjust the notional balance of phantom units in each director’s account, to the extent such director participates in the deferred compensation plan, to equitably credit the fair value of the change in the ARLP common units and/or the distributions (of cash, securities or other assets) received or economic enhancement realized by the holders of the ARLP common units.

Compensation Committee Interlocks and Insider Participation

With the exception of AHGP, none of our executive officers serves as a member of the Board of Directors or Compensation Committee of any entity that has one or more of its executive officers serving as a member of the Board of Directors or Compensation Committee of our managing general partner.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth certain information as of January 31, 2008, regarding the beneficial ownership of common units held by (a) each director of our managing general partner, (b) each executive officer of our managing general partner identified in the Summary Compensation Table included in “Item 11. Executive Compensation” above, (c) all such directors and executive officers as a group, and (d) each person known by our managing general partner to be the beneficial owner of 5% or more of our common units. Our managing general partner is owned by AHGP (which is reflected as a 5% common unit holder in the table below), and approximately 80% of the equity of AHGP is owned by members of management and certain former members of management. Our special general partner is a wholly-owned subsidiary of ARH, which is indirectly wholly-owned by Joseph W. Craft III. The address of each of AHGP, ARH, our managing general partner, our special general partner, and unless otherwise indicated in the footnotes to the table below, each of the directors and executive officers reflected in the table below is 1717 South Boulder Avenue, Suite 400, Tulsa, Oklahoma 74119. Unless otherwise indicated in the footnotes to the table below, the common units reflected as being beneficially owned by our managing general partner’s directors and named executive officers are held directly by such directors and officers. The percentage of common units beneficially owned is based on 36,550,659 common units outstanding as of January 31, 2008.

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Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned
Directors and Executive Officers
Joseph W. Craft III (1)	15,882,768	43.45	%
Merribel S. Ayres	—	*
Michael J. Hall	26,601	*
John P. Neafsey	33,850	*
John H. Robinson	6,450	*
Wilson M. Torrence	—	*
Brian L. Cantrell	10,619	*
Robert G. Sachse	18,030	*
Charles R. Wesley III	100,108	*
Thomas M. Wynne	28,938	*
All directors and executive officers as a group (10 persons)	16,107,364	44.07	%

5% Common Unit Holders
Alliance Holdings GP, L.P. (2)	15,544,169	42.53	%
M&G Investment Funds 1 (3)	1,970,000	5.39	%

*	Less than one percent.

(1)

Mr. Craft’s common units consist of (i) 337,599 common units held directly by him, (ii) 1,000 common units held by his son, and (iii) 15,544,169 common units held by AHGP. Mr. Craft is a director, and through his ownership of C-Holdings, LLC, the sole owner of AGP, the general partner of AHGP, and he holds, directly or indirectly, or may be deemed to be the beneficial owner of, a majority of the outstanding common units of AHGP. AHGP owns 42.53% of our common units as of January 31, 2008. Mr. Craft disclaims beneficial ownership of the common units held by AHGP except to the extent of his pecuniary interest therein.

(2)	See footnote (1) above and the paragraph preceding the above table for explanation of the relationship between AHGP, Joseph W. Craft III and us.

(3)	The information in the above table with respect to M&G Investment Funds 1 is based on a Schedule 13G/A filing made by it with the Securities and Exchange Commission. The address for M&G Investment Funds 1 is Governor’s House, Laurence Pountney Hill, London, EC4R 0HH.

Equity Compensation Plan Information


Plan Category	Number of units to be issued upon exercise/vesting of outstanding options, warrants and rights as of December 31, 2007	Weighted-average exercise price of outstanding options, warrants and rights	Number of units remaining available for future issuance under equity compensation plans as of December 31, 2007
Equity compensation plans approved by unitholders:
Long-Term Incentive Plan	255,180	N/A	186,330
Equity compensation plans not approved by unitholders:
Supplemental Executive Retirement Plan	84,604	N/A	75,396
Deferred Compensation Plan for Directors	35,694	N/A	64,306

For a description of our SERP and our Deferred Compensation Plan for Directors, please read “Supplemental Executive Retirement Plan” and “Compensation of Directors” under “Item 11. Executive Compensation.”

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ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Certain Relationships and Related Transactions

As of December 31, 2007, AHGP owned 15,544,169 common units representing 42.5% of our common units and our incentive distribution rights. In addition, our general partners own, on a combined basis, an aggregate 2% general partner interest in us, the Intermediate Partnership and the subsidiaries. Our managing general partner’s ability, as managing general partner, to control us together with AHGP’s ownership of 15,544,169 common units, effectively gives our general partner the ability to veto some of our actions and to control our management.

Certain of our officers and directors are also officers and/or directors of AHGP, including Joseph W. Craft III, the President and Chief Executive Officer of our managing general partner, Michael J. Hall, a Director and Chairman of the Audit Committee, Brian L. Cantrell, the Senior Vice President and Chief Financial Officer of our managing general partner, and R. Eberley Davis, the Senior Vice President, General Counsel and Secretary of our managing general partner.

Transactions Between Us, SGP, SGP Land, ARH, ARH II and AHGP

Administrative Services

In connection with AHGP’s IPO, ARLP entered into an Administrative Services Agreement with our managing general partner, Alliance Coal, AGP, AHGP and ARH II. Under the Administrative Services Agreement, certain employees, including some executive officers, provide administrative services for AHGP and ARH II and their respective affiliates. We are reimbursed for services rendered by our employees on behalf of these entities as provided under the Administrative Services Agreement. We billed and recognized administrative service revenue under this agreement of $0.3 million for the year ended December 31, 2007, from AHGP and $0.4 million for the year ended December 31, 2007, from ARH II. Concurrently in 2006, AHGP and AGP joined as parties to our Omnibus Agreement, discussed below, which addresses areas of non-competition between us and ARH, ARH II, SGP and our managing general partner.

Managing General Partner Contribution

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SGP Land, LLC

SGP Land, LLC (“SGP Land”) is owned by our special general partner, which is owned indirectly by Mr. Craft.

On May 2, 2007, Alliance Coal, our operating subsidiary, entered into a time sharing agreement with SGP Land concerning the use of two airplanes owned by SGP Land. In accordance with the provisions of the time sharing agreement, we reimbursed SGP Land $0.3 million for the year ended December 31, 2007 for use of the airplanes.

In 2000, Webster County Coal entered into a mineral lease and sublease with SGP Land, requiring annual minimum royalty payments of $2.7 million, payable in advance through 2013 or until $37.8 million of cumulative annual minimum and/or earned royalty payments have been paid. Webster County Coal paid royalties of $2.7 million the year ended December 31, 2007. As of December 31, 2007, Webster County Coal had recouped, against earned royalties otherwise due, all but $3.2 million of the advance minimum royalty payments made under the lease.

In 2001, Warrior entered into a mineral lease and sublease with SGP Land, requiring annual minimum royalty payments of $2.3 million, payable in arrears until $15.9 million of cumulative annual minimum and/or earned royalty payments were paid. The annual minimum royalty periods expired on September 30, 2007. Warrior paid royalties of $1.3 million for the year ended December 31, 2007. As of December 31, 2007, Warrior had recouped, against earned royalties otherwise due, all advance minimum royalty payments made under the lease.

In 2005, Hopkins County Coal entered into a mineral lease and sublease with SGP Land, and the parties also entered into a Royalty Agreement (collectively, the “Coal Lease Agreements”) in connection therewith. The Coal Lease Agreements provide for payment of five annual minimum royalty payments of $0.7 million beginning in December 2005, and certain option fees. Hopkins County Coal paid advance minimum royalties and/or option fees of $0.7 million during the year ended December 31, 2007. As of December 31, 2007, $4.4 million of advance minimum royalties and/or option fees paid under the Coal Lease Agreements was available for recoupment.

Under the terms of the mineral leases and sublease agreements described above, Webster County Coal, Warrior, and Hopkins County Coal also reimburse SGP Land for its base lease obligations. We reimbursed SGP Land $6.1 million for the year ended December 31, 2007 for the base lease obligations. As of December 31, 2007, Webster County Coal, Warrior, and Hopkins County Coal have recouped, against earned royalties otherwise due base lessors by SGP Land, all advance minimum royalty payments paid by SGP Land to the base lessors in accordance with the terms of the base leases (and reimbursed by Webster County Coal, Warrior, and Hopkins County Coal), except for $0.4 million.

SGP

In 2005, Tunnel Ridge entered into a coal lease agreement with SGP, requiring advance minimum royalty payments of $3.0 million per year. As of December 31, 2007, Tunnel Ridge had paid $9.0 million of advance minimum royalty payments pursuant to the lease. The advance royalty payments are fully recoupable against earned royalties. Tunnel Ridge also controls surface land and other tangible assets under a separate lease agreement with the SGP. Under the terms of the lease agreement, Tunnel Ridge has paid and will continue to pay the SGP an annual lease payment of $0.2 million. The lease agreement has an initial term of four years, which may be extended to be coextensive with the term of the coal lease. Lease expense was $0.2 million for the year ended December 31, 2007.

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We have a noncancelable operating lease arrangement with SGP for the coal preparation plant and ancillary facilities at the Gibson mining complex. Under the terms of the lease, we will make monthly payments of approximately $0.2 millions through January 2011. Lease expense incurred for the year ended December 31, 2007 was $2.6 million.

We previously entered into and have maintained agreements with two banks to provide letters of credit in an aggregate amount of $31.0 million. At December 31, 2007, we had $30.6 million in outstanding letters of credit under these agreements. Our special general partner, SGP, guarantees $5.0 million of these outstanding letters of credit. Historically, the Partnership has paid SGP a guarantee fee equal to 0.30% per annum of the face amount of the letters of credit outstanding. During 2003, SGP agreed to waive the guarantee fee in exchange for guarantees from the Intermediate Partnership and Alliance Coal on the mineral leases and subleases with Webster County Coal and Warrior described above. As noted above, those leases have now been assigned by SGP to Alliance Resource Properties. Since the guarantee is made on behalf of entities within the consolidated partnership, the guarantee has no fair value under FIN No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantees of Indebtedness of Others, and does not impact our consolidated financial statements.

Omnibus Agreement

Concurrent with the closing of our initial public offering, we entered into an omnibus agreement with ARH and our general partners, which govern potential competition among us and the other parties to this agreement. The omnibus agreement was amended in May 2002. Pursuant to the terms of the amended omnibus agreement, ARH agreed, and caused its controlled affiliates to agree, for so long as management controls our managing general partner, not to engage in the business of mining, marketing or transporting coal in the U.S., unless it first offers us the opportunity to engage in a potential activity or acquire a potential business, and the Board of Directors of our managing general partner, with the concurrence of its Conflicts Committee, elects to cause us not to pursue such opportunity or acquisition. In addition, ARH has the ability to purchase businesses, the majority value of which is not mining, marketing or transporting coal, provided ARH offers us the opportunity to purchase the coal assets following their acquisition. The restriction does not apply to the assets retained and business conducted by ARH at the closing of our initial public offering. Except as provided above, ARH and its controlled affiliates are prohibited from engaging in activities wherein they compete directly with us. In addition to its non-competition provisions, this agreement contains provisions which indemnify us against liabilities associated with certain assets and businesses of ARH which were disposed of or liquidated prior to consummating our initial public offering. In May 2006, in connection with the closing of the AHGP IPO, the omnibus agreement was amended to include AHGP and AGP as parties to the agreement.

Director Independence

As a publicly traded limited partnership listed on the NASDAQ Global Select Market, we are required to maintain a sufficient number of independent directors on the board of our managing general partner to satisfy the Audit Committee requirement set forth in NASDAQ Rule 4350(d)(2). Rule 4350(d)(2) requires us to maintain an Audit Committee of at least three members, each of whom must, among other requirements, be independent as defined under NASDAQ Rule 4200(a)(15) and meet the criteria for independence set forth in Rule 10A-3(b)(1) under the Exchange Act (subject to the exemptions provided in Rule 10A-3(c)).

In 2007, the Board of Directors of our managing general partner affirmatively determined that the members of the Audit Committee of our managing general partner—Messrs. Hall, Neafsey and Robinson—are independent directors as defined under applicable NASDAQ and Exchange Act rules. Please see “Item 10. Directors, Executive Officers and Corporate Governance of the Managing General Partner—Audit Committee.”

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ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The firm of Deloitte & Touche LLP is our independent registered public accounting firm. Fees paid to Deloitte & Touche LLP during the last two fiscal years were as follows:

Audit Fees. Fees for audit services provided during the years ended December 31, 2007 and 2006 were $0.8 million and $0.7 million, respectively. Audit services consist primarily of the audit and quarterly reviews of the consolidated financial statements, but can also be related to statutory audits of subsidiaries required by governmental or regulatory bodies, attestation services required by statute or regulation, comfort letters, consents, assistance with and review of documents filed with the SEC, work performed by tax professionals in connection with the audit and quarterly reviews, and accounting and financial reporting consultations and research work necessary to comply with generally accepted accounting principles.

Audit-Related Fees. Fees for audit-related services provided during the years ended December 31, 2007 and 2006, were $0.1 million and $0.1 million, respectively. Audit-related services consist primarily of audits of employee benefit plans, consultations concerning financial accounting and reporting standards, and attestation services associated with third-party compliance.

Tax Fees. Fees for tax services provided during the years ended December 31, 2007 and 2006 were $0.2 million and $0.3 million, respectively. Tax services relate primarily to the preparation of federal and state tax returns but can also be related to tax advice, exclusive of tax services rendered in conjunction with the audit.

All Other Fees. There were no other fees for the years ended December 31, 2007 and 2006, respectively.

The charter of the Audit Committee provides that the committee is responsible for the pre-approval of all auditing services and permitted non-audit services to be performed for us by our independent registered public accounting firm, subject to the requirements of applicable law. In accordance with such charter, the Audit Committee may delegate the authority to grant such pre-approvals to the Audit Committee chairman or a sub-committee of the Audit Committee, which pre-approvals are then reviewed by the full Audit Committee at its next regular meeting. Typically, however, the Audit Committee itself reviews the matters to be approved. The Audit Committee periodically monitors the services rendered by and actual fees paid to the independent registered public accounting firm to ensure that such services are within the parameters approved by the Audit Committee.

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PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)(1)

Financial Statements.

The response to this portion of Item 15 is submitted as a separate section herein under Part II, Item 8. Financial Statements and Supplementary Data.

(a)(2)

Financial Statement Schedules.

Schedule II – Valuation and Qualifying Accounts – Years ended December 31, 2007, 2006 and 2005, is set forth under Part II, Item 8. Financial Statements and Supplementary Data. All other schedules are omitted because they are not applicable or the information is shown in the financial statements or notes thereto.

(a)(3) and (c)

The exhibits listed below are filed as part of this annual report.

3.1

Second Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P. (Incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed with the Commission on October 27, 2005, File No. 000-26823).

3.2

Amended and Restated Agreement of Limited Partnership of Alliance Resource Operating Partners, L.P. (Incorporated by reference to Exhibit 3.2 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 000-26823).

3.3

Certificate of Limited Partnership of Alliance Resource Partners, L.P. (Incorporated by reference to Exhibit 3.6 of the Registrant’s Registration Statement on Form S-1 filed with the Commission on May 20, 1999 (Reg. No. 333-78845)).

3.4

Certificate of Limited Partnership of Alliance Resource Operating Partners, L.P. (Incorporated by reference to Exhibit 3.8 of the Registrant’s Registration Statement on Form S-1/A filed with the Commission on July 23, 1999 (Reg. No. 333-78845)).

3.5

Certificate of Formation of Alliance Resource Management GP, LLC (Incorporated by reference to Exhibit 3.7 of the Registrant’s Registration Statement on Form S-1/A filed with the Commission on July 23, 1999 (Reg. No. 333-78845)).

3.6

Amended and Restated Operating Agreement of Alliance Resource Management GP, LLC (Incorporated by reference to Exhibit 3.4 of the Registrant’s Registration Statement on Form S-3 filed with the Commission on April 1, 2002 (Reg. No. 333-85282)).

3.7

Amendment No. 1 to Amended and Restated Operating Agreement of Alliance Resource Management GP, LLC (Incorporated by reference to Exhibit 3.5 of the Registrant’s Registration Statement on Form S-3 filed with the Commission on April 1, 2002 (Reg. No. 333-85282)).

3.8

Amendment No. 2 to Amended and Restated Operating Agreement of Alliance Resource Management GP, LLC (Incorporated by reference to Exhibit 3.6 of the Registrant’s Registration Statement on Form S-3 filed with the Commission on April 1, 2002 (Reg. No. 333-85282)).

3.9

Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P. (Incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed with the Commission on August 1, 2006, File No. 000-26823).

*3.10

Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L. P. dated October 25, 2007.

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4.1

Form of Common Unit Certificate (Included as Exhibit A to the Second Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P.)

10.1

Credit Agreement, dated as of August 22, 2003, among Alliance Resource Operating Partners, L.P., JPMorgan Chase Bank (as paying agent), Citicorp USA, Inc. and JPMorgan Chase Bank (as co-administrative agents) and lenders named therein. (Incorporated by reference to Exhibit 10.41 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 000-26823).

10.2

Note Purchase Agreement, dated as of August 16, 1999, among Alliance Resource GP, LLC and the purchasers named therein. (Incorporated by reference to Exhibit 10.20 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 000-26823).

10.3

Letter of Credit Facility Agreement dated as of August 30, 2001, between Alliance Resource Partners, L.P. and Fifth Third Bank. (Incorporated by reference to Exhibit 10.23 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, File No. 000-26823).

10.4

Amendment No. 1 to Letter of Credit Facility Agreement between Alliance Resource Partners, L.P. and Fifth Third Bank. (Incorporated by reference to Exhibit 10.9 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 000-26823).

10.5

Guarantee Agreement, dated as of August 30, 2001, between Alliance Resource GP, LLC and Fifth Third Bank. (Incorporated by reference to Exhibit 10.24 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, File No. 000-26823).

10.6

Letter of Credit Facility Agreement dated as of October 2, 2001, between Alliance Resource Partners, L.P. and Bank of the Lakes, National Association. (Incorporated by reference to Exhibit 10.25 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, File No. 000-26823).

10.7

First Amendment to the Letter of Credit Facility Agreement between Alliance Resource Partners, L.P. and Bank of the Lakes, National Association. (Incorporated by reference to Exhibit 10.32 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, File No. 000-26823).

10.8

Promissory Note Agreement dated as of October 2, 2001, between Alliance Resource Partners, L.P. and Bank of the Lakes, N.A. (Incorporated by reference to Exhibit 10.26 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, File No. 000-26823).

10.9

Guarantee Agreement, dated as of October 2, 2001, between Alliance Resource GP, LLC and Bank of the Lakes, N.A. (Incorporated by reference to Exhibit 10.27 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, File No. 000-26823).

10.10

Guaranty Fee Agreement dated as of July 31, 2001, between Alliance Resource Partners, L.P. and Alliance Resource GP, LLC. (Incorporated by reference to Exhibit 10.28 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, File No. 000-26823).

10.11

Contribution and Assumption Agreement, dated August 16, 1999, among Alliance Resource Holdings, Inc., Alliance Resource Management GP, LLC, Alliance Resource GP, LLC, Alliance Resource Partners, L.P., Alliance Resource Operating Partners, L.P. and the other parties named therein. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 000-26823).

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10.12

Omnibus Agreement, dated August 16, 1999, among Alliance Resource Holdings, Inc., Alliance Resource Management GP, LLC, Alliance Resource GP, LLC and Alliance Resource Partners, L.P. (Incorporated by reference to Exhibit 10.4 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 000-26823).

10.13⁽¹⁾

Amended and Restated Alliance Coal, LLC 2000 Long-Term Incentive Plan. (Incorporated by reference to Exhibit 10.17 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 000-26823).

10.14⁽¹⁾

First Amendment to the Alliance Coal, LLC 2000 Long-Term Incentive Plan. (Incorporated by reference to Exhibit 10.18 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 000-26823).

10.15⁽¹⁾

Alliance Coal, LLC Short-Term Incentive Plan. (Incorporated by reference to Exhibit 10.12 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 000-26823).

10.16⁽¹⁾

Alliance Coal, LLC Supplemental Executive Retirement Plan. (Incorporated by reference to Exhibit 99.2 of the Registrant’s Registration Statement on Form S-8 filed with the Commission on April 1, 2002 (Reg. No. 333-85258)).

10.17

Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors. (Incorporated by reference to Exhibit 99.3 of the Registrant’s Registration Statement on Form S-8 filed with the Commission on April 1, 2002 (Reg. No. 333-85258)).

10.18

Restated and Amended Coal Supply Agreement, dated February 1, 1986, among Seminole Electric Cooperative, Inc., Webster County Coal Corporation and White County Coal Corporation. (Incorporated by reference to Exhibit 10.9 of the Registrant’s Registration Statement on Form S-1/A filed with the Commission on July 20, 1999 (Reg. No. 333-78845)).

10.19

Amendment No. 1 to the Restated and Amended Coal Supply Agreement effective April 1, 1996, between MAPCO Coal Inc., Webster County Coal Corporation, White County Coal Corporation, and Seminole Electric Cooperative, Inc. (Incorporated by reference to Exhibit 10.14 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2000, File No. 000-26823).

10.20

Amendment No. 4 dated October 25, 2005, between Seminole Electric Cooperative, Inc. and Webster County Coal, LLC (successor-in-interest to Webster County Coal Corporation), White County Coal, LLC (successor-in-interest to White County Coal Corporation), and Alliance Coal, LLC, as successor-in-interest to Mapco Coal, Inc. and agent for Webster County Coal, LLC and White County Coal, LLC, to the Coal Supply Agreement. (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K filed with the Commission on October 26, 2005, File No. 000-26823).

10.21

Guaranty by Alliance Coal, LLC dated October 25, 2005. (Incorporated by reference to Exhibit 10.28 of the Registrant’s Annual Report on Form 10-K filed with the Commission on March 16, 2006, File No. 000-26823).

10.22⁽²⁾

Financial Covenants Agreement dated October 25, 2005 by and between Seminole Electric Corporation, Inc. and Alliance Coal, LLC. (Incorporated by reference to Exhibit 10.29 of the Registrant’s Annual Report on Form 10-K filed with the Commission on March 16, 2006, File No. 000-26823).

10.23

Agreement for Supply of Coal to the Mt. Storm Power Station, dated January 15, 1996, between Virginia Electric and Power Company and Mettiki Coal Corporation. (Incorporated by reference to Exhibit 10. (t) to MAPCO Inc.’s Annual Report on Form 10-K, filed April 1, 1996, File No. 1-5254).

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10.24

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

10.25⁽²⁾

Amendment No. 1 to the Agreement for the supply of coal to Mt. Storm Power Station, made effective January 1, 2007, between Virginia Electric and Power Company and Alliance Coal, LLC. (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed with the Commission on February 20, 2007, File No. 000-26823).

10.26⁽²⁾

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

10.27⁽²⁾

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

10.28⁽²⁾

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

10.29⁽²⁾

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

10.30⁽²⁾

Feedstock Agreement No. 2, dated as of July 1, 2005, between Alliance Coal, LLC and Mount Storm Coal Supply, LLC. (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed with the Commission on August 5, 2005, File No. 000-26823).

10.31⁽²⁾

Memorandum of Understanding dated January 17, 2005 between VEPCO and Mettiki. (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed with the Commission on January 19, 2005, File No. 000-26823).

10.32⁽²⁾

Memorandum of Understanding, made effective January 1, 2007, between Virginia Electric and Power Company, and Alliance Coal, LLC, Mettiki Coal (WV), LLC and Mettiki Coal, LLC. (Incorporated by reference to Exhibit 10.33 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 000-26823).

10.33⁽²⁾

Amendment No. 1 dated January 17, 2005 between VEPCO and Mettiki to the Coal Supply Agreement. (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed with the Commission on January 19, 2005, File No. 000-26823).

10.34

Coal Feedstock Supply Agreement dated October 26, 2001, between Synfuel Solutions Operating LLC and Hopkins County Coal, LLC (Incorporated by reference to Exhibit 10.27 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001, File No. 000-26823).

10.35

First Amendment to Coal Feedstock Supply Agreement dated February 28, 2002, between Synfuel Solutions Operating LLC and Hopkins County Coal, LLC (Incorporated by reference to Exhibit 10.28 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001, File No. 000-26823).

10.36⁽²⁾

Second Amendment to Coal Feedstock Supply Agreement dated April 1, 2003, between Synfuel Solutions Operating LLC and Warrior Coal, LLC. (Incorporated by reference to Exhibit 10.40 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, File No. 000-26823).

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10.37

Assignment and Assumption Agreement dated April 1, 2003 between Synfuel Solutions Operating LLC, Hopkins County Coal, LLC, and Warrior Coal, LLC. (Incorporated by reference to Exhibit 10.31 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 000-26823).

10.38

Letter Agreement dated January 31, 2003 between ARH Warrior Holdings, Inc. and Alliance Resource Partners, L.P. (Incorporated by reference to Exhibit 10.34 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 File No. 000-26823).

10.39⁽¹⁾

Consulting Agreement for Mr. Sachse dated January 1, 2001. (Incorporated by reference to Exhibit 10.18 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2000, File No. 000-26823).

10.40⁽¹⁾

Extension of Consulting Agreement with Mr. Sachse, dated September 30, 2003. (Incorporated by reference to Exhibit 10.42 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 000-26823).

*10.41

Amended and Restated Charter for the Audit Committee of the Board of Directors dated February 22, 2008.

10.42

Amended and Restated Credit Agreement, dated as of April 13, 2006, among Alliance Resource Operating Partners, L.P. as Borrower and the Initial Lenders, Initial Issuing Banks and Swing Line Bank and JPMorgan Chase Bank, N.A. as Paying Agent and Citicorp USA, Inc. and JP Morgan Chase Bank, N.A. as Co-Administrative Agents and Citigroup Global Markets Inc. and J.P. Morgan Securities Inc. as Joint Lead Arrangers and Joint Bookrunners (Incorporated by reference to Exhibit 99.1 of the Registrant’s Current Report on Form 8-K filed with the Commission on April 18, 2006, File No. 000-26823)

10.43

Amendment No. 2 to Letter of Credit Facility Agreement between Alliance Resource Partners, L.P. and Fifth Third Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed with the Commission on May 16, 2006, File No. 000-26823).

10.44

The termination of Guarantee Agreement, dated as of April 24, 2006, between Alliance Resource GP, LLC and Fifth Third Bank (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed with the Commission on May 16, 2006, File No. 000-26823).

10.45

Second Amendment to the Omnibus Agreement dated May 15, 2006 by and among Alliance Resource Partners, L.P., Alliance Resource GP, LLC, Alliance Resource Management GP, LLC, Alliance Resource Holdings, Inc., Alliance Resource Holdings II, Inc., AMH-II, LLC, Alliance Holdings GP, L.P., Alliance GP, LLC and Alliance Management Holdings, LLC. (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, File No. 000-26823)

10.46

Administrative Services Agreement dated May 15, 2006 among Alliance Resource Partners, L.P., Alliance Resource Management GP, LLC, Alliance Resource Holdings II, Inc., Alliance Holdings GP, L.P. and Alliance GP, LLC. (Incorporated by reference to Exhibit 10.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, File No. 000-26823)

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10.47⁽²⁾

Restated and Amended Feedstock Agreement No. 2, dated June 1, 2006, between Alliance Coal, LLC and Mount Storm Coal Supply, LLC (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed with the Commission on July 13, 2006, File No. 000-26823)

*10.48

Amended and Restated Charter for the Compensation Committee of the Board of Directors dated February 22, 2008.

10.49⁽¹⁾

First Amendment to the Amended and Restated Alliance Coal, LLC Supplemental Executive Retirement Plan (Incorporated by reference to Exhibit 10.50 of the Registrant’s Annual Report on Form 10-K filed with the Commission on March 1, 2007, File No. 000-26823).

*10.50⁽¹⁾

Second Amendment to the Amended and Restated Alliance Coal, LLC Supplemental Executive Retirement Plan.

10.51⁽¹⁾

Second Amendment to the Amended and Restated Alliance Coal, LLC Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.51 of the Registrant’s Annual Report on Form 10-K filed with the Commission on March 1, 2007, File No. 000-26823).

10.52⁽¹⁾

First Amendment to the Alliance Coal, LLC Short-Term Incentive Plan (Incorporated by reference to Exhibit 10.52 of the Registrant’s Annual Report on Form 10-K filed with the Commission on March 1, 2007, File No. 000-26823).

*10.53⁽¹⁾

Second Amendment to the Alliance Coal, LLC Short-Term Incentive Plan.

10.54

First Amendment to the Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors (Incorporated by reference to Exhibit 10.53 of the Registrant’s Annual Report on Form 10-K filed with the Commission on March 1, 2007, File No. 000-26823).

*10.55

Second Amendment to the Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors.

10.56

Second Amended and Restated Credit Agreement, dated as of September 25, 2007, among Alliance Resource Operating Partners, L.P. as Borrower and the Initial Lenders, Initial Issuing Banks and Swing Line Bank and J.P. Morgan Chase Bank, N.A. as Paying Agent and Citicorp USA, inc. and JP Morgan Chase Bank, N.A. as Co-Administrative Agents and Citigroup Global markets Inc. and J.P. Morgan Securities Inc. as Joint Lead Arrangers and Joint Bookrunners (Incorporated by reference to Exhibit 99.1 of the Registrant’s Current Report on Form 8-K filed with the Commission on September 27, 2007, File No. 000-26823).

18.1

Preferability Letter on Accounting Change. (Incorporated by reference to Exhibit 18.1 of the Registrant’s Amended Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2001, File No. 000-26823).

*21.1

List of Subsidiaries.

*23.1

Consent of Deloitte & Touche LLP regarding Form S-3 and Form S-8, Registration Statements No. 333-85282 and 333-85258, respectively.

*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 February 29, 2008, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*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 February 29, 2008, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

126

*32.1

*32.2

Filed herewith.

(1)	Denotes management contract or compensatory plan or arrangement.

(2)	Portions of this exhibit have been omitted pursuant to a request for confidential treatment under Rule 24b-2 of the Securities Exchange Act of 1934, as amended, and the omitted material has been separately filed with the Securities and Exchange Commission.

127

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 February 29, 2008.


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

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ Joseph W. Craft III Joseph W. Craft III	President, Chief Executive Officer, and Director (Principal Executive Officer)	February 29, 2008
/s/ Joseph W. Craft III Joseph W. Craft III		February 29, 2008

/s/ Brian L. Cantrell Brian L. Cantrell	Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	February 29, 2008
/s/ Brian L. Cantrell Brian L. Cantrell		February 29, 2008

/s/ Merribel S. Ayres	Director	February 29, 2008
Merribel S. Ayres

/s/ Michael J. Hall	Director	February 29, 2008
Michael J. Hall

/s/ John P. Neafsey	Director	February 29, 2008
John P. Neafsey

/s/ John H. Robinson	Director	February 29, 2008
John H. Robinson

/s/ Wilson M. Torrence	Director	February 29, 2008
Wilson M. Torrence

128