Form 10-K
Table of Contents

 

 

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, 2009

OR

 

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

FOR THE TRANSITION PERIOD FROM              TO             

COMMISSION FILE NO.: 0-26823

 

 

ALLIANCE RESOURCE PARTNERS, L.P.

(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

 

DELAWARE   73-1564280

(STATE OR OTHER JURISDICTION OF

INCORPORATION OR ORGANIZATION)

 

(IRS EMPLOYER

IDENTIFICATION NO.)

1717 SOUTH BOULDER AVENUE, SUITE 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   The 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.    ¨  Yes    x  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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    ¨  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.    x

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 the 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   ¨

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 $665,739,100 as of June 30, 2009, 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 26, 2010, 36,716,855 common units were outstanding.

 

 

DOCUMENTS INCORPORATED BY REFERENCE:

None

 

 

 


Table of Contents

TABLE OF CONTENTS

 

         Page
PART I
Item 1.   Business    1
Item 1A.   Risk Factors    19
Item 1B.   Unresolved Staff Comments    35
Item 2.   Properties    36
Item 3.   Legal Proceedings    39
Item 4.   Submission of Matters to a Vote of Securities Holders    39
PART II
Item 5.   Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities    40
Item 6.   Selected Financial Data    41
Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations    43
Item 7A.   Quantitative and Qualitative Disclosures about Market Risk    69
Item 8.   Financial Statements and Supplementary Data    71
Item 9.   Changes in and Disagreements with Accountant on Accounting and Financial Disclosure    105
Item 9A.   Controls and Procedures    105
Item 9B.   Other Information    108
PART III
Item 10.   Directors, Executive Officers and Corporate Governance of the Managing General Partner    109
Item 11.   Executive Compensation    114
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters    128
Item 13.   Certain Relationships and Related Transactions, and Director Independence    129
Item 14.   Principal Accountant Fees and Services    131
PART IV
Item 15.   Exhibits and Financial Statement Schedules    132

 

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FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”) that 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;

 

   

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

 

   

risks associated with the expansion of our operations and properties;

 

   

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

 

   

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

 

   

weakness in global economic conditions or in industries in which our customers operate;

 

   

liquidity constraints, including those resulting from the cost or unavailability of financing due to current capital market conditions;

 

   

customer bankruptcies, cancellations or breaches to existing contracts, or other failures to perform;

 

   

customer delays, failure to take coal under contracts or defaults in making payments;

 

   

adjustments made in price, volume or terms to existing coal supply agreements;

 

   

fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment availability, governmental regulations, including those related to carbon dioxide emissions, and other factors;

 

   

legislation, regulatory and court decisions and interpretations thereof, including issues related to climate change and miner health and safety;

 

   

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

 

   

greater than expected increases in raw material costs;

 

   

greater than expected shortage of skilled labor;

 

   

our ability to maintain satisfactory relations with our employees;

 

   

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

 

   

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

 

   

greater than expected environmental regulation, costs and liabilities;

 

   

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

 

   

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

 

   

results of litigation, including claims not yet asserted;

 

   

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

 

   

difficulty in making accurate assumptions and projections regarding pension and other post-retirement benefit liabilities;

 

   

coal market’s share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of alternative sources of energy, such as natural gas, nuclear energy and renewable fuels;

 

   

replacement of coal reserves;

 

   

a loss or reduction of benefits from certain tax credits;

 

   

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

 

   

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

 

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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 Securities and Exchange Commission (“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.

 

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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 (“U.S.”) utilities and industrial users. We began mining operations in 1971 and, since then, have grown through acquisitions and internal development to become what we believe to be the fifth largest coal producer in the eastern U.S. At December 31, 2009, we had approximately 647.2 million tons of coal reserves in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia. In 2009, we produced 25.8 million tons of coal and sold 25.0 million tons of coal, of which 10.1% was low-sulfur coal, 22.5% was medium-sulfur coal and 67.4% was high-sulfur coal. In 2009, we sold 91.8% of our total tons to electric utilities, of which 88.6% was sold to utility plants with installed pollution control devices. These devices, also known as scrubbers, eliminate substantially all emissions of 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%.

We operate nine underground mining complexes in Illinois, Indiana, Kentucky, Maryland, and West Virginia. We are constructing a new mining complex in West Virginia, and we also operate 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 and a Director 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.

 

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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 owns and is the 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 (“IDR”) in ARLP and 15,544,169 common units of ARLP. The following diagram depicts our organization and ownership as of December 31, 2009:

LOGO

 

(1) The Management Group comprises current and former members of our management, who are the former indirect owners of MGP, and their affiliates.
(2) The units held by SGP 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 Mr. Craft 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 free of charge on our 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 SEC. 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.

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.

 

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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

   2009    2008    2007    2006    2005
     (tons in millions)

Illinois Basin:

              

Dotiki, Warrior, Pattiki, Hopkins, River View and Gibson complexes

   20.7    20.3    17.9    16.9    15.7

Central Appalachian:

              

Pontiki and MC Mining complexes

   2.6    3.2    3.2    3.5    3.3

Northern Appalachian:

              

Mettiki complex

   2.5    2.9    3.2    3.3    3.3
                        

Total

   25.8    26.4    24.3    23.7    22.3
                        

The following map shows the location of our mining complexes and projects:

LOGO

 

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Illinois Basin Operations

Our Illinois Basin mining operations are located in western Kentucky, southern Illinois and southern Indiana. We currently have approximately 2,230 employees and operate six mining complexes in the Illinois Basin.

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 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 directly to customers or to various transloading facilities, including our Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) transloading facility, for sale to customers capable of receiving barge deliveries.

Warrior Complex. Our subsidiary, Warrior Coal, LLC (“Warrior”), operates 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 new preparation plant became operational in the first quarter of 2009 and has throughput capacity of 1,200 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 directly to customers or to various transloading facilities, including our Mt. Vernon transloading facility, for sale to customers capable of receiving barge deliveries.

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. The Pattiki complex utilizes continuous mining units employing room-and-pillar mining techniques to produce high-sulfur coal. The preparation plant has 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 directly to customers or to various transloading facilities, including our Mt. Vernon transloading facility, for sale to customers capable of receiving barge deliveries.

Hopkins Complex. The Hopkins complex, which we acquired in January 1998, is located near the city of Madisonville in Hopkins County, Kentucky. It is operated by our subsidiary, Hopkins County Coal, LLC (“Hopkins County Coal”). During 2006, Hopkins County Coal ceased production from its Newcoal surface mine, which is being reclaimed, and began operations at its Elk Creek underground mine using continuous mining units employing room-and-pillar mining techniques to produce high-sulfur coal. Coal produced from the Elk Creek mine is processed and shipped through Hopkins County Coal’s preparation plant, which has throughput capacity of 1,200 tons of raw coal an hour. Elk Creek’s production can be shipped via the CSX and PAL railroads and by truck on U.S. and state highways directly to customers or to various transloading facilities, including our Mt. Vernon transloading facility, for sale to customers capable of receiving barge deliveries.

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 medium-sulfur coal. The preparation plant has throughput capacity of 700 tons of raw coal an hour. Production from Gibson is either shipped by truck on U.S. and state highways or transported by rail on CSX and Norfolk Southern Railway Company (“NS”) railroads directly to customers or to various transloading facilities, including our Mt. Vernon transloading facility, for sale to customers capable of receiving barge deliveries. 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. See “Gibson South Reserves” discussed below.

River View Complex. In April 2006, we acquired River View Coal, LLC (“River View”) from ARH. River View currently controls, through coal leases or direct ownership, approximately 120.8 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. In July 2007, we began construction of the mining complex and production began in August 2009. River View is an underground mining complex that, at full capacity, will have the capability of annually producing approximately 6.4 million tons utilizing eight continuous mining units employing room-and-pillar mining techniques. River View’s

 

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preparation plant has throughput capacity of 1,800 tons of raw coal per hour. Coal produced from the River View mine is transported by overland belt to a barge loading facility on the Ohio River (mile marker 843). Total capital expenditures required to develop the River View mine to full capacity are estimated to range from approximately $250 million to $275 million, of which $199.5 million has been incurred as of December 31, 2009. These amounts exclude capitalized interest and capitalized mine development costs associated with 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.”)

Gibson South Reserves. We have partially completed the permitting process for the Gibson South reserves and we continue to evaluate development of the project. (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.”) Development of the project continues to be market dependent, and its timing is open-ended pending sufficient coal sales commitments to support the project. We expect the mine to be developed as an underground mining complex using continuous mining units employing room-and-pillar techniques, and to have annual production capacity of approximately 3.0 million to 3.5 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”).

Central Appalachian Operations

Our Central Appalachian mining operations are located in eastern Kentucky. We currently have approximately 440 employees and operate two mining complexes in Central Appalachia.

Pontiki Complex. The Pontiki complex is located near the city of Inez in Martin County, Kentucky. We constructed the mine in 1977. Our subsidiary, Pontiki Coal, LLC (“Pontiki”), owns the mining complex and controls the reserves, and our subsidiary, Excel Mining, LLC (“Excel”), conducts all mining operations. The underground operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal. The preparation plant has throughput capacity of 900 tons of raw coal an hour. Coal produced in 2009 remained low sulfur, but does not meet 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 via the NS railroad directly to customers or to various transloading facilities on the Ohio River for sale to customers capable of receiving barge deliveries, or by truck via U.S. and state highways directly to customers or to various docks on the Big Sandy River for shipment to customers capable of receiving barge deliveries. In 2009, we idled one of the Pontiki production units due to weak coal market conditions.

MC Mining Complex. The MC Mining complex is located near the city of Pikeville in Pike County, Kentucky. We acquired the mine in 1989. Our subsidiary, MC Mining, LLC (“MC Mining”), owns the mining complex and leases the reserves, and Excel conducts all mining operations. The underground operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal. The preparation plant has throughput capacity of 1,000 tons of raw coal an hour. Substantially all of the coal produced at MC Mining in 2009 met or exceeded the compliance requirements of Phase II of the CAA (see “—Regulation and Laws—Air Emissions” below). Coal produced from the mine is shipped via the CSX railroad directly to customers or to various transloading facilities on the Ohio River for sale to customers capable of receiving barge deliveries, or by truck via U.S. and state highways directly to customers or to various docks on the Big Sandy River for shipment to customers capable of receiving barge deliveries.

Northern Appalachian Operations

Our Northern Appalachian mining operations currently employ approximately 250 employees and are located in Maryland and West Virginia. We operate one mining complex and have one mining complex under construction 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) on properties controlled by Mettiki (MD) and another of our subsidiaries, Backbone Mountain, LLC, supplements the Mettiki (WV) production, providing blending optimization and allowing the operation to take advantage of market opportunities as they arise. The surface strip mine was idled for part of 2009 due to weak coal market conditions.

 

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Our Mettiki (MD) preparation plant has 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 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 ship into 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. The Mountain View mine produces medium-sulfur coal which is transported by truck either to the Mettiki (MD) preparation plant (which is served by CSX) or to the coal blending facility at the VEPCO Mt. Storm Power Station.

Tunnel Ridge Complex. Our subsidiary, Tunnel Ridge, LLC (“Tunnel Ridge”), controls, through a coal lease agreement with our special general partner, approximately 70.2 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 to Tunnel Ridge by the West Virginia Department of Environmental Protection on February 12, 2007, and we either have received or have applications pending for all permits necessary to conduct operations. (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.”) In September of 2008, our Board of Directors gave final approval for development of the reserves, and Tunnel Ridge has begun construction of the mining complex, which will be an underground, longwall mine. Capital expenditures required for development are estimated to be in the range of approximately $285 million to $300 million, of which $92.7 million has been incurred as of December 31, 2009. These amounts exclude capitalized interest and capitalized mine development costs associated with 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.”) We expect to begin longwall mining operations at Tunnel Ridge in the second half of 2011, and we expect annual production capacity of the mine to be approximately 5.5 to 6.0 million tons. Beginning in the second quarter of 2010, we anticipate incidental production of approximately 20,000 to 40,000 tons per month during the mine development phase increasing to approximately 100,000 tons per month of incidental production in 2011 until longwall mining and full production begins later in 2011.

Penn Ridge. Our subsidiary, Penn Ridge Coal, LLC (“Penn Ridge”), is party to a coal lease agreement effective December 31, 2005 with Allegheny Pittsburgh Coal Company (“Allegheny”), pursuant to which Penn Ridge leases Allegheny’s Buffalo coal reserve in Washington County, Pennsylvania, which is estimated to include approximately 56.7 million tons of proven and probable high-sulfur coal in the Pittsburgh No. 8 seam. Penn Ridge has initiated the permitting process for the Buffalo coal reserves and continue to evaluate development. (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.”) Development of the project continues to be market dependent, and its timing is open-ended pending sufficient coal sales commitments to support the project. It is expected that these reserves will be developed as an underground mining complex using either continuous mining units employing room-and-pillar techniques, longwall mining, or both. We expect the annual production capacity of the Penn Ridge mine to be approximately 2.5 to 3.0 million tons utilizing continuous mining units or up to 5.0 million tons with longwall mining. Definitive development commitment for Penn Ridge is dependent upon final approval by our Board of Directors.

Other Operations

Mt. Vernon Transfer Terminal, LLC

Our subsidiary, 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 2009, the terminal loaded approximately 2.9 million tons for customers of Pattiki, Gibson, Elk Creek, and for third parties.

 

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Coal Brokerage

As markets allow, we buy coal from non-affiliated producers principally throughout the eastern U.S., which we then resell. We have a policy of matching our outside coal purchases and sales to minimize market risks associated with buying and reselling coal. In 2009, we sold 13,497 tons classified as brokerage coal in our financial results.

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 2009, 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 in 2009 and historically have represented less than one percent of our total revenues. In addition, our affiliate, Mid-America Carbonates, LLC (“MAC”), which is a joint venture in which White County Coal participates, manufactures and sells rock dust to us and to unrelated parties. In 2009, our financial results were not significantly impacted by MAC’s business. Please read “Item 8. Financial Statements and Supplementary Data—Note 18. Noncontrolling Interest.”

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 22. Segment Information” for information concerning our reportable segments.

Synfuel Facilities

For several years, three of our mining complexes—the Warrior Complex and the Gibson Complex in the Illinois Basin Region and the Mettiki Complex in the Northern Appalachian Region—supplied coal feedstock and provided services to third-party coal synfuel facilities located at or near these complexes. Our agreements with those third-parties terminated on December 31, 2007 coincident with the expiration of the federal non-conventional source fuel tax credit and, as a result, we no longer supply feedstock or provide services to those facilities. In 2007, the incremental net income benefit to us from these synfuel-related agreements was approximately $28.5 million.

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 2009, approximately 92.6% and 91.1% 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 committed term expirations ranging from 2010 to 2016. Our total nominal commitment under significant long-term contracts for existing operations was approximately 138.7 million tons at December 31, 2009, and is expected to be delivered as follows: 29.2 million tons in 2010, 26.9 million tons in 2011, 20.4 million tons in 2012, and 62.2 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 typically sufficient to allow us to balance our sales commitments with prospective production capacity. In addition, the nominal total commitment can otherwise change because of reopener provisions contained in certain of these long-term contracts.

 

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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 transportation of coal, 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 four largest customers in 2009 were Louisville Gas and Electric Company, VEPCO, Seminole Electric Cooperative, Inc and Tennessee Valley Authority. During 2009, we derived approximately 41.8% of our total revenues from these four customers and at least 10.0% of our total revenues from each of the four. For more information about these customers, please read “Item 8. Financial Statements and Supplementary Data—Note 21. Concentration of Credit Risk and Major Customers.”

Competition

The coal industry is intensely competitive. The most important factors on which we compete are coal price, 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., 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. The prices we are able to obtain for our coal are primarily linked to coal consumption patterns of domestic electricity generating utilities, which in turn are influenced by economic activity, government regulations, weather and technological developments. Additionally, coal competes with other fuels such as petroleum, natural gas, nuclear energy and renewable energy sources for 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. For additional information, please see “Item 1A. Risk Factors”. As the price of domestic coal increases, we may also begin to compete with companies that produce coal from one or more foreign countries.

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 3.0% to 55.0% 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 multiple transportation options. Typically, our customers pay the transportation costs from the mining complex to the destination, which is the standard practice in the industry. Approximately 76.1% of our 2009 sales volume was initially shipped from the mines by rail with the remainder leaving the mines by truck or barge. In 2009, the largest volume transporter of our coal shipments was the CSX, which moved approximately 37.0% of our tonnage over its rail system. The practices of, and rates set by, the transportation company serving a particular mine or customer may affect, either adversely or favorably, our marketing efforts with respect to coal produced from the relevant mine.

 

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Regulation and Laws

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

 

   

employee health and safety;

 

   

mine permits and other licensing requirements;

 

   

air quality standards;

 

   

water quality standards;

 

   

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

 

   

plant and wildlife protection;

 

   

reclamation and restoration of mining properties after mining is completed;

 

   

the discharge of materials into the environment;

 

   

storage and handling of explosives;

 

   

wetlands protection;

 

   

surface subsidence from underground mining; and

 

   

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 all of the costs of compliance with applicable federal and state laws and 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.

 

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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.

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. The Mine Safety and Health Administration (“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. Although many of the requirements primarily impact underground mining, our competitors in all of the areas in which we operate are subject to the same laws and regulations.

In 2006, the Federal Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”) was enacted. The MINER Act significantly amended the FMSHA, imposing more extensive and stringent compliance standards, 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 has issued new or more stringent rules and policies on a variety of topics, including:

 

   

sealing off abandoned areas of underground coal mines;

 

   

mine safety equipment, training and emergency reporting requirements;

 

   

substantially increased civil penalties for regulatory violations;

 

   

training and availability of mine rescue teams;

 

   

underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;

 

   

flame-resistant conveyor belt, fire prevention and detection, and use of air from the belt entry; and

 

   

post-accident two-way communications and electronic tracking systems.

Subsequent to passage of the MINER Act, Illinois, Kentucky, Pennsylvania and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Other states may pass similar legislation in the future. Also, additional federal legislation that would have imposed additional safety and health requirements on coal mining was introduced in the 110th Congress, but did not become law. Although the same or similar legislation has not been introduced in the current 111th Congress, it could be introduced at any time. In addition, MSHA continues to interpret and implement various provisions of the MINER Act. Although we are unable to quantify the full impact, implementing and complying with these new laws and regulations have had, and are expected to continue to have, an adverse impact on our results of operation and financial position.

 

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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. Although we have minimal surface mining activity and no mountaintop removal mining activity, SMCRA nevertheless requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of our 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 tax for surface-mined and underground-mined coal is $0.315 per ton and $0.135 per ton, respectively, 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. Please read “Item 8. Financial Statements and Supplementary Data.—Note 16. Asset Retirement Obligations.” 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.

 

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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. 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.

On June 11, 2009, the U.S. Department of the Interior, the U.S. Army Corps of Engineers (“Corps of Engineers”) and the U.S. Environmental Protection Agency (“EPA”) issued a Memorandum of Understanding (“MOU”) setting forth an Interagency Action Plan on Appalachian Surface Coal Mining to “significantly reduce the harmful environmental consequences of Appalachian surface coal mining operations, while ensuring that future mining remains consistent with federal law.” Pursuant to the MOU, the Office of Surface Mining Reclamation and Enforcement (“OSM”) intends to “reevaluate and determine how it will more effectively conduct oversight of state permitting, state enforcement, and regulatory activities under SMCRA.” In a statement issued on its oversight review, the OSM specifically noted that while the MOU applies only to six Appalachian states, any changes it makes to its oversight policy will apply nationwide. Among the immediate actions OSM has indicated it plans to take are more oversight inspections, articulation of OSM authority to conduct inspections without prior notification to the state, evaluation of oversight data collection, analysis, and reporting requirements and methodologies, review of more state-issued permits and state permitting procedures, and development of a national geographic information system with data on coal mining and reclamation activities. We are unable to predict the impact, if any, of such actions by the OSM, although the actions could result in additional delays in obtaining permits and additional enforcement action, as a result of increased inspections.

Bonding Requirements

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.

Air Emissions

The CAA and similar state and local laws and regulations regulate emissions into the air and 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, achieve certain emissions standards, or implement certain work practices 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 and other coal-burning facilities. 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 laws and EPA regulations will make it more costly to operate coal-fired power plants and 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.

 

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The EPA has promulgated rules, referred to as the “Nitrogen Oxide SIP Call,” that, among other things, 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 permanently capped nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. beginning in 2009 and 2010, respectively. CAIR required these states to achieve the mandated nitrogen oxide and sulfur dioxide emission reductions by requiring power plants to either participate in an EPA-administered “cap-and-trade” program that capped 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 established a two-part, nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. If it had been fully implemented, the CAMR would have permitted 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 were both the subject of successful legal challenges, however, which have rendered the future of these rules uncertain. On February 8, 2008, the D.C. Circuit Court of Appeals vacated the CAMR rule for further consideration by the EPA. In response to that ruling, the EPA is developing, and has stated that it intends to propose by March 10, 2011, air toxics standards for coal- and oil-fired generating units. On December 24, 2009, the EPA approved an Information Collection Request requiring power plants to submit emissions information for use in developing those standards. In addition, on July 11, 2008, the D.C. Circuit Court of Appeals vacated the CAIR, but on petition for rehearing, the court retracted its vacatur and remanded the rule to the EPA for further consideration. This remand has the effect of leaving the rule in place while the EPA evaluates possible changes to the rule to correct the defects identified in the court’s original opinion. While the futures of the CAIR and CAMR are uncertain, the EPA may require a significant amount of emissions reductions at coal-fired power generation facilities in replacing those rules. The additional costs that could be associated with the implementation of any rules could make coal a less attractive fuel source.

The EPA is required by the CAA to periodically re-evaluate the available health effects information to determine whether the national ambient air quality standards should be revised. Pursuant to this process, in 2006, the EPA adopted a more stringent national air quality standard for fine particulate matter: in 2008, the EPA adopted a more stringent national ambient air quality standard for ozone, and in January 2010, the EPA adopted a more stringent national air quality standard for nitrogen oxide. 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 and other states will be required to develop new state implementation plans for areas that were previously in “attainment” but do not attain the new standards. States are expected to submit their implementation plans for meeting the new fine particulate matter standard to the EPA over the next two years, and their implementation plans for meeting the new ozone standard over the next four years. By January 2012, the EPA expects to make an initial classification of areas as either in attainment or nonattainment regarding the new nitrogen dioxide standard or as unclassifiable. When sufficient data from the rule’s new monitoring requirements becomes available after 2015, the EPA will then reclassify previously unclassifiable areas as in attainment or nonattainment. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and nitrogen oxides, which are precursors to ozone formation, 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. Most states missed the December 2007 deadline, and on January 9, 2009, the EPA issued a Finding of Failure to Submit State Implementation Plans, which may trigger Federal enforcement plans in some states. 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.

 

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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, and still more lawsuits may be filed. Depending on the ultimate resolution of these cases, demand for our coal could be affected.

Carbon Dioxide Emissions

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide into the atmosphere. The U.S. Congress is considering legislation to reduce emissions of greenhouse gases. On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” (“ACESA”), which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions. President Obama has expressed support for legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. Depending on the particular regulatory program that could apply, at either the federal or state level, our customers could be required to purchase and surrender allowances for greenhouse gas emissions resulting from their operations or install emission control equipment to reduce emissions of greenhouse gases. These requirements could increase our customers’ operational and compliance costs and result in reduced demand for our coal products and have an adverse effect on our operations.

Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts v. EPA that greenhouse gases including carbon dioxide fall under the federal CAA definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources. In September 2009, the EPA published a proposed rule to regulate greenhouse gas emissions for light-duty vehicles under the CAA, in response to the Supreme Court’s decision in Massachusetts. On December 15, 2009, the EPA published its finding that greenhouse gas emissions, including carbon dioxide and methane, endanger public health and welfare and that greenhouse gases emitted by motor vehicles contribute to that endangerment (“Endangerment Finding”). The EPA’s Endangerment Finding does not impose greenhouse gas controls on its own, but is a necessary prerequisite to further regulatory action under the CAA to control greenhouse gas emissions from sources, in particular mobile sources. Several groups have filed Petitions for Reconsideration asking the EPA to reconsider the Endangerment Finding based on developments occurring after the end of the public comment period for the Endangerment Finding. Further, several groups have filed Petitions for Review asking the United States Court of Appeals for the District of Columbia Circuit to review the legality of the EPA’s Endangerment Finding.

The EPA has indicated that it expects to issue final greenhouse gas emission standards for light-duty vehicles in March 2010. Once these rules are finalized and actual greenhouse gases become subject to regulation under the CAA, then another CAA program – the prevention of significant deterioration (“PSD”) program – could require certain stationary sources, including coal-fired power plants, to obtain permits prior to construction and modification and to implement best available control technology. In another, related rulemaking, the so-called “tailoring rule,” the EPA has proposed to exclude thousands of smaller stationary sources by limiting the reach of the PSD program for greenhouse gas emissions to sources that emit more than 25,000 tons of carbon dioxide equivalent, rather than to sources that emit 100 or 250 tons per year according to statutory limits. At the same time, the EPA is proposing to limit the reach of the CAA’s Title V permitting program to sources that emit 25,000 tons of carbon dioxide equivalent per year, rather than 100 tons per year, as set forth under the statute. Although these EPA rules may be subject to litigation, if greenhouse gases become subject to PSD regulation, these requirements could increase our customers’ operational and compliance costs and result in reduced demand for our coal products, and have an adverse effect on our operations. Measures to control and regulate carbon dioxide emissions could increase the costs of our coal mining and processing operations.

In addition, on October 30, 2009, the EPA issued the Final Mandatory Reporting of Greenhouse Gases Rule requiring all stationary sources that emit more than 25,000 tons of greenhouse gases per year to collect and report to the EPA data regarding such emissions. This rule affects many of our customers, as well as our Mettiki (MD) mining complex where we operate a coal-fired stationary source thermal dryer to process coal.

 

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In December 2009, the U.S. joined other countries in negotiating the Copenhagen Accord, a nonbinding agreement that allows countries to commit to specific efforts to reduce greenhouse gas emissions, although how and when the commitment may be converted into binding emission reduction obligations is currently uncertain. Those specific efforts must be brought forward during 2010 and established officially in the Copenhagen Accord. In addition, the terms of the Copenhagen Accord include a system of monitoring the progress being made in the reduction of greenhouse gas emissions.

In addition, there have been an increasing number of protests of and challenges to the permitting of new coal-fired power plants in several states by environmental organizations for concerns related to greenhouse gas emissions from new plants. Environmental permitting agencies in several states have denied permits for construction of new coal-fired power plants based on concerns over emissions of greenhouse gases. In November 2008, the federal Environmental Appeals Board remanded a CAA permitting decision in the In re Deseret Power Electric Cooperative case for reconsideration of whether carbon dioxide is a pollutant subject to regulation under the CAA with instructions to consider its nationwide implications. In response to this decision, in December 2008, the EPA Administrator issued an interpretive rule determining that carbon dioxide is not subject to regulation under the CAA. Environmental groups filed a Petition for Reconsideration of the interpretive rule. On February 17, 2009, the EPA granted the Petition for Reconsideration and sought public comment on the interpretive memorandum as well as the Deseret decision. In granting the petition, the EPA emphasized that the memorandum does not bind states issuing air permits under their own State Implementation Plans. If the EPA regulates greenhouse gas emissions of light-duty vehicles, as discussed above, the “subject to regulation” dispute will be resolved in that such emissions will become regulated under the CAA. Other lawsuits regarding the permitting of coal-fired power plants have challenged, and are expected to continue to challenge, how permitting authorities such as the EPA or states consider what is “best available control technology” for greenhouse gases, which may result in delays or difficulties in obtaining permits. The increased difficulty or inability of our customers to obtain permits for construction of new or expansion of existing coal-fired power plants could adversely affect our operations and demand for our products.

It is possible that future international, 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, or otherwise adversely affect our operations and demand for our products, 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 U.S. 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 Corps of Engineers maintains two permitting programs under CWA Section 404 for the discharge of dredged or fill material: one for “individual” permits and a more streamlined program for “general” permits.

Decisions as a result of litigation filed in the federal district court for the Southern District of West Virginia, and related litigation filed in federal district court in Kentucky, have created uncertainty regarding the future ability to obtain general permits, including Nationwide Permit 21, authorizing the construction of valley fills for the disposal of overburden from mining operations. We do not operate any mines located within the Southern District of West Virginia and currently utilize Nationwide Permit 21 at limited locations. Litigation over the validity of Nationwide Permit 21 is ongoing. In November 2009, pursuant to the MOU, the

 

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Corps of Engineers published a proposal to modify or suspend the use of Nationwide Permit 21 in connection with surface coal mining activities in the Appalachian region. If challenges to the use of Nationwide Permit 21 ultimately are successful, or if Nationwide Permit 21 is modified or suspended, 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. State and federal legislation that would prohibit or restrict the use of Section 404 permits for the discharge of overburden from certain mining operations or otherwise limit mountaintop mining also has been proposed. If such legislation were to pass, the disposal of overburden could be regulated in a more stringent and costly manner, or there could be other restrictions or additional costs, delays, or other regulatory burdens placed on our operations.

In addition, litigation has been filed in West Virginia and Kentucky challenging the issuance of individual Section 404 permits for mining activities by other coal producers. 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 Section 404 permits could adversely affect our ability to obtain permits in a timely manner and could therefore adversely affect our results of operations and financial position.

A number of other ongoing and proposed regulatory and legislative initiatives also could adversely affect our ability to obtain required permits in a timely manner. The June 11, 2009 interagency MOU set forth Enhanced Coordination Procedures for the review of applications for CWA Section 404 permits for surface coal mining activities in Appalachia. In September 2009, the EPA identified 79 projects that required further, detailed environmental review of their pending permit applications under these procedures. Although none of our projects were subjected to additional review, the enhanced review procedures indicate that obtaining Section 404 permits could become more difficult, time-consuming, and costly.

In addition, the OSM published in November 2009, an Advance Notice of Proposed Rulemaking and announced its intent to revise the Stream Buffer Zone (“SBZ”) rule published in December 2008. The SBZ rule sets forth conditions under which mining activities may be conducted in or near perennial or intermittent streams. The OSM also announced a series of measures that it intends to implement immediately, until the revisions to the SBZ rule are finalized, including: (1) mandatory coordination of review and approval of SMCRA permits with those required under the CWA; (2) meetings in each state with appropriate state and federal agencies regarding the coordination of SMCRA and CWA permitting and authorization; and (3) specific direction to OSM inspectors to focus on particular standards and permit conditions when conducting oversight inspections, including, among other things, verifying that provisions of the CWA were complied with prior to the initiation of mining activities. We are unable to predict the impact, if any, of the proposed rulemaking and the interim measures taken by the OSM, although the actions could result in prohibitions or restrictions relating to mining activities near streams, additional delays and costs associated with obtaining permits, and potentially additional CWA enforcement actions as a result of an increased focus on inspections.

Also, 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:

 

   

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

 

   

identify all current pollutant sources and loadings to that waterbody;

 

   

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

 

   

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 us or our customers to modify existing operations, the extent of which cannot be accurately or reasonably predicted.

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.

 

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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 regulatory restrictions 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, on March 14, 2007, the OSM issued an Advanced Notice of Rule making proposing federal regulations on CCB mine filling practices. On August 29, 2007, the 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. 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.

In addition, the EPA has recently issued Information Request Letters to electric utilities that have surface impoundments containing CCB, seeking information to assist the EPA in evaluating the structural integrity of these impoundments. The EPA has been conducting on-site assessments of coal ash impoundments and ponds at electric utility facilities, and a number of these facilities have developed action plans to improve the integrity of impoundments. The EPA also has announced its intention to promulgate regulations for the management of CCB by electric utilities, potentially by revising its 2000 determination that CCB should not be regulated as hazardous wastes under RCRA. Although it is not currently possible to predict how such regulations would impact our operations or those of our customers, the regulation of CCB as hazardous waste could result in increased disposal and compliance costs, which could result in decreased demand for our products.

 

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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. In addition, our use of explosives is subject to the Federal Safe Explosives Act (“SEA”). The costs of compliance with these regulations should not have a material adverse effect on our business, financial condition or results of operations.

Employees

To conduct our operations, we currently employ approximately 3,090 full-time employees, including approximately 170 corporate employees and approximately 2,920 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 the AHGP IPO, ARLP entered into an administrative services agreement (“Administrative Services Agreement”) with our managing general partner, the 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, AGP 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 for the year ended December 31, 2009 of $0.4 million from AHGP and $0.5 million from ARH II. Please read “Item 13—Certain Relationships and Related Transactions, and Director Independence—Administrative Services.”

 

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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:

 

   

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

 

   

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

 

   

the level of our operating costs;

 

   

weather conditions;

 

   

the proximity to and capacity of transportation facilities;

 

   

domestic and foreign governmental regulations and taxes;

 

   

the price and availability of alternative fuels;

 

   

the effect of worldwide energy consumption; and

 

   

prevailing economic conditions.

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

 

   

the level of our capital expenditures;

 

   

the cost of acquisitions, if any;

 

   

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

 

   

fluctuations in our working capital needs;

 

   

unavailability of financing resulting in unanticipated liquidity restraints;

 

   

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

 

   

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 and other factors, we may not have sufficient available cash to pay a specific level of cash distributions to our unitholders. Furthermore, 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 available cash.

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:

 

   

our unitholders’ proportionate ownership interest in us will decrease;

 

   

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

 

   

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

 

   

the ratio of taxable income to distributions may increase; and

 

   

the market price of our common units may decline.

 

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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, 2009, 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 its owners 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.

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. Our credit ratings and risk profile could be adversely affected if the ratings and risk profiles of AHGP and the entities that control it 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, 2009, AHGP owned approximately 42.4% 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, 2009, AHGP held approximately 42.4% of our outstanding units. Consequently, it is not currently possible 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 also 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.

 

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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 19. 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 partners generally have 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 partners. 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 Delaware law, 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:

 

   

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”;

 

   

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

 

   

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 becoming a limited partner of our partnership, a common unitholder is 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, 2009, AHGP owned approximately 42.4% 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:

 

   

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.

 

   

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.

 

   

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”).

 

   

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.

 

   

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

 

   

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

 

   

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

 

   

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.

 

   

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

Weakness in global economic conditions or in any of the industries in which our customers operate, or sustained uncertainty in financial markets may have material adverse impacts on our business and financial condition that we currently cannot predict.

As widely reported, economic conditions in the U.S. and globally have deteriorated and the extent and timing of a recovery, especially in the U.S. and Europe, is uncertain. Financial markets in the U.S., Europe and Asia have also experienced a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in security prices, severely diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of various financial institutions and an unprecedented level of intervention from the U.S. federal government and other governments. Weakness in the U.S. or global economies, in any of the industries we serve or in the financial markets, could materially adversely affect our business and financial condition. For example:

 

   

the demand for electricity in the U.S. has declined and may remain at low levels or further decline if economic conditions remain weak, which may negatively impact the revenues, margins and profitability of our business;

 

   

the tightening of capital markets or lack of capital availability to our customers could adversely affect their ability to honor their obligations to us; and

 

   

our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for operating our business, including development of our coal reserves.

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

Our results of operations are primarily dependent upon the prices we receive for our coal, as well as our ability to improve productivity and control costs. The prices we receive for our production depends upon factors beyond our control, including:

 

   

the supply of and demand for domestic and foreign coal;

 

   

weather conditions;

 

   

the proximity to, and capacity of, transportation facilities;

 

   

domestic and foreign governmental regulations and taxes;

 

   

the price and availability of alternative fuels;

 

   

the effect of worldwide energy consumption; and

 

   

prevailing economic conditions.

Any adverse change in these factors could result in weaker demand and lower prices for our products. 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.

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 many small coal producers in various regions of the U.S. 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.

 

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

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, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as alternative sources of energy. For example, the relatively low price of natural gas in 2009 resulted, in some instances, in utilities increasing natural gas consumption while decreasing coal consumption. Future environmental regulation of greenhouse gas emissions could accelerate the use by utilities of fuels other than coal. In addition, state and federal mandates for increased use of electricity derived from renewable energy sources could affect demand for our coal. A number of states have enacted mandates that require electricity suppliers to rely on renewable energy sources in generating a certain percentage of power. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. 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.

The stability and profitability of our operations could be adversely affected if our customers do not honor existing contracts or do not extend existing or enter into new long-term contracts for coal.

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 2009, we sold approximately 92.6% of our sales tonnage under contracts having a term greater than one year, which we refer to 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 sales contracts 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 events that are beyond the customer’s reasonable control. Such events may include labor disputes, mechanical malfunctions and changes in government regulations, including changes in the CAA rendering use of our coal inconsistent with the customer’s pollution control strategies. 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

 

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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, further reducing demand for our coal. Please read “Item 1. Business—Regulation and Laws—Air Emissions” and “—Carbon Dioxide Emissions.” In addition, the EPA has announced its intent to promulgate regulations for the management of CCB. Currently, CCB is not regulated as a hazardous waste. If the EPA were to regulate CCB as a hazardous waste or impose other restrictions or limitations on the management and disposal of CCB, this change could result in increased disposal and compliance costs, which could result in decreased demand for our products. Please read “Item 1. Business—Regulation and Laws—Hazardous Substances and Wastes.”

Increased regulation of greenhouse gas emissions could result in increased operating costs and reduced demand for coal as a fuel source, which could reduce demand for our products, decrease our revenues and reduce our profitability.

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide into the atmosphere. On December 15, 2009, the U.S. EPA published its findings that emissions of carbon dioxide and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings may lead to the EPA adopting and implementing regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. Accordingly, the EPA has proposed regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources, including many industrial users and coal-fired power plants. The U.S. Congress is considering legislation to reduce emissions of greenhouse gases. On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as coal. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions. President Obama has expressed support for legislation to restrict or regulate emissions of greenhouse gases. In December 2009, the U.S. joined with a number other countries in negotiating the Copenhagen Accord, a nonbinding agreement to commit to specific efforts to reduce greenhouse gas emissions, although how and when the commitment may be converted into binding emission reduction obligations is currently uncertain. Many states already have begun implementing legal measures to reduce emissions of greenhouse gases. Please read “Item 1. Business—Regulation and Laws—Air Emissions” and “—Carbon Dioxide Emissions.”

Future international, 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 reduced demand for coal and some customers switching to alternative sources of fuel, which could have a material adverse effect on our business, financial condition, and results of operations. In addition, the increased difficulty or inability of our customers to obtain permits for construction of new or expansion of existing coal-fired power plants could adversely affect demand for our coal and have an adverse effect on our business and results of operation.

Recent federal court rulings may allow plaintiffs to pursue tort claims based on the alleged effects of climate change.

In 2004, eight states and New York City sued five electric utility companies in Connecticut v. American Electric Power Co., Civ. No. 04 CV 05669 (S.D.N.Y.). These defendants were chosen as allegedly the five largest carbon dioxide emitters in the U.S., through their fossil-fuel-fired electric power plants. Invoking the federal and state common law of public nuisance, plaintiffs sought an injunction requiring defendants to abate their contribution to the nuisance of climate change by capping carbon dioxide emissions and then reducing them. Plaintiffs sued both on their own behalf to protect state-owned property and on behalf of their citizens and residents to protect public health and well-being. On September 21, 2009, on appeal of the trial court’s dismissal of the case, the Second Circuit issued a ruling holding that the district court erred in dismissing the complaints on political question grounds, that all of the Plaintiffs have standing and that Plaintiffs validly stated claims under the federal common law on nuisance.

Also, in late November 2009, in Comer v. Murphy Oil USA, et al., No. 07-60756 (5th Cir.) industry defendants asked the Fifth Circuit for a rehearing of its decision of October 16, 2009 overturning the dismissal of tort claims brought by residents of Mississippi against dozens of companies in the energy, fossil fuel production, and chemical industries, including ten coal companies, seeking

 

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money damages for injuries allegedly sustained as a result of Hurricane Katrina in 2005. In 2007, the district court had granted the defendants’ motions to dismiss, finding that the plaintiffs lacked standing and holding that the complaint raised only nonjusticiable political questions. In reversing, the Fifth Circuit held the plaintiffs had standing to bring their four state common law claims (public and private nuisance, trespass, and negligence), and that the claims did not present nonjusticiable political questions, and remanded to the trial court for further proceedings.

Although we cannot predict the impact, if any, of these court decisions, proliferation of successful climate change litigation could ultimately have a material adverse effect on our business, financial condition and results of operations.

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 2009, we derived approximately 41.8% of our total revenues from four customers and at least 10.0% of our 2009 total revenues from each of the four. 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 or our customers’ 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, which could have a material adverse effect on our business, financial condition and results of operations.

Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If the creditworthiness of our customers declines significantly, our business could be adversely affected. In addition, if a customer refuses to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customer’s contractual obligations are honored.

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:

 

   

fires;

 

   

mining and processing equipment failures and unexpected maintenance problems;

 

   

unavailability of required equipment;

 

   

prices for fuel, steel, explosives and other supplies;

 

   

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

 

   

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

 

   

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

 

   

weather conditions, such as heavy rains, flooding, ice and other storms;

 

   

accidental mine water discharges and other geological conditions;

 

   

employee injuries or fatalities;

 

   

labor-related interruptions;

 

   

increased reclamation costs;

 

   

inability to acquire, maintain or renew mining rights or permits in a timely manner, if at all; 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.

During September 2009, we completed our annual property and casualty insurance renewal with various insurance coverages effective as of October 1, 2009. We elected to retain a participating interest in our commercial property insurance program at an average rate of approximately 14.7% in the overall $75.0 million of coverage, representing 22% of the primary $50.0 million layer. We do not participate in the second 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 are responsible for a maximum amount of $11.0 million for each occurrence, excluding a $1.5 million deductible for property damage, a $5.0 million aggregate deductible for extra expense and a 60-day waiting period for business interruption. 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 experienced coal miners has caused us to include some inexperienced staff in the operation of certain mining units, which decreases our productivity and increases our costs. This shortage of experienced 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, and proposed legislation such as the Employee Free Choice Act, could, if enacted, make staying union-free more difficult. 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.

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 may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations may occur, that could materially affect our mining operations, cash flow, and profitability, either through direct impacts on our mining operations, or indirect impacts that discourage or limit our customers’ use of coal. Please read “Item 1. Business—Regulations and Laws.”

 

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Congress and several state legislatures (including those in Illinois, Kentucky, West Virginia and Pennsylvania) 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.”

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 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.”

Litigation has been filed to enjoin the issuance of Nationwide Permit 21, which is a general permit issued by the Corps of Engineers to streamline the process for obtaining permits for the discharge of overburden from mining operations under Section 404 of the CWA. In addition, the Corps of Engineers published a proposal to modify or suspend the use of Nationwide Permit 21 in the Appalachian region. 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. This could result in additional delays and costs in developing mining operations. In addition, lawsuits have also challenged the Corps of Engineers’ issuance of certain individual Section 404 permits. Although our mining operations are not implicated in any of these particular cases, it is possible that the outcome of these lawsuits 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. In addition, there are a number of ongoing or proposed regulatory and legislative developments that could restrict or limit the ability to obtain Section 404 permits for discharges of dredged or fill material associated with mining operations, including a federal, interagency action plan on Appalachian surface coal mining and an enhanced environmental review process for Section 404 permits for mining operations in Appalachia. 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. Disruption of 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.

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 U.S. inherently more expensive on a per-mile basis than coal shipments originating in the western U.S. 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 rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created major competitive challenges 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.

 

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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.

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

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. 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.

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

If we are unable to successfully integrate the companies, businesses or properties we acquire, 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:

 

   

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;

 

   

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

 

   

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

 

   

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.

Completion of growth projects and future expansion could require significant amounts of financing which may not be available to us on acceptable terms, or at all.

We plan to fund capital expenditures for our current growth projects with existing cash balances, future cash flow from operations, borrowings under our revolving credit facility and cash provided from the issuance of debt or equity. Our funding plans may, however, be negatively impacted by numerous factors, including higher than anticipated capital expenditures or lower than expected cash flow from operations. In addition, we may be unable to refinance our current revolving credit facility when it expires or obtain adequate funding prior to expiry because our lending counterparties may be unwilling or unable to meet their funding obligations. Furthermore, additional growth projects and expansion opportunities may develop in the future which could also require significant amounts of financing. Consequently, completion of growth projects and future expansion could require significant amounts of financing which may not be available to us on acceptable terms or in the proportions that we expect, or at all.

 

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Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.

The cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have raised interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to expiring terms and, in some cases, reduced or ceased to provide funding to borrowers under existing facilities. For a discussion of how these tighter lending standards may impact our 2010 capital expenditure plans, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures.”

The credit market and debt and equity capital market conditions discussed above could negatively impact our credit ratings or our ability to remain in compliance with the financial covenants under our revolving credit agreement, which could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth and future expansions as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our plans.

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 we deplete our reserves 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 mineable 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.

The estimates of our coal reserves may prove inaccurate and could result in decreased profitability.

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:

 

   

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;

 

   

the percentage of coal in the ground ultimately recoverable;

 

   

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

 

   

the assumed effects of regulation and taxes by governmental agencies; and

 

   

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. Any inaccuracy in the estimates of our reserves could result in higher than expected costs and decreased profitability.

 

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Mining in certain areas in which we operate is more difficult and involves more regulatory constraints than mining in other areas of the U.S., 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 mineable 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.

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 our subsidiary 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.

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

Our coal mining operations are 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 and the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel fluctuate significantly and may change unexpectedly. There may be acts of nature or terrorist attacks or threats that could also impact the future costs of raw materials. Future volatility in the price of steel, petroleum products or other raw materials will impact our operational expenses and could result in significant fluctuations to 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 senior unsecured notes and our revolving credit facility. At December 31, 2009, our total long-term indebtedness outstanding was $422.0 million. Our leverage may:

 

   

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

 

   

limit our ability to pursue acquisitions and other business opportunities;

 

   

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

 

   

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:

 

   

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

 

   

if either before or after such distribution, we fail 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.

 

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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:

 

   

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

 

   

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

 

   

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.

We and our subsidiaries are subject to various legal proceedings, which may have a material effect on our business.

We are party to a number of legal proceedings incident to our normal business activities. There is the potential that an individual matter or the aggregation of multiple matters could have an adverse effect on our cash flows, results of operations or financial position. Please see “Item 8. Financial Statements and Supplementary Data—Note 20. Commitments and Contingencies” for further discussion.

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 recently been considered that would have eliminated partnership tax treatment for certain publicly traded partnerships. Although such legislation would not have appeared to apply to us as considered, it could be reintroduced in a manner that does apply to us. We are unable to predict whether any of these changes or other proposals will be reintroduced or 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 as an entity, the cash available for distribution to you would be reduced.

 

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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 our 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 IRAs 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 U.S. 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.

 

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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. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued.

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 intangible assets and a lesser portion allocated to our tangible 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.

Certain federal income tax deductions currently available with respect to coal mining and production may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2011 Budget includes proposed legislation that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key U.S. federal income tax provisions currently applicable to coal companies, including the repeal of the percentage depletion allowance with respect to coal properties. The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to our operations. Although the current proposal would have no impact on our financial statements or results of operations, any such change could result in unfavorable tax consequences for our unitholders and as a result, negatively impact our unit price.

 

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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. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. 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 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 calendar year,, 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, but it would result in our being treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred.

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.

 

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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, 2009, we had approximately 647.2 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 United States Geological Survey (“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, 2009, about our mining operations:

 

                Proven and Probable Reserves        

Operations

   Mine Type    Heat Content
(Btus per pound)
   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    12,200    —        —        97.8      97.8      97.8      —     

Warrior (KY)

   Underground    12,600    —        —        74.6      74.6      56.8      17.8   

Hopkins (KY)

   Underground    12,200    —        —        41.2      41.2      26.1      15.1   
   /Surface    11,500    —        —        7.8      7.8      7.8      —     

River View (KY)

   Underground    11,600    —        —        120.8      120.8      120.8      —     

Pattiki (IL)

   Underground    11,500    —        —        47.4      47.4      47.4      —     

Gibson (North) (IN)

   Underground    11,600    —        22.0      3.7      25.7      25.7      —     

Gibson (South) (IN)

   Underground    11,500    —        12.9      40.7      53.6      —        53.6   
                                          

Region Total

         —        34.9      434.0      468.9      382.4      86.5   
                                          

Central Appalachian Operations

                  

Pontiki (KY)

   Underground    13,000    —        9.2      —        9.2      9.2      —     

MC Mining (KY)

   Underground    12,600    16.3      —        1.8      18.1      18.1      —     
                                          

Region Total

         16.3      9.2      1.8      27.3      27.3      —     
                                          

Northern Appalachian Operations

                  

Mettiki (MD)

   Underground    13,200    —        2.6      7.0      9.6      9.6      —     

Mountain View (WV)

   Underground    13,200    —        5.2      9.3      14.5      14.5      —     

Tunnel Ridge (PA/WV)

   Underground    12,600    —        —        70.2      70.2      70.2      —     

Penn Ridge (PA)

   Underground    12,500    —        —        56.7      56.7      56.7      —     
                                          

Region Total

         —        7.8      143.2      151.0      151.0      —     
                                          

Total

         16.3      51.9      579.0      647.2      560.7      86.5   
                                          

% of Total

         2.5   8.0   89.5   100.0   86.6   13.4
                                          

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 USGS. 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.

 

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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, which audit will be updated during 2010.

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, but the reserves at our Mettiki and Mountain View complexes can be characterized as cross-over coal that can be produced as metallurgical. The 16.3 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—8.8 million tons, Pattiki—5.7 million tons, Hopkins County Coal—3.3 million tons, River View—23.5 million tons, Gibson (North)—2.4 million tons, Gibson (South)—14.0 million tons, Warrior—8.1 million tons, Mettiki – 5.1 million tons; Tunnel Ridge—6.1 million tons, Penn Ridge—3.4 million tons, Pontiki—8.6 million tons, and 66.0 million tons of coal located near the River View complex, for total non-reserve coal deposits of 155.0 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.

 

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Mining Operations

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

 

     Location    Tons Produced   

Transportation

   Equipment

Operations

      2009    2008    2007      
          (in millions)          

Illinois Basin Operations

                 

Dotiki

   Kentucky    4.2    4.7    4.6    CSX, PAL, truck, barge    CM

Warrior

   Kentucky    6.2    5.1    4.6    CSX, PAL, truck, barge    CM

Hopkins

   Kentucky    4.0    4.0    2.6    CSX, PAL, truck, barge    CM

River View

   Kentucky    0.5    —      —      Barge    CM

Pattiki

   Illinois    2.5    2.7    2.9    EVW, barge    CM

Gibson (North)

   Indiana    3.3    3.8    3.2    CSX, NS, truck, barge    CM
                       

Region Total

      20.7    20.3    17.9      
                       

Central Appalachian Operations

                 

Pontiki

   Kentucky    1.1    1.5    1.4    NS, truck, barge    CM

MC Mining

   Kentucky    1.5    1.7    1.8    CSX, truck, barge    CM
                       

Region Total

      2.6    3.2    3.2      
                       

Northern Appalachian Operations

                 

Mettiki

   Maryland    0.3    0.4    0.4    Truck, CSX    CM

Mountain View

   West Virginia    2.2    2.5    2.8    Truck, CSX    LW, CM
                       

Region Total

      2.5    2.9    3.2      
                       

TOTAL

      25.8    26.4    24.3      
                       

 

CSX

NS

PAL

CM

LW

EVW

 

- CSX Railroad

- Norfolk Southern Railroad

- Paducah & Louisville Railroad

- Continuous Miner

- Longwall

- Evansville Western Railroad

 

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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 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 20. Commitments and Contingencies” is incorporated herein by this reference.

On November 2, 2006 George W. Rector et al. (the “Plaintiffs”) filed a complaint in the Circuit Court of the Second Judicial Circuit of Illinois, in White County, Illinois, against our subsidiaries White County Coal, LLC, Alliance Properties, LLC and Alliance Coal, LLC (collectively the “Alliance Defendants”) asserting claims for breach of contract, breach of fiduciary duty and unjust enrichment. A bench trial of the case was concluded in November 2009, but the court has not yet issued a decision. The Plaintiffs’ claims are based on their assertion that, as a result of assignments in 1977, 1978 and 1979 from the Plaintiffs’ or their predecessors to the Alliance Defendants’ predecessors, MAPCO Coal, Inc. and MAPCO Land & Development Corporation (collectively “MAPCO”), of certain coal leases, they are entitled to receive royalty payments on all coal mined previously or in the future from the property once affected by those leases as well as from other property in the area. Plaintiffs have alleged damages of $33.0 million or more, and have also asserted a claim for punitive damages. The subject assignments were made in accordance with an agreement between Plaintiffs and MAPCO pursuant to which Plaintiffs reserved the right to receive an overriding royalty on coal mined under the assigned leases. Several years after MAPCO terminated a number of the assigned leases, the Alliance Defendants entered into new leases of some of the property previously covered by the assigned leases, and subsequently began mining in the area. We believe that Plaintiffs’ overriding royalty interest did not extend to any renewal of the subject leases or to any new lease covering the same property, and that Plaintiffs’ claims are without merit. We also believe that an adverse decision in this litigation, if any, would not have a material adverse effect on our business, financial position or results of operations.

On April 24, 2006, we were served with a complaint from Mr. Ned Comer, et al. (the “Plaintiffs”) alleging that approximately 40 oil and coal companies, including us, (the “Defendants”) are liable to the Plaintiffs for tortuously 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 trial court dismissed the Plaintiffs’ complaint. On September 17, 2007, Plaintiffs filed a notice of appeal of that dismissal to the U.S. Court of Appeals for the Fifth Circuit. On October 16, 2009, the Fifth Circuit overturned the trial court’s dismissal of the Plaintiffs’ private nuisance, trespass and negligence claims, finding Article III constitutional standing and no political question. The Fifth Circuit remanded these claims to the trial court for further proceedings. The Defendants have petitioned for re-hearing by the Fifth Circuit. We believe this complaint is without merit and we do not believe that an adverse decision in this litigation matter, if any, based on our status as a defendant, will have a material adverse effect on our business, financial position or results of operations. If, however, tort claims brought in this and other cases against corporate defendants for liability arising from greenhouse gas emissions are successful, demand for our coal could be adversely impacted.

 

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS

The Partnership filed a Consent Solicitation Statement dated September 25, 2009 with the SEC on Schedule 14A in connection with the solicitation of consents of the holders of common units to approve The Third Amendment (“Third Amendment”) to the 2000 Long-Term Incentive Plan, as amended (the “Plan”). A summary of the Third Amendment was set forth in the Partnership’s Consent Solicitation Statement under the caption “The Plan and Proposed Amendment.” Such description is incorporated herein by reference and is qualified in its entirety by reference to the full text of the Amended and Restated Plan, as amended. On October 23, 2009, the unitholders of the Partnership approved the Third Amendment to the Plan. The Third Amendment had previously been authorized by the Board of Directors. The Third Amendment increased the number of common units available for issuance under the Plan from 1.2 million to 3.6 million.

 

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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 23, 2010, the closing market price for the common units was $41.13 per unit. As of February 23, 2010, there were 36,716,855 common units outstanding. There were approximately 29,195 record holders and beneficial owners (held in street name) of common units at December 31, 2009.

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 2008

   $ 40.10    $ 32.54    $0.585 (paid May 15, 2008)

2nd Quarter 2008

   $ 58.00    $ 34.34    $0.660 (paid August 14, 2008)

3rd Quarter 2008

   $ 56.25    $ 28.74    $0.700 (paid November 14, 2008)

4th Quarter 2008

   $ 34.85    $ 17.39    $0.715 (paid February 13, 2009)

1st Quarter 2009

   $ 33.65    $ 23.87    $0.730 (paid May 15, 2009)

2nd Quarter 2009

   $ 40.24    $ 28.46    $0.745 (paid August 14, 2009)

3rd Quarter 2009

   $ 38.49    $ 30.78    $0.760 (paid November 13, 2009)

4th Quarter 2009

   $ 45.00    $ 34.07    $0.775 (paid February 12, 2010)

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.

 

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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, 2009, 2008, 2007, 2006 and 2005.

 

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

   Year Ended December 31,  
   2009     2008     2007     2006     2005  

Statements of Income

          

Sales and operating revenues:

          

Coal sales

   $ 1,163.9      $ 1,093.1      $ 960.3      $ 895.8      $ 768.9   

Transportation revenues

     45.7        44.7        37.7        39.9        39.1   

Other sales and operating revenues

     21.4        18.7        35.3        31.9        30.7   
                                        

Total revenues

     1,231.0        1,156.5        1,033.3        967.6        838.7   
                                        

Expenses:

          

Operating expenses (excluding depreciation, depletion and amortization)

     797.6        801.9        685.1        627.8        521.5   

Transportation expenses

     45.7        44.7        37.7        39.9        39.1   

Outside coal purchases

     7.5        23.8        22.0        19.2        15.1   

General and administrative

     41.1        37.2        34.4        30.9        33.5   

Depreciation, depletion and amortization

     117.5        105.3        85.3        66.5        55.6   

Gain from sale of coal reserves

     —          (5.2     —          —          —     

Net gain from insurance settlement and other (1)

     —          (2.8     (11.5     —          —     
                                        

Total operating expenses

     1,009.4        1,004.9        853.0        784.3        664.8   
                                        

Income from operations

     221.6        151.6        180.3        183.3        173.9   

Interest expense (net of interest capitalized)

     (30.8     (22.1     (11.7     (12.2     (14.6

Interest income

     1.0        3.7        1.7        3.0        2.8   

Other income

     1.3        0.9        1.4        0.9        0.6   
                                        

Income before income taxes and cumulative effect of accounting change

     193.1        134.1        171.7        175.0        162.7   

Income tax expense (benefit)

     0.7        (0.5     1.6        2.4        2.7   
                                        

Income before cumulative effect of accounting change

     192.4        134.6        170.1        172.6        160.0   

Cumulative effect of accounting change (2)

     —          —          —          0.1        —     
                                        

Net income

     192.4        134.6        170.1        172.7        160.0   

Less: Net (income) loss attributable to noncontrolling interest

     (0.2     (0.4     0.3        0.2        —     
                                        

Net income attributable to Alliance Resource Partners, L.P. (“Net Income of ARLP”)

   $ 192.2      $ 134.2      $ 170.4      $ 172.9      $ 160.0   
                                        

General Partners’ interest in Net Income of ARLP

   $ 60.7      $ 45.7      $ 31.3      $ 24.6      $ 12.4   
                                        

Limited Partners’ interest in Net Income of ARLP

   $ 131.5      $ 88.5      $ 139.1      $ 148.3      $ 147.6   
                                        

Basic net income of ARLP per limited partner unit

   $ 3.56      $ 2.39      $ 3.78      $ 4.03      $ 4.07   
                                        

Diluted net income of ARLP per limited partner unit (3)

   $ 3.56      $ 2.39      $ 3.78      $ 4.03      $ 3.99   
                                        

Distributions paid per limited partner unit

   $ 2.95      $ 2.53      $ 2.20      $ 1.92      $ 1.58   
                                        

Weighted average number of units outstanding-basic

     36,655,555        36,604,707        36,548,150        36,425,350        36,288,527   
                                        

Weighted average number of units outstanding-diluted

     36,655,555        36,604,707        36,548,150        36,425,350        36,977,061   
                                        

Balance Sheet Data:

          

Working capital

   $ 54.9      $ 239.8      $ 25.9      $ 37.4      $ 76.1   

Total assets

     1,051.4        1,030.6        701.7        635.0        532.7   

Long-term obligations (4)

     422.5        440.8        137.1        127.5        144.0   

Total liabilities (5)

     730.4        740.4        384.0        385.6        376.9   

Partners’ capital (5)

     321.0        290.2        317.7        249.3        155.8   

Other Operating Data:

          

Tons sold

     25.0        27.2        24.7        24.4        22.8   

Tons produced

     25.8        26.4        24.3        23.7        22.3   

Revenues per ton sold (6)

   $ 47.41      $ 40.88      $ 40.31      $ 38.02      $ 35.07   

Cost per ton sold (7)

   $ 33.85      $ 31.72      $ 30.02      $ 27.78      $ 25.00   

Other Financial Data:

          

Net cash provided by operating activities

   $ 282.7      $ 261.0      $ 244.0      $ 250.9      $ 193.6   

Net cash used in investing activities

     (320.1     (184.1     (178.7     (137.7     (110.2

Net cash provided by (used in) financing activities

     (186.6     166.8        (101.0     (108.5     (82.6

EBITDA (8)

     340.4        257.8        267.0        250.8        230.1   

Maintenance capital expenditures (9)

     96.1        77.7        76.3        67.8        56.7   

 

(1) Represents the net gain from the final settlement in 2007 with our insurance underwriters for claims relating to a fire at the Dotiki mine and a fire at MC Mining, (“MC Mining Fire Incident”), and a realized gain in 2008 of $2.8 million on settlement of our claim against the third-party that provided security services at the time of the MC Mining Fire Incident. (Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Analysis of Historical Results of Operations—MC Mining Mine Fire.”)

 

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(2) Represents the cumulative effect of the accounting change attributable to the adoption of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 718, Compensation-Stock Compensation (Statement of Financial Accounting Standards (“SFAS”) No. 123R, Share-Based Payments), on January 1, 2006.
(3) Basic and diluted earnings per unit (“EPU”) have been restated for the years ending December 31, 2008, 2007, 2006 and 2005 due to the adoption of FASB ASC 260-10-55-102 through 55-110, Master Limited Partnerships (Emerging Issues Task Force (“EITF”) No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings Per Share, to Master Limited Partnerships) and FASB ASC 260-10-55-25 (FASB Staff Position (“FSP”) No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities). Diluted EPU give effect to all dilutive potential common units outstanding during the period using the treasury stock method. Dilutive EPU exclude all dilutive units calculated under the treasury stock method if their effect is anti-dilutive. For the years ended December 31, 2009, 2008, 2007 and 2006, LTIP, Supplemental Executive Retirement Plan (“SERP”) and Directors compensation units of 176,743, 165,175, 252,061 and 385,032, respectively, were considered anti-dilutive. There were no anti-dilutive units for the year ended December 31, 2005.
(4) Long-term obligations include long-term portions of debt and capital lease obligations.
(5) On January 1, 2009, we adopted FASB ASC 810-10-65 and 810-10-45-16 (SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements), which amended accounting and reporting standards for noncontrolling ownership interests in subsidiaries. As a result of the adoption of the FASB ASC 810-10-65 and 810-10-45-16 amendments, noncontrolling ownership interest in consolidated subsidiaries is now presented in the consolidated balance sheet within partners’ capital as a separate component from the parent’s equity. Consolidated net income now includes earnings attributable to both the parent and the noncontrolling interests.
(6) Revenues per ton sold are based on the total of coal sales and other sales and operating revenues divided by tons sold.
(7) Cost per ton sold is based on the total of operating expenses, outside coal purchases and general and administrative expenses divided by tons sold.
(8) EBITDA is a non-Generally Accepted Accounting Principles (“GAAP”) measure and is defined as net income of ARLP before income taxes, cumulative effect of accounting change, net income attributable to noncontrolling 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 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 GAAP. 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).

 

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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 of ARLP (in thousands):

 

     Year Ended December 31,  
   2009     2008     2007     2006     2005  

Cash flows provided by operating activities

   $ 282,741      $ 261,041      $ 244,012      $ 250,923      $ 193,618   

Non-cash compensation expense

     (3,582     (3,931     (3,925     (4,112     (8,193

Asset retirement obligations

     (2,678     (2,827     (2,419     (2,101     (1,918

Coal inventory adjustment to market

     (3,030     (452     (21     (319     (573

Net gain on foreign currency exchange

     653        —          —          —          —     

Net gain (loss) on sale of property, plant and equipment

     (136     911        3,189        1,188        (179

Gain on sale of coal reserves

     —          5,159        —          —          —     

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

     (537     (366     (811     (1,119     (580

Net effect of working capital changes

     36,440        (19,661     7,898        (5,317     34,770   

Interest expense, net

     29,798        18,418        9,952        9,175        11,816   

Income tax expense (benefit)

     708        (480     1,669        2,443        2,682   
                                        

EBITDA

     340,377        257,812        266,989        250,761        230,145   

Depreciation, depletion and amortization

     (117,524     (105,278     (85,310     (66,489     (55,637

Interest expense, net

     (29,798     (18,418     (9,952     (9,175     (11,816

Income tax (expense) benefit

     (708     480        (1,669     (2,443     (2,682

Cumulative effect of accounting change

     —          —          —          112        —     
                                        

Net income

     192,347        134,596        170,058        172,766        160,010   

Net (income) loss attributable to noncontrolling interest

     (190     (420     332        161        —     
                                        

Net income of ARLP

   $ 192,157      $ 134,176      $ 170,390      $ 172,927      $ 160,010   
                                        

 

(9) 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 coal primarily to major U.S. utilities and industrial users. In 2009, our total production was 25.8 million tons and our total sales were 25.0 million tons. The coal we produced in 2009 was approximately 10.1% low-sulfur coal, 22.5% medium-sulfur coal and 67.4% 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 operate nine underground mining complexes and at December 31, 2009, had approximately 647.2 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 are constructing a new mining complex in West Virginia, and also operate 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.

 

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As discussed in more detail in “Item 1A. Risk Factors,” our results of operations could be 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. Additionally, our results of operations could be impacted by our ability to obtain and renew permits necessary for our operations, secure or acquire coal reserves, or find replacement buyers for coal under contracts with comparable terms to existing contracts. Moreover, the regulatory environment has grown increasingly more stringent in recent years. As outlined in “Item 1. Business—Regulation and Laws” a variety of measures taken by regulatory agencies in the U.S. and abroad and legislation pending in the U.S. Congress in response to the perceived threat from climate change attributed to greenhouse gas emissions could substantially increase compliance costs for us and our customers and reduce demand for coal, which could materially and adversely impact our results of operations. For additional information regarding some of the risks and uncertainties that affect our business and industry in which we operate, see “Item 1A. Risk Factors.”

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 available cash to maximize our distributions to our unitholders 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 U.S. 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 mining complex, Gibson County Coal’s Gibson North mining complex, Hopkins County Coal’s Elk Creek mining complex, White County Coal’s Pattiki mining complex, Warrior’s mining complex, River View’s newly constructed mining complex, which recently initiated operations, the Gibson South property and certain properties of Alliance Resource Properties, LLC (“Alliance Resource Properties”). We are in the process of permitting the Gibson South property 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.”

 

   

Central Appalachian segment is comprised of Pontiki’s and MC Mining’s mining complexes.

 

   

Northern Appalachian segment is comprised of Mettiki (MD)’s mining complex, Mettiki (WV)’s Mountain View mining complex, two small third-party mining operations (one of which was idled in May 2009), a mining complex currently under construction at Tunnel Ridge, and the Penn Ridge property. We are in the process of permitting the Penn Ridge property 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, Matrix Design Group, LLC (“Matrix Design”), Alliance Design Group, LLC (“Alliance Design”), the Mt. Vernon dock activities, coal brokerage activity, MAC and certain properties of Alliance Resource Properties.

 

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How We Evaluate Our Performance

Our management uses a variety of financial and operational measurements to analyze our 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; (4) EBITDA; and (5) Segment Adjusted 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. Our discussion of mining conditions and preparation plant costs are found below under “—Analysis of Historical Results of Operations” and therefore provides implicit analysis of saleable tons produced per unit shift.

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 to evaluate marketing efforts and for 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 coal 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 of ARLP before net interest expense, income taxes, depreciation, depletion and amortization and net income attributable to noncontrolling 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 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.

Segment Adjusted EBITDA. We define Segment Adjusted EBITDA as net income of ARLP before net interest expense, income taxes, depreciation, depletion and amortization, net income attributable to noncontrolling interest, and corporate general and administrative expenses. Management therefore is able to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.

Sources of Our Revenue

In 2009, approximately 91.8% of our sales tonnage was consumed by electric utilities, with the balance shipped to third-party resellers, industrial consumers and cogeneration plants. In 2009, approximately 92.6% of our sales tonnage, including approximately 95.2% 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 2009, approximately 88.5% of our medium- and high-sulfur coal was sold to utility plants with installed pollution control devices. These devices, also known as scrubbers, eliminate substantially all emissions of sulfur dioxide.

Expiration of Federal Non-Conventional Source Fuel Tax Credit

Historically, we received material revenues from coal sales, rental, marketing and other services provided under synfuel-related agreements at three of our mining operations. As anticipated, operations at these third-party synfuel facilities ended in December 2007 as the federal non-conventional source fuel tax credits expired. As a result, we no longer sell coal to the synfuel operators, but

 

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instead sell that coal directly to our customers, including (but not exclusively) Louisville Gas and Electric Company, Seminole Electric Cooperative, Inc., the Tennessee Valley Authority and VEPCO, each of which individually accounted for at least 10% of our total revenues in 2009. 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.

Analysis of Historical Results of Operations

A comparison of our operating results for the years ended December 31, 2009, 2008 and 2007 was affected by the following significant non-recurring items:

2009

 

   

There were no significant non-recurring items for the year ended December 31, 2009.

2008

 

   

Gain on sale of non-core coal reserves of $5.2 million in 2008;

 

   

Gain of $2.8 million on settlement of claims against the third-party that provided security services at the time of the December 2004 MC Mining Fire Incident was recognized in 2008. Please read “–MC Mining Mine Fire” below; and

 

   

Gain of $1.9 million on settlement of claims relating to the 2005 failure of the vertical belt system (the “Vertical Belt Incident”) at our Pattiki mine in 2008 recorded as a reduction to operating expenses. The 2008 gain resulted from a settlement reached with the third-party installer of the vertical belt system and represents a partial recovery of expenses incurred in 2005.

2007

 

   

Realized net income of approximately $28.5 million from various coal synfuel-related agreements. The expiration of the federal non-conventional source fuel tax credit and its impact on our results of operations are discussed in more detail above; and

 

   

Net gain of $3.2 million realized primarily from sales of surplus surface mining equipment.

2009 Compared with 2008

We reported Net Income of ARLP of $192.2 million, an increase of 43.2% in 2009 compared to Net Income of ARLP of $134.2 million in 2008. The increase of $58.0 million was principally due to improved contract pricing resulting in an average coal sales price of $46.60 per ton sold, compared to $40.23 per ton sold in 2008, partially offset by lower sales volumes and higher operating expense per ton sold in 2009. We had tons sold of 25.0 million and tons produced of 25.8 million in 2009 compared to 27.2 million tons sold and 26.4 million tons produced in 2008. Unplanned customer outages, contractual deferrals and weak spot market demand combined to reduce coal sales and production volumes in 2009 compared to 2008. In addition, as discussed above, 2008 operating results included significant, non-recurring gains of $9.9 million. Decreased operating expenses in the aggregate primarily reflected lower coal production and sales volumes, as well as, reduced materials and supplies expenses, contract mining costs and other factors described below. The significant factors related to increased operating expense per ton are also included in our analysis below.

 

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     December 31,    December 31,
   2009    2008    2009    2008
     (in thousands)    (per ton sold)

Tons sold

     24,975      27,170      N/A      N/A

Tons produced

     25,838      26,429      N/A      N/A

Coal sales

   $ 1,163,871    $ 1,093,059    $ 46.60    $ 40.23

Operating expenses and outside coal purchases

   $ 805,051    $ 825,630    $ 32.23    $ 30.39

Coal sales. Coal sales increased 6.5% to $1.2 billion in 2009 from $1.1 billion in 2008. The increase of $0.1 billion reflected the benefit of higher average coal sales prices (contributing an increase of $0.2 billion) partially offset by lower sales volume (reducing coal sales by $0.1 billion). Average coal sales prices increased $6.37 per ton sold in 2009 to $46.60 per ton compared to 2008, primarily as a result of improved contract pricing on long-term sales contracts, particularly in the Illinois Basin and Central Appalachian segments described below.

Operating expenses. Operating expenses in the aggregate decreased 0.5% to $797.5 million in 2009 from $801.9 million in 2008 primarily as a result of decreased tons produced and sold, in addition to various other factors, the most significant of which are discussed below. In addition, factors related to increased operating expense per ton are also included in our analysis below:

 

   

Labor and benefit expenses per ton produced, excluding workers’ compensation, increased 16.5% to $11.08 per ton in 2009 from $9.51 per ton in 2008. The increase of $1.57 per ton represents pay rate increases and higher benefit expenses, particularly increased health care costs and retirement expenses, and the impact of increased headcount as we continue to hire and train new employees for the River View and Tunnel Ridge mine development projects;

 

   

Workers’ compensation expenses per ton produced increased 23.1% to $0.96 per ton in 2009 from $0.78 per ton in 2008. The increase of $0.18 per ton primarily reflected a non-cash charge that resulted from a decrease in the discount rate from 6.11% at the end of 2008 to 5.27% at the end of 2009, which increased the accrued liabilities for the present value of estimated future claim payments;

 

   

Material and supplies expenses per ton produced decreased 2.2% to $9.62 per ton in 2009 from $9.84 per ton in 2008. This decrease of $0.22 per ton resulted from decreased costs for certain products and services, primarily roof support (decrease of $0.25 per ton), outside expenses including dozer repair and trucking (decrease of $0.12 per ton) and fuel used in the mining process (decrease of $0.10 per ton). These decreases were offset in part by increased costs in bits and cutter bars (increase of $0.05 per ton), higher power costs (increase of $0.12 per ton), preparation plant costs (increase of $0.09 per ton) reflecting reduced clean coal recovery and additional supplies associated with disruptions related to an ice storm during the 2009 first quarter in the Illinois Basin region, among other factors;

 

   

Maintenance expenses per ton produced increased 10.9% to $3.67 per ton in 2009 from $3.31 per ton in 2008. The increase of $0.36 per ton resulted from higher repair costs related to continuous miners, belt conveyor equipment and other equipment categories;

 

   

Mine administration expenses decreased $4.2 million in 2009 compared to 2008, primarily as a result of lower accruals related to estimated regulatory settlements;

 

   

Contract mining expenses decreased $5.3 million in 2009 compared to 2008. The decrease reflects a curtailment of third-party mining operations in our Northern Appalachian segment in response to weak demand in export and spot coal markets;

 

   

Production taxes and royalties (which were incurred as a percentage of coal sales or based on coal volumes) increased $0.48 per produced ton sold in 2009 compared to 2008, primarily as a result of increased average coal sales prices;

 

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Operating expenses incurred in 2009 relating to our River View and Tunnel Ridge mine development projects increased $18.7 million over 2008. Theses expenses are generally included in the variances discussed above; and

 

   

2008 operating expenses benefited from a $1.9 million gain on settlement of claims relating to the Vertical Belt Incident at our Pattiki mine.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, products and services provided by MAC and Matrix Design and other outside services and administrative services revenue from affiliates. Other sales and operating revenues increased 14.4% to $21.4 million in 2009 from $18.7 million in 2008. The increase of $2.7 million was primarily attributable to increased revenues from Matrix Design product sales and Mt. Vernon transloading revenues partially offset by decreases in ash disposal revenues and MAC product sales.

Outside coal purchases. Outside coal purchases decreased to $7.5 million in 2009 from $23.8 million in 2008. The decrease of $16.3 million was primarily attributable to a decrease in outside coal purchases in our Central and Northern Appalachian regions in response to a weak demand in export and spot coal markets.

General and administrative. General and administrative expenses in 2009 increased to $41.1 million compared to $37.2 million in 2008. The increase of $3.9 million was primarily attributable to higher unit-based incentive compensation expense and increased salary and benefit costs primarily related to higher staffing levels.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased to $117.5 million in 2009 compared to $105.3 million in 2008. The increase of $12.2 million was primarily attributable to additional depreciation expense associated with continuing capital expenditures related to infrastructure improvements, efficiency projects and expansion of production capacity.

Interest expense. Interest expense, net of capitalized interest, increased to $30.8 million in 2009 from $22.1 million in 2008. The increase of $8.7 million was principally attributable to the increased interest expense resulting from the $350 million private placement completed in June of 2008, partially offset by reduced interest expense from our August 2009 principal payment of $18.0 million on our senior notes issued in 1999. The 2008 financing activities are discussed in more detail below under “–Debt Obligations.”

Interest income. Interest income decreased to $1.0 million in 2009 from $3.7 million in 2008. The decrease of $2.7 million resulted from reduced interest income earned on short-term investments purchased with funds received from the 2008 financing activities, which were substantially liquidated to principally fund increased capital expenditures during 2009.

Transportation revenues and expenses. Transportation revenues and expenses increased 2.0% to $45.7 million in 2009 from $44.8 million in 2008. The increase of $0.9 million was primarily attributable to an increase in coal sales volumes for which we arranged transportation in 2009 compared to 2008, partially offset by a decrease in average transportation rates of $0.35 per ton in 2009 compared to 2008, primarily due to lower fuel costs. The cost of transportation services are a pass-through to our customers; consequently, we do not realize any margin on our transportation revenues.

Income tax expense (benefit). Income tax expense increased to $0.7 million in 2009 from an income tax benefit of $0.5 million in 2008. The income tax expense in 2009 and benefit in 2008 were primarily due to operations of Matrix Design.

Net income attributable to noncontrolling interest. The noncontrolling interest represents a 50% third-party interest in MAC. The third-party’s portion of MAC’s net income was $0.2 million in 2009 and $0.4 million in 2008. For more information, please read “Item 8. Financial Statements —Note 18. Noncontrolling Interest” of this Annual Report on Form 10-K.

 

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Segment Information. Our 2009 Segment Adjusted EBITDA increased 29.3% to $381.5 million from 2008 Segment Adjusted EBITDA of $295.0 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)  
     2009     2008    

Segment Adjusted EBITDA

        

Illinois Basin

   $ 315,542      $ 194,410      $ 121,132      62.3

Central Appalachia

     41,149        52,812        (11,663   (22.1 )% 

Northern Appalachia

     15,552        39,480        (23,928   (60.6 )% 

Other and Corporate

     9,621        8,264        1,357      16.4

Elimination

     (370     22        (392   (1
                          

Total Segment Adjusted EBITDA (2)

   $ 381,494      $ 294,988      $ 86,506      29.3
                          

Tons sold

        

Illinois Basin

     19,660        20,496        (836   (4.1 )% 

Central Appalachia

     2,641        3,428        (787   (23.0 )% 

Northern Appalachia

     2,660        3,246        (586   (18.1 )% 

Other and Corporate

     14        —          14      (1

Elimination

     —          —          —        —     
                          

Total tons sold

     24,975        27,170        (2,195   (8.1 )% 
                          

Coal sales

        

Illinois Basin

   $ 846,940      $ 715,862      $ 131,078      18.3

Central Appalachia

     179,369        207,339        (27,970   (13.5 )% 

Northern Appalachia

     136,412        169,858        (33,446   (19.7 )% 

Other and Corporate

     1,150        —          1,150      (1

Elimination

     —          —          —        —     
                          

Total coal sales

   $ 1,163,871      $ 1,093,059      $ 70,812      6.5
                          

Other sales and operating revenues

        

Illinois Basin

   $ 1,151      $ 1,123      $ 28      2.5

Central Appalachia

     191        258        (67   (26.0 )% 

Northern Appalachia

     3,316        4,422        (1,106   (25.0 )% 

Other and Corporate

     39,260        23,546        15,714      66.7

Elimination

     (22,491     (10,614     (11,877   (1
                          

Total other sales and operating revenues

   $ 21,427      $ 18,735      $ 2,692      14.4
                          

Segment Adjusted EBITDA Expense

        

Illinois Basin

   $ 532,549      $ 522,575      $ 9,974      1.9

Central Appalachia

     138,412        157,575        (19,163   (12.2 )% 

Northern Appalachia

     124,176        134,800        (10,624   (7.9 )% 

Other and Corporate

     30,789        20,441        10,348      50.6

Elimination

     (22,122     (10,636     (11,486   (1
                          

Total Segment Adjusted EBITDA Expense (3)

   $ 803,804      $ 824,755      $ (20,951   (2.5 )% 
                          

 

(1) Percentage increase or decrease was greater than or equal to 100%.
(2) Segment Adjusted EBITDA is defined as net income of ARLP before net interest expense, income taxes, depreciation, depletion and amortization, net income attributable to noncontrolling interest and general and administration expenses. Segment Adjusted EBITDA is a key component of consolidated EBITDA, which is used as a supplemental financial measure by 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;

 

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

 

   

our operating performance and return on investment 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.

Segment Adjusted EBITDA is also used as a supplemental financial measure by our management for reasons similar to those stated in the above explanation of EBITDA. In addition, the exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA allows management to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.

The following is a reconciliation of consolidated Segment Adjusted EBITDA to net income and Net Income of ARLP (in thousands):

 

     Year Ended December 31,  
     2009     2008  

Segment Adjusted EBITDA

   $ 381,494      $ 294,988   

General and administrative

     (41,117     (37,176

Depreciation, depletion and amortization

     (117,524     (105,278

Interest expense, net

     (29,798     (18,418

Income tax (expense) benefit

     (708     480   
                

Net income

     192,347        134,596   

Net (income) loss attributable to noncontrolling interest

     (190     (420
                

Net income of ARLP

   $ 192,157      $ 134,176   
                

 

(3) Segment Adjusted EBITDA Expense includes operating expenses, outside coal purchases and other income. Transportation expenses are excluded as these expenses are passed through to our customers and, consequently, we do not realize any gain or loss 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 coal purchases are included in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside coal purchases.

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

 

     Year Ended December 31,  
     2009     2008  

Segment Adjusted EBITDA Expense

   $ 803,804      $ 824,755   

Outside coal purchases

     (7,524     (23,776

Other income

     1,247        875   
                

Operating expense (excluding depreciation, depletion and amortization)

   $ 797,527      $ 801,854   
                

 

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Illinois Basin—Segment Adjusted EBITDA in 2009 increased 62.3% to $315.5 million from 2008 Segment Adjusted EBITDA of $194.4 million. The increase of $121.1 million was primarily attributable to improved contract pricing resulting in a higher average coal sales price of $43.08 per ton in 2009 compared to $34.93 per ton in 2008. The benefit of higher average coal sales pricing was partially offset by reduced tons sold due to first quarter 2009 weather disruptions in western Kentucky, particularly at the Dotiki, Warrior and Elk Creek mines, as well as unplanned customer outages and weakness in the spot market during 2009. Total Segment Adjusted EBITDA Expense in 2009 increased 1.9% to $532.5 million from $522.6 million in 2008. The increase in 2009 Segment Adjusted EBITDA Expense compared to 2008 was primarily the result of cost increases described above under consolidated operating expenses, the impact of weather disruptions in 2009, in addition to the $1.9 million gain on settlement of claims relating to the Pattiki Vertical Belt Incident in 2008, as discussed above under “–Analysis of Historical Results of Operations.” Segment Adjusted EBITDA Expense per ton in 2009 increased $1.59 per ton to $27.09 per ton compared to 2008 Segment Adjusted EBITDA Expense of $25.50 per ton.

Central Appalachia—Segment Adjusted EBITDA in 2009 decreased 22.1% to $41.1 million compared to $52.8 million in 2008. The decrease was primarily the result of lower sales volumes due to contract deferrals and weak coal demand in the spot market during 2009, partially offset by improved contract pricing that resulted in an increase in the average coal sales price of $7.42 per ton to $67.91 per ton in 2009 compared to $60.49 per ton in 2008. Central Appalachia coal production was also impacted by the idling of one of four continuous mining units at Pontiki’s Van Lear mine, which reduced coal production by approximately 140,000 tons. Although lower coal sales volumes resulted in a 12.2% decrease in 2009 Segment Adjusted EBITDA Expense to $138.5 million from $157.6 million in 2008, Segment Adjusted EBITDA Expense per ton sold increased by $6.44 per ton in 2009 to $52.41 per ton, or 14.0% over 2008 Segment Adjusted EBITDA per ton of $45.97. The increase in the Segment Adjusted EBITDA Expense per ton resulted in part from decreased coal production primarily due to contractual deferrals, lower spot market demand and reduced clean coal recovery resulting partly from Pontiki’s transition from the depleted Pond Creek coal seam into the thinner Van Lear coal seam in 2009 in addition to cost per ton increases described above under consolidated operating expenses. Segment Adjusted EBITDA in 2008 benefited from the $2.8 million gain recognized on settlement of claims from the third-party that provided security services at the time of the MC Mining Fire Incident as discussed below under “—MC Mining Mine Fire.”

Northern Appalachia—Segment Adjusted EBITDA decreased 60.6% to $15.6 million in 2009 compared to $39.5 million in 2008. This decrease of $23.9 million was primarily the result of lower sales volumes reflecting reduced spot market sales and higher Segment Adjusted EBITDA Expense per ton sold in 2009 of $46.68 per ton, an increase of $5.15 per ton, or 12.4%, compared to $41.53 per ton in 2008. Increased Segment Adjusted EBITDA Expense per ton in 2009 resulted primarily from lower production which was impacted by increased longwall move days in 2009, increased longwall maintenance expense per ton, lower clean coal recovery due to mining conditions and a curtailment of third-party mining operations in 2009, as well as the other cost increases described above under consolidated operating expenses, including increased expenses incurred related to our Tunnel Ridge organic growth project. Although Segment Adjusted EBITDA Expense per ton sold increased in 2009, Segment EBITDA Expense in 2009 decreased 7.9% to $124.2 million from $134.8 million in 2008, primarily as a result of lower coal sales volumes offset in part by higher expenses per ton as described above.

Other and Corporate—Segment Adjusted EBITDA increased to $9.6 million in 2009 from $8.3 million in 2008, primarily due to increased Matrix Design and Alliance Design product sales and service revenues and Mt. Vernon transloading revenue in 2009, partially offset by decreased MAC product sales in 2009 and a $5.2 million gain on sale of non-core coal reserves in 2008. In addition, during 2009, we purchased a six-month United Kingdom treasury bill which matured in October 2009, resulting in a gain of $0.7 million. The increase in Segment Adjusted EBITDA Expense primarily reflects increased costs associated with higher outside services revenue and product sales.

2008 Compared with 2007

In 2008, we reported Net Income of ARLP of $134.2 million, a decrease of 21.3% compared to 2007 Net Income of ARLP of $170.4 million. This decrease of $36.2 million was principally due to the significant items discussed above at the beginning of “Analysis of Historical Results of Operations,” in addition to higher depreciation, depletion and amortization resulting from capital expenditures associated with our growth initiatives and increased interest expense, net of interest income resulting from our 2008 financing activities, partially offset by improved coal sales. We had tons sold and tons produced of 27.2 million and 26.4 million, respectively, in 2008 compared to 24.7 million tons sold and 24.3 million tons produced in 2007. Operating expenses in 2008 increased primarily as a result of higher coal production and sales volumes as well as increased labor and labor related expenses, materials and supply costs, maintenance costs, higher regulatory compliance costs and other factors described below.

 

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     December 31,    December 31,
   2008    2007    2008    2007
     (in thousands)    (per ton sold)

Tons sold

     27,170      24,725      N/A      N/A

Tons produced

     26,429      24,269      N/A      N/A

Coal sales

   $ 1,093,059    $ 960,354    $ 40.23    $ 38.84

Operating expenses and outside coal purchases

   $ 825,630    $ 707,054    $ 30.39    $ 28.60

Coal sales. Coal sales increased 13.8% to $1.1 billion in 2008 from $960.4 million in 2007. The increase of $132.7 million reflected increased sales volumes (contributing $94.9 million of the increase) and higher average coal sales prices (contributing $37.8 million of the increase). Tons sold increased 9.9% to 27.2 million tons in 2008 from 24.7 million tons in 2007. Tons produced increased 8.9% to 26.4 million tons in 2008 from 24.3 million tons in 2007. Average coal sales prices increased $1.39 per ton sold to $40.23 per ton in 2008 compared to 2007, primarily as a result of improved contract pricing across all operations, as well as from certain higher priced sales in the spot and export markets, particularly in the Central and Northern Appalachian segments.

Operating expenses. Operating expenses increased 17.0% to $801.9 million in 2008 from $685.1 million in 2007 primarily as a result of increased production and tons sold, as well as the following factors:

 

   

Labor and benefit expenses per ton produced, excluding workers’ compensation costs, increased 7.6% to $9.51 per ton in 2008 from $8.84 per ton in 2007. This increase of $0.67 per ton represents pay rate and benefit increases and increased health care costs, as well as increased headcount due to capacity expansion and increased regulatory compliance;

 

   

Material and supplies and maintenance expenses per ton produced increased 10.6% and 8.5%, respectively, to $9.84 and $3.31 per ton, respectively, in 2008 from $8.90 and $3.05 per ton, respectively, in 2007. The respective increases of $0.94 and $0.26 per ton resulted from increased costs for certain products and services (particularly roof support, power, fuel and other consumables) used in the mining process, as well as higher compliance costs associated with more stringent regulatory enforcement which has also contributed to increased mine administrative expenses;

 

   

Expenses incurred during 2008 relating to our River View and Tunnel Ridge organic growth projects increased $2.6 million over 2007;

 

   

Production taxes and royalties (which were incurred as a percentage of coal sales and coal volumes) increased $3.3 million as a result of increased tons sold and increased average coal sales prices;

 

   

Reduced expenses of $6.0 million in 2008 compared to 2007 were associated with the purchase and sale of coal during 2007 under a settlement agreement we entered into with ICG, Inc. (“ICG”) in November 2005. Consistent with the guidance in FASB ASC 845, Nonmonetary Transactions (EITF No. 04-13 Accounting for Purchases and Sales of Inventory with the Same Counterparty), Pontiki’s coal sales to ICG and Alliance Coal’s purchases from ICG pursuant to that settlement agreement were combined. Therefore, the excess of Alliance Coal’s purchase price from ICG over Pontiki’s sales price to ICG was reported as an operating expense. We fully satisfied our coal sales agreement with ICG in April 2007:

 

   

2008 benefited from a $1.9 million gain on settlement of claims relating to the Vertical Belt Incident at our Pattiki mine;

 

   

2007 included a $0.8 million reduction in operating expenses as a result of the final insurance settlement of the MC Mining Fire Incident; and

 

   

The 2007 operating expenses benefited from net gains of $3.2 million realized from the sale of surplus equipment compared to net gains of $0.9 million realized in 2008.

 

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Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, products and services provided by MAC and Matrix Design, and other outside services and administrative services revenue from affiliates. The 2007 other sales and operating revenues include rental and service fees from third-party coal synfuel facilities. Other sales and operating revenues decreased to $18.7 million in 2008 from $35.3 million in 2007. The decrease of $16.6 million was primarily attributable to the loss of synfuel-related benefits due to the expiration of the non-conventional synfuel tax credits on December 31, 2007, partially offset by increased revenues from transloading services and MAC and Matrix Design product sales. Our synfuel-related arrangements are discussed in more detail above under “—Executive Overview.”

Outside coal purchases. Outside coal purchases increased $1.8 million to $23.8 million in 2008 from $22.0 million in 2007. The increase was primarily attributable to an increase in outside coal purchases in our Northern Appalachian region to supply attractive spot and export market opportunities partially offset by lower purchases in the Illinois Basin and Central Appalachian regions.

General and administrative. General and administrative expenses in 2008 increased to $37.2 million compared to $34.5 million in 2007. The increase of $2.7 million was primarily attributable to higher salary and benefit costs related to increased staffing levels and higher incentive compensation expense.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased to $105.3 million in 2008 compared to $85.3 million in 2007. The increase of $20.0 million was primarily attributable to additional depreciation expense associated with continuing capital expenditures related to infrastructure improvements, efficiency projects, reserve acquisitions and expansion of production capacity.

Interest expense. Interest expense, net of capitalized interest, increased to $22.1 million in 2008 from $11.7 million in 2007. The increase of $10.4 million was principally attributable to interest expense resulting from our 2008 financing activities, partially offset by reduced interest expense resulting from our August 2008 principal repayment of $18.0 million on our senior notes issued in 1999. The 2008 financing activities are discussed in more detail below under “–Debt Obligations.”

Interest income. Interest income increased to $3.7 million in 2008 from $1.7 million in 2007. The increase of $2.0 million resulted from increased interest income earned on short-term investments purchased with funds received from our 2008 financing activities.

Transportation revenues and expenses. Transportation revenues and expenses each increased 18.8% to $44.8 million in 2008 compared to $37.7 million in 2007. The increase of $7.1 million in 2008 was primarily attributable to higher transported coal volumes and higher average per ton transportation rates compared to 2007, primarily reflecting higher fuel costs and the location of our customers for which we arranged transportation. The cost of transportation services are passed through to our customers; consequently, we do not realize any gain or loss on our transportation revenues.

Income tax expense (benefit). Income tax benefit in 2008 was $0.5 million compared to income tax expense of $1.7 million in 2007. The income tax benefit in 2008 was primarily due to operating losses associated with Matrix Design, a business owned by our subsidiary, Alliance Service, Inc. (“Alliance Service”). The 2007 income tax expense was impacted by Alliance Service’s receipt of a material amount of income from services we provided to a third-party coal synfuel facility, which ceased operations on December 31, 2007 as a result of the expiration of the synfuel tax credits. Our synfuel-related arrangements are discussed in more detail above under “—Executive Overview.”

Net income attributable to noncontrolling interest. The noncontrolling interest represents a 50% third-party interest in MAC. The third-party’s portion of MAC’s net income and net loss was $0.4 million and $0.3 million in 2008 and 2007, respectively. For more information, please read “Item 8. Financial Statements —Note 18. Noncontrolling Interest” of this Annual Report on Form 10-K.

 

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Segment Information. Our 2008 Segment Adjusted EBITDA decreased $6.5 million, or 2.1%, to $295.0 million from 2007 Segment Adjusted EBITDA of $301.5 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)  
     2008     2007    

Segment Adjusted EBITDA

        

Illinois Basin

   $ 194,410      $ 208,658      $ (14,248   (6.8 )% 

Central Appalachia

     52,812        58,937        (6,125   (10.4 )% 

Northern Appalachia

     39,480        35,478        4,002      11.3

Other and Corporate

     8,264        (1,605     9,869      (1

Elimination

     22        —          22      —     
                          

Total Segment Adjusted EBITDA (2)

   $ 294,988      $ 301,468      $ (6,480   (2.1 )% 
                          

Tons sold

        

Illinois Basin

     20,496        17,970        2,526      14.1

Central Appalachia

     3,428        3,455        (27   (0.8 )% 

Northern Appalachia

     3,246        3,300        (54   (1.6 )% 

Other and Corporate

     —          —          —        —     

Elimination

     —          —          —        —     
                          

Total tons sold

     27,170        24,725        2,445      9.9
                          

Coal sales

        

Illinois Basin

   $ 715,862      $ 612,850      $ 103,012      16.8

Central Appalachia

     207,339        193,104        14,235      7.4

Northern Appalachia

     169,858        147,315        22,543      15.3

Other and Corporate

     —          7,085        (7,085   (1

Elimination

     —          —          —        —     
                          

Total coal sales

   $ 1,093,059      $ 960,354      $ 132,705      13.8
                          

Other sales and operating revenues

        

Illinois Basin

   $ 1,123      $ 25,371      $ (24,248   (95.6 )% 

Central Appalachia

     258        99        159      (1

Northern Appalachia

     4,422        4,201        221      5.3

Other and Corporate

     23,546        10,423        13,123      (1

Elimination

     (10,614     (4,802     (5,812   (1
                          

Total other sales and operating revenues

   $ 18,735      $ 35,292      $ (16,557   (46.9 )% 
                          

Segment Adjusted EBITDA Expense

        

Illinois Basin

   $ 522,575      $ 429,563      $ 93,012      21.7

Central Appalachia

     157,575        145,759        11,816      8.1

Northern Appalachia

     134,800        116,037        18,763      16.2

Other and Corporate

     20,441        19,112        1,329      7.0

Elimination

     (10,636     (4,802     (5,834   (1
                          

Total Segment Adjusted EBITDA Expense (3)

   $ 824,755      $ 705,669      $ 119,086      16.9
                          

 

(1) Percentage increase or decrease was greater than or equal to 100%.
(2) Segment Adjusted EBITDA is defined as net income of ARLP before net interest expense, income taxes, depreciation, depletion and amortization, net income attributable to noncontrolling interest and general and administrative expenses. Segment Adjusted EBITDA is a key component of consolidated EBITDA, which is used as a supplemental financial measure by 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;

 

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

 

   

our operating performance and return on investment 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.

Segment Adjusted EBITDA is also used as a supplemental financial measure by our management for reasons similar to those stated in the above explanation of EBITDA. In addition, the exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA allows management to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses which are primarily controlled by our segments.

The following is a reconciliation of consolidated Segment Adjusted EBITDA to net income and Net Income of ARLP (in thousands):

 

     Year Ended December 31,  
     2008     2007  

Segment Adjusted EBITDA

   $ 294,988      $ 301,468   

General and administrative

     (37,176     (34,479

Depreciation, depletion and amortization

     (105,278     (85,310

Interest expense, net

     (18,418     (9,952

Income tax (expense) benefit

     480        (1,669
                

Net income

     134,596        170,058   

Net (income) loss attributable to noncontrolling interest

     (420     332   
                

Net income of ARLP

   $ 134,176      $ 170,390   
                

 

(3) Segment Adjusted EBITDA Expense includes operating expenses, outside coal purchases and other income. Transportation expenses are excluded as these expenses are passed through to our customers, and consequently we do not realize any gain or loss 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 coal purchases are included in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside coal purchases.

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

 

     Year Ended December 31,  
     2008     2007  

Segment Adjusted EBITDA Expense

   $ 824,755      $ 705,669   

Outside coal purchases

     (23,776     (21,969

Other income

     875        1,385   
                

Operating expense (excluding depreciation, depletion and amortization)

   $ 801,854      $ 685,085   
                

 

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Illinois Basin—Segment Adjusted EBITDA decreased 6.8% in 2008 to $194.4 million, compared to 2007 Segment Adjusted EBITDA of $208.7 million. The decrease of $14.3 million is primarily attributable to the loss of synfuel-related benefits and higher operating expenses partially offset by increased coal sales and a $1.9 million gain on settlement of claims relating to the Pattiki Vertical Belt Incident. Other sales and operating revenues decreased by $24.2 million due to the expiration of the non-conventional synfuel tax credits on December 31, 2007 and the resulting loss of benefits derived from supplying third-party coal synfuel facilities with coal feedstock and related services. Our synfuel-related arrangements are discussed in more detail above under “—Executive Overview.” Illinois Basin coal sales in 2008 increased by $103.0 million to $715.9 million compared to $612.9 million in 2007, primarily as a result of increased tons sold of 2.5 million tons (contributing $86.0 million of the increase in coal sales) reflecting increased production capacity at the Elk Creek and Warrior mines and increased production at the Dotiki and Gibson mines. Additionally, increased coal sales in 2008 resulted from a higher average coal sales price per ton, which increased 2.4% to $34.93 per ton in 2008 compared to $34.10 per ton in 2007 (contributing $17.0 million of the total increase in coal sales). The 2008 average coal sales prices benefited from improved long-term contract realizations. Total Segment Adjusted EBITDA Expense in 2008 increased 21.7% to $522.6 million from $429.6 million in 2007, primarily as a result of production costs and sales related expenses associated with increased tons sold, as well as the impact of the cost increases described above under consolidated operating expenses. The 2007 Segment Adjusted EBITDA Expense also benefited from certain favorable operating tax adjustments. On a per ton sold basis, 2008 Segment Adjusted EBITDA Expense increased $1.60 to $25.50 per ton compared to the 2007 Segment Adjusted EBITDA Expense of $23.90 per ton.

Central Appalachia—Segment Adjusted EBITDA in 2008 decreased 10.4% to $52.8 million, compared to 2007 Segment Adjusted EBITDA of $58.9 million. The $6.1 million decrease was primarily the result of the net gain from insurance settlement of approximately $11.5 million and a reduction in operating expenses of approximately $0.8 million in 2007 related to the MC Mining Fire Incident, compared to a $2.8 million gain recognized in 2008 on settlement of claims from the third-party that provided security services at the time of the fire. Please read “—MC Mining Mine Fire” below. Central Appalachia coal sales in 2008 and 2007 were $207.3 million and $193.1 million, respectively, an increase of $14.2 million primarily resulting from a higher average coal sales price per ton, which increased $4.60 to $60.49 per ton in 2008 compared to $55.89 per ton in 2007 (contributing $15.7 million of the total increase in coal sales). Higher 2008 average coal sales prices reflect both improved contract sales prices, as well as certain higher priced sales in the spot and export markets. Segment Adjusted EBITDA Expense in 2008 increased 8.1% to $157.6 million, compared to $145.8 million in 2007. Segment Adjusted EBITDA Expense per ton increased $3.78 to $45.97 per ton in 2008, compared to $42.19 per ton in 2007 resulting from a lower percentage of salable tons recovered from raw production, increased labor and benefits expense, as well as other cost increases described above under consolidated operating expenses.

Northern Appalachia—Segment Adjusted EBITDA in 2008 increased 11.3% to $39.5 million, compared to 2007 Segment Adjusted EBITDA of $35.5 million. The increase of $4.0 million in Segment Adjusted EBITDA was primarily attributable to a higher average sales price of $52.33 per ton during 2008 compared to $44.64 per ton during 2008, resulting from improved pricing on long-term sales contracts and certain higher priced sales in the spot and export markets. Segment Adjusted EBITDA Expense per ton sold during 2008 of $41.53 per ton was an increase of $6.37 per ton compared to $35.16 per ton in 2007. The increase in Segment Adjusted EBITDA Expense per ton sold was primarily a result of higher purchased coal expense, lower production in 2008 and increased power costs, coal transportation costs, water treatment costs and contract mining expenses. The decreased production in 2008 reflects adverse mining conditions and reduced salable coal recoveries compared to 2007.

Other and Corporate—Segment Adjusted EBITDA increased to $8.3 million in 2008 from a loss of $1.6 million in 2007, primarily due to the $5.2 million gain on sale of non-core coal reserves and increased outside services revenue and product sales in 2008. The increase in Segment Adjusted EBITDA Expense primarily reflects increased expenses associated with higher outside services revenue and product sales.

Elimination—The increase is primarily comprised of the elimination of sales and operating expenses between MAC and Matrix Design 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 the MC Mining Fire Incident. 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 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. In May 2008, we realized a $2.8 million gain on settlement of our claim against the third-party that provided security services at the time of the fire.

 

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Ongoing Acquisition Activities

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

Liquidity and Capital Resources

Liquidity

We have historically satisfied our working capital requirements and funded our capital expenditures and debt service obligations from cash generated from operations, cash provided by the issuance of debt or equity and borrowings under revolving credit facilities. We believe that the current cash on hand, cash generated from operations, cash from borrowings under our current credit facility, and cash provided from the issuance of debt or equity will be sufficient to meet our working capital requirements, anticipated capital expenditures, scheduled debt payments and distribution payments. Our ability to satisfy our obligations and planned expenditures will depend upon our future operating performance and access to and cost of financing sources, which will be affected by prevailing economic conditions generally and in the coal industry specifically, which are beyond our control. Based on our recent operating results, current cash position, anticipated future cash flows and sources of financing that we expect to have available, we do not anticipate any significant liquidity constraints in the foreseeable future. However, to the extent operating cash flow or access to and cost of financing sources are materially different than expected, future liquidity may be adversely affected. Please see “Item 1A. Risk Factors” above.

Cash Flows

Cash provided by operating activities was $282.7 million in 2009, compared to $261.0 million in 2008. The increase in cash provided by operating activities was principally attributable to higher net income, partially offset by reduced cash flow related to increases in certain operating assets, such as trade receivables and inventories and decreases in certain operating liabilities, such as account payable.

Net cash used in investing activities was $320.1 million in 2009, compared to $184.1 million in 2008. The increase in cash used for investing activities was primarily attributable to an increase in capital expenditures for the continuing mine development at the River View and Tunnel Ridge growth projects. There were no significant acquisitions or sales of coal reserves and other assets in 2009 compared to $29.8 million net use of cash on such transactions in 2008.

Net cash used in financing activities was $186.6 million in 2009, compared to net cash provided by financing activities of $166.8 million in 2008. The decrease in cash provided by financing activities was primarily attributable to an absence of additional proceeds from borrowings in 2009 compared to proceeds in 2008 that included issuance of the of the $350 million of senior notes in a private placement (see “–Debt Obligations”) in addition to increased distributions paid to partners in 2009.

 

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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 on hand, 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, 2009 (in thousands):

 

Contractual

Obligations

   Total    Less
than 1
year
   1-3
years
   3-5
years
   More than
5 years

Long-term debt

   $ 440,000    $ 18,000    $ 36,000    $ 36,000    $ 350,000

Future interest obligations on senior notes

     175,817      30,097      55,707      49,723      40,290

Operating leases

     9,331      5,059      2,161      734      1,377

Capital leases(1)

     1,577      504      788      285      —  

Reclamation obligations(2)

     123,891      2,735      4,541      5,325      111,290

Purchase obligations for capital projects

     85,903      85,903      —        —        —  

Workers’ compensation and pneumoconiosis benefit(2)

     248,621      12,987      19,307      16,137      200,190
                                  
   $ 1,085,140    $ 155,285    $ 118,504    $ 108,204    $ 703,147
                                  

 

(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 $9.8 million to the defined benefit pension plan (“Pension Plan”) during 2010. We estimate our income tax cash requirements to be approximately $0.8 million in 2010.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include related party 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, 2009 (in thousands):

 

     Reclamation
Obligation
   Workers’
Compensation
Obligation
   Other    Total

Surety bonds

   $ 62,511    $ 22,024    $ 2,251    $ 86,786

Letters of credit

     —        44,847      9,548      54,395

Capital Expenditures

Capital expenditures increased to $328.2 million in 2009 compared to $176.5 million in 2008. See our discussion of “Cash Flows” above concerning this increase in capital expenditures.

We currently project average estimated annual maintenance capital expenditures of approximately $4.00 per ton produced. Our anticipated total capital expenditures for 2010 are estimated in a range of $275 to $315 million. Management anticipates funding 2010 capital requirements with our December 31, 2009 cash and cash equivalents of $21.6 million, cash flows provided by operations and borrowing available under our revolving credit facility as discussed below. 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 and cost 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.

Insurance

During September 2009, we completed our annual property and casualty insurance renewal with various insurance coverages effective October 1, 2009. As in past years, we have elected to retain a participating interest in our commercial property insurance program at an average rate of approximately 14.7% in the overall $75.0 million of coverage, representing 22% of the primary $50.0 million layer. We do not participate in the second layer of $25.0 million in excess of $50.0 million.

 

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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 are responsible for a maximum amount of $11.0 million for each occurrence, excluding a $1.5 million deductible for property damage, a $5.0 million aggregate deductible for extra expense and a 60-day waiting period for business interruption. 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

Credit Facility. Our Intermediate Partnership has a $150.0 million revolving credit facility (“ARLP Credit Facility”) dated September 25, 2007, which matures in 2012. On September 30, 2009, our Intermediate Partnership entered into Amendment No. 2 (the “Credit Amendment”) to the ARLP Credit Facility. The Credit Amendment increased the annual capital expenditure limits under the ARLP Credit Facility. The new limits, excluding capital expenditures related to acquisitions, were $425.0 million for 2009, $375.0 million for 2010, $350.0 million for 2011 and $250.0 million for 2012. The amount of any annual limit in excess of actual capital expenditures for that year carries forward and is added to the annual limit of the subsequent year. As a result, the capital expenditure limit for 2010 is approximately $471.8 million.

Pursuant to the Credit Amendment, the applicable margin for London Interbank Offered Rate borrowings under the ARLP Credit Facility was increased from a range of 0.625% to 1.150% (depending on the Intermediate Partnership’s leverage margin) to a range of 1.115% to 2.000%, and the annual commitment fee was increased from a range of 0.15% to 0.35% (also depending on the Intermediate Partnership’s leverage margin) to a range of 0.25% to 0.50%. In addition, the Credit Amendment includes certain changes relating to a “defaulting lender,” including changes which clarify that the overall ARLP Credit Facility commitment would be reduced by the commitment share of a defaulting lender but also provides our Intermediate Partnership with more flexibility in replacing a defaulting lender.

At December 31, 2009, we had $23.3 million of letters of credit outstanding with $126.7 million available for borrowing under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility as of December 31, 2009. We incur an annual commitment fee of 0.375% on the undrawn portion of the ARLP Credit Facility.

Lehman Commercial Paper, Inc. (“Lehman”), a subsidiary of Lehman Brothers Holding, Inc., holds a 5%, or $7.5 million, commitment in our $150 million ARLP Credit Facility. The ARLP Credit Facility is underwritten by a syndicate of twelve financial institutions, including Lehman, with no individual institution representing more than 11.3% of the $150 million revolving credit facility. Lehman filed for protection under Chapter 11 of the Federal Bankruptcy Code in early October 2008. In the event Lehman, or any other financial institution in our syndicate, does not fund our future borrowing requests, our borrowing availability under the ARLP Credit Facility would be reduced. The obligations of the lenders under our credit facility are individual obligations and the failure of one or more lenders does not relieve the remaining lenders of their funding obligations. On February 11, 2010, we gave our lenders a notice of borrowing under the ARLP Credit Facility and, in response to that notice, Lehman notified us that it would not fund its proportionate share of the borrowing. As a result, as of February 11, 2010, Lehman became a defaulting lender and availability for borrowing under the ARLP Credit Facility was reduced by $7.5 million, unless and until we replace Lehman as a lender.

Senior Notes. Our Intermediate Partnership has $90.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in five remaining equal annual installments of $18.0 million with interest payable semi-annually (“Senior Notes”).

Series A Senior Notes. On June 26, 2008, our Intermediate Partnership entered into a Note Purchase Agreement (the “2008 Note Purchase Agreement”) with a group of institutional investors in a private placement offering. We issued $205.0 million of Series A Senior Notes, which bear interest at 6.28% and mature on June 26, 2015 with interest payable semi-annually.

 

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Series B Senior Notes. On June 26, 2008, we issued under the 2008 Note Purchase Agreement $145.0 million of Series B Senior Notes, which bear interest at 6.72% and mature on June 26, 2018 with interest payable semi-annually.

The proceeds from the Series A and Series B Senior Notes (collectively, the “2008 Senior Notes”) were used to repay $21.5 million outstanding under the ARLP Credit Facility and pay expenses associated with the offering of the 2008 Senior Notes. The remaining proceeds were primarily used to fund the development of the River View and Tunnel Ridge mining complexes and for other general working capital requirements. We incurred debt issuance costs of approximately $0.3 million in 2009 associated with the ARLP Credit Facility and $1.7 million in 2008 associated with the 2008 Senior Notes, which have been deferred and are being amortized as a component of interest expense over the term of the respective notes.

The ARLP Credit Facility, Senior Notes and 2008 Senior Notes (collectively, the “ARLP Debt Arrangements”) are guaranteed by all of the direct and indirect subsidiaries of our Intermediate Partnership. The ARLP Debt Arrangements 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 ARLP Debt Arrangements also require the Intermediate Partnership to remain in control of a certain amount of mineable coal reserves relative to its annual production. In addition, the ARLP Debt Arrangements require our Intermediate Partnership to maintain (i) a minimum debt to cash flow ratio of not more than 3.0 to 1.0, (ii) a ratio of cash flow to interest expense of not less than 4.0 to 1.0 in each case, during the four most recently ended fiscal quarters and (iii) maximum annual capital expenditures, excluding acquisitions as described above. The Credit Amendment did not change the required minimum debt to cash flow or cash flow to interest expense ratios. The debt to cash flow ratio, cash flow to interest expense ratio and actual capital expenditures were 1.3 to 1.0, 10.8 to 1.0, and $328.2 million for the trailing twelve months ended December 31, 2009. We were in compliance with the covenants of the ARLP Debt Arrangements as of December 31, 2009.

Other. In addition to the letters of credit available under the ARLP Credit Facility discussed above, we also have agreements with two banks to provide additional letters of credit in an aggregate amount of $31.1 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers’ compensation benefits. At December 31, 2009, we had $31.1 million in letters of credit outstanding under agreements with these two banks. 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. By amendment effective April 1, 2008, the term of the Revolver was extended to June 30, 2009. On November 17, 2009, MAC entered into Amendment No. 2, effective June 30, 2009, which increased the Revolver to $1.75 million. The Revolver is scheduled to expire on December 31, 2010. Due to the consolidation of MAC in accordance with FASB ASC 810, the intercompany transactions associated with the Revolver are eliminated for our financials presented.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S. The preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. We discuss these estimates and judgments with our MGP’s Audit Committee periodically. Actual results may differ from these estimates. We have provided a description of all significant accounting policies in the notes to our consolidated financial statements. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of our consolidated financial statements:

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.

 

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Non-coal sales revenues primarily consist of transloading fees, administrative service revenues from our affiliates, mine safety services and products, rock dust sales and other handling and service fees. For 2007, non-coal sales revenues included rental and service fees from third-party coal synfuel facilities, agreements related to these services expired on December 31, 2007 in conjunction with the expiration of non-conventional synfuel tax credits. These non-coal sales revenues are recognized when the following criteria are met: persuasive evidence of an arrangement exists; delivery has occurred or services have been rendered; the seller’s price to the buyer is fixed or determinable; and collectability is reasonably assured.

Coal Reserve Values

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:

 

   

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;

 

   

the percentage of coal in the ground ultimately recoverable;

 

   

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

 

   

the assumed effects of regulation and taxes by governmental agencies; and

 

   

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. Certain account classifications within our financial statements such as depreciation, depletion, and amortization and certain liability calculations such as asset retirement obligations may depend upon estimates of coal reserve quantities and values. Accordingly, when actual coal reserve quantities and values vary significantly from estimates, certain accounting estimates and amounts within our consolidated financial statements may be materially impacted. Coal reserve values are reviewed annually, at a minimum, for consideration in our consolidated financial statements.

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 $63.2 million and $56.7 million for these costs at December 31, 2009 and 2008, respectively. A one-percentage-point reduction in the discount rate would have increased the liability at December 31, 2009 approximately $4.4 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 $34.9 million and $32.0 million for these benefits at December 31, 2009 and 2008, respectively. A one-percentage-point reduction in the discount rate would have increased the expense recognized for the year ended December 31, 2009 by approximately $0.8 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.

 

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Defined Benefit Plan

Eligible employees at certain of our mining operations participate in a Pension Plan that we sponsor. The benefit formula for the Pension Plan is a fixed dollar unit based on years of service. The calculation of our net periodic benefit cost (pension expense) and benefit obligation (pension liability) associated with our Pension Plan requires the use of a number of assumptions. Changes in these assumptions can result in materially different pension expense and pension liability amounts. In addition, actual experiences can differ materially from the assumptions. Significant assumptions used in calculating pension expense and pension liability are as follows:

 

   

Our expected long-term rate of return assumption is based on broad equity and bond indices, the investment goals and objectives, the target investment allocation and on the long term historical rates of return for each asset class. Our expected long-term rate of return used to determine our pension liability and our pension expense was 8.35% for the years ended December 31, 2009 and 2008, determined by the above factors and an asset allocation assumption of 70.0% invested in domestic equity securities with an expected long-term rate of return of 9.25%, 10.0% invested in international equities with an expected long-term rate of return of 6.45% and 20.0% invested in fixed income securities with an expected long-term rate of return of 6.10%. Our expected long-term rate of return is based on a 20 year average annual total return for each investment group. Additionally, we base our determination of pension expense on a smoothed market-related valuation of assets equal to the fair value of assets, which immediately recognizes all investment gains or losses Our actual return gain/(loss) on plan assets was 23.7% and (27.2)% for the years ended December 31, 2009 and 2008, respectively. Lowering the expected long-term rate of return assumption by 1.0% (from 8.35% to 7.35%) at December 31, 2008 would have increased our pension expense for the year ended December 31, 2009 by approximately $0.3 million;

 

   

Our weighted average discount rate used to determine our pension liability was 5.88% and 6.15% at December 31, 2009 and 2008, respectively. Our weighted average discount rate used to determine our pension expense was 6.15% and 6.70% at December 31, 2009 and 2008, respectively. 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. Lowering the discount rate assumption by 0.5% (from 6.15% to 5.65%) at December 31, 2008 would have increased our pension expense for the year ended December 31, 2009 by approximately $0.5 million;

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. Long-lived assets and certain intangibles are not reviewed for impairment unless an impairment indicator is noted. Several examples of impairment indicators include:

 

   

A significant decrease in the market price of a long-lived asset;

 

   

A significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset; or

 

   

A significant adverse change in the extent or manner in which a long-lived is being used or in its physical condition.

The above factors are not all inclusive, and management must continually evaluate whether other factors are present that would indicate a long-lived asset may be impaired. 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.

 

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Mine Development Costs

Mine development costs are capitalized until production, other than production incidental to the mine development process, commences and are amortized on a units of production method based on the estimated proven and probable reserves. 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. Our estimate of when construction of the mine for economic extraction is substantially complete is based upon a number of assumptions, such as expectations regarding the economic recoverability of reserves, the type of mine under development, and completion of certain mine requirements, such as ventilation. 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. At December 31, 2009 and 2008, mine development costs include $16.4 million and $17.5 million, respectively, representing the carrying value of development costs attributable to properties where we are not currently engaged in mining operations or leasing to third-parties, and therefore, the mine development costs are not currently being depleted. We believe that the carrying value of these development costs will be recovered.

Asset Retirement Obligations

SMCRA and similar state statutes require that mined property be restored in accordance with specified standards and an approved reclamation plan. A liability is recorded 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. Accrued liabilities of $55.9 million and $58.6 million for these costs are recorded at December 31, 2009 and 2008, respectively. The liability for asset retirement and closing procedures is sensitive to changes in cost estimates and estimated mine lives.

On at least an annual basis, we review our entire asset retirement obligation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Adjustments to the liability resulted in a decrease of $4.9 million for the year ended December 31, 2009 and an increase in the liability of $0.3 million for the year ended December 31, 2008. These adjustments to the liability for the years ended December 31, 2009 and 2008 were primarily attributable to decreased refuse site reclamation disturbances at Hopkins County Coal and White County Coal operations and the impact of favorable permit requirements regarding reduced liner and cover necessary for refuse storage at Gibson County Coal, as well as overall general changes in inflation and discount rates, current estimates of the costs and scope of remaining reclamation work, and fluctuations in projected mine life estimates for coal reserve increases and decreases across all operations offset in part by increased surface disturbances as a result of the new mine development work at Tunnel Ridge and River View.

While the precise amount of these future costs cannot be determined with certainty, we have estimated the costs and timing of future asset retirement obligations escalated for inflation, then discounted and recorded at the present value of those estimates. Discounting resulted in reducing the accrual for asset retirement obligations by $68.0 million and $65.2 million at December 31, 2009 and 2008. We estimate that the aggregate undiscounted cost of final mine closure is approximately $123.9 million at December 31, 2009. If our assumptions differ from actual experiences, or if changes in the regulatory environment occur, our actual cash expenditures and costs that we incur could be materially different than currently estimated.

Contingencies

We are currently involved in certain legal proceedings. Our estimates of the probable costs and probability of resolution of these claims are based upon a number of assumptions, which we have developed in consultation with legal counsel involved in the defense of these matters and based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. 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.

 

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Universal Shelf

In April 2009, we filed with the SEC a universal shelf registration statement allowing us to issue from time to time up to an aggregate of $500 million of debt or equity securities. At February 23, 2010, we had not utilized any amounts available under this registration statement.

Related–Party Transactions

The Board of Directors and its conflicts committee (“Conflicts Committee”) review each of our related-party transactions to determine that such transactions reflect 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 AHGP IPO in 2006, ARLP entered into an Administrative Services Agreement between our managing general partner, our Intermediate Partnership, AHGP and its general partner AGP, and ARH II, the indirect parent of SGP. Under the Administrative Services Agreement, certain employees, including some executive officers, provide 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 $0.4 million for each of the years ended December 31, 2009 and 2008 and $0.3 million for the year ended December 31, 2007, from AHGP and $0.5 million for each of the years ended December 31, 2009 and 2008 and $0.4 million from ARH II for the year ended December 31, 2007. 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 $1.1 million, $0.3 million and $0.9 million for the years ended December 31, 2009, 2008 and 2007, respectively. The increase from 2008 to 2009 was primarily attributable to increased unit-based directors’ compensation accruals due to an increase in market value of our common units from the beginning of the year compared to the end of the year. The decrease from 2007 to 2008 was primarily attributable to lower unit-based directors’ compensation accruals due to a decrease in market value of our common units from the beginning of the year compared to the end of the year.

Managing General Partner Contribution

During 2008 and 2007, an affiliated entity controlled by Joseph W. Craft III, contributed 25,898 and 50,980 AHGP common units, respectively, valued at approximately $0.6 million and $1.1 million, respectively, at the time of contribution and $0.8 million of cash for each of the years 2008 and 2007 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. Concurrent with this contribution, Alliance Coal distributed the 25,898 and 50,980 AHGP common units to certain employees and recognized compensation expense of $1.4 million and $1.9 million in 2008 and 2007, respectively. 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 its contribution.

 

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SGP Land, LLC

On May 2, 2007, SGP Land, LLC (“SGP Land”), a subsidiary of our special general partner that is controlled by Mr. Craft, entered into a time sharing agreement with Alliance Coal, our operating subsidiary, concerning the use of aircraft owned by SGP Land. In accordance with the provisions of the time sharing agreement as amended, we reimbursed SGP Land $0.7 million for the years ended December 31, 2009 and 2008, respectively, and $0.3 million for the year ended December 31, 2007 for use of the aircraft.

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 below. 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, are eliminated in our consolidated financial statements as of December 31, 2009 and 2008.

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 for the year ended December 31, 2007 and had recouped all but $3.2 million of the advance royalty payments made under the lease. As described above, this mineral lease and sublease is now with Alliance Resource Properties.

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, and therefore the annual minimum royalty payment of $2.3 million was no longer required. Warrior paid royalties of $1.3 million for the year ended December 31, 2007 and had recouped all advance royalty payments made in accordance with these lease terms. As described above, this mineral lease and sublease is now with Alliance Resource Properties.

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 to SGP Land, are fully recoupable against future earned royalty payments. Hopkins County Coal paid to SGP Land advance minimum royalties and/or option fees of $0.7 million for the year ended December 31, 2007 and had recouped all but $4.4 million under the Coal Lease Agreements. As described above, this mineral lease and sublease is now with Alliance Resource Properties.

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 for the year ended December 31, 2007, for the base lease obligations.

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 during each of the years ended December 31, 2009, 2008 and 2007, respectively. As of December 31, 2009, $1.8 million of advance minimum royalties paid under the lease is available for recoupment, and management expects that it will be recouped against future production.

 

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SGP

In January 2005, we acquired Tunnel Ridge from ARH. In connection with this acquisition, we assumed a coal lease with 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 the years ended December 31, 2009, 2008 and 2007. As of December 31, 2009, $15.0 million of advance minimum royalties paid under the lease is available for recoupment and management expects that it will be recouped against future production.

Tunnel Ridge also controls surface land and other tangible assets under a separate lease agreement with SGP. Under the terms of the lease agreement, Tunnel Ridge has paid and will continue to pay SGP an annual lease payment of $0.2 million. The lease agreement has an initial term of four years, which may be extended to match the term of the coal lease. Lease expense was $0.2 million for each of the years ended December 31, 2009, 2008 and 2007, respectively.

We have a noncancelable operating lease arrangement with 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 years ended December 31, 2009, 2008 and 2007 was $2.6 million, respectively.

We have agreements with two banks to provide letters of credit in an aggregate amount of $31.1 million. At December 31, 2009, we had $31.1 million in outstanding letters of credit under these agreements. SGP guarantees $5.0 million of these outstanding letters of credit. SGP does not charge us for this guarantee. Since the guarantee is made on behalf of entities within the consolidated partnership, the guarantee has no fair value under FASB ASC 460, Guarantees (FASB Interpretation No. (“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 $170.3 million and $162.0 million at December 31, 2009 and 2008. 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 16. Asset Retirement Obligations and Note 17. 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 $4.6 million, $1.9 million and $3.3 million for the years ended December 31, 2009, 2008 and 2007. 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 8.35% and discount rates of 6.15% and 6.70% for the years ended December 31, 2009 and 2008, respectively. Our actual return gain/(loss) on plan assets was 23.7% and (27.2)% for the years ended December 31, 2009 and 2008, respectively. Additionally, we base our determination of pension expense on a smoothed 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, 2009, our expected long-term rate of return assumption was 8.35% determined by the above factors and based on an asset allocation assumption of 70.0% invested in domestic equity securities, with an expected long-term rate of return of 9.25%, 10.0% invested in international equities with an expected long-term rate of return of 6.45% and 20.0% invested in fixed income securities, with an expected long-term rate of return of 6.10%. We, along with our Pension Plan investment manager and trustee and the compensation committee of the Board of Directors of our managing general partner (“Compensation Committee”) regularly review our actual asset allocation in accordance with our investment guidelines and periodically rebalance our investments to our targeted allocation when considered appropriate.

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, 2009, 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 decreased from 6.15% at December 31, 2008 to 5.88% at December 31, 2009.

 

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As of December 31, 2009, our Pension Plan was underfunded by approximately $20.0 million. We estimate that our Pension Plan expense and cash contributions will be approximately $3.6 million and $9.8 million, respectively, in 2010. 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 8.35% to 7.35%) at December 31, 2008 would have increased our pension expense for the year ended December 31, 2009 by approximately $0.3 million. Lowering the discount rate assumption by 0.5% (from 6.15% to 5.65%) at December 31, 2008 would have increased our pension expense for the year ended December 31, 2009 by approximately $0.5 million.

Inflation

At times, our results have been significantly impacted by price increases affecting many of the components of our operating expenses such as fuel, steel, maintenance expense and labor. The impact of recent governmental initiatives to stimulate economies worldwide remains unclear. Any resulting inflationary or deflationary pressures could adversely affect the results of our operations. Please see “Item 1A. Risk Factors.”

New Accounting Standards

New Accounting Standards Issued and Adopted

In June 2009, we adopted amendments to FASB ASC 105, Generally Accepted Accounting Principles (SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles - A Replacement of FASB Statement No. 162), effective for interim periods ending after September 15, 2009. These amendments establish the FASB ASC as the only source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. Rules and interpretive releases of the SEC under federal securities laws are also sources of authoritative GAAP for SEC registrants. FASB ASC 105 is not intended to change GAAP. All references to GAAP standards include both the FASB ASC reference in addition to the previously disclosed GAAP standard references as appropriate. The adoption of FASB ASC 105 had no impact on our financial position or results of operations.

In September 2009, the FASB issued Accounting Standards Update (“ASU”) 2009-06, Implementation Guidance on Accounting for Uncertainty in Income Taxes and Disclosure Amendments for Nonpublic Entities. ASU 2009-06 amended guidance on certain aspects of FASB ASC 740, Income Taxes, including application to nonpublic entities, as well as application guidance on the accounting for income tax uncertainties for all entities. The amendments are applicable to all entities that apply FASB ASC 740 as well as those that historically had not, such as pass-through and tax-exempt not-for-profit entities. The amendments clarify that an entity’s tax status as a pass-through or tax-exempt not-for-profit entity is a tax position subject to the recognition requirements of FASB ASC 740 and therefore, these entities must use the recognition and measurement guidance in FASB ASC 740 when assessing their tax positions. The ASU 2009-06 amendments are effective for interim and annual periods ending after September 15, 2009. The adoption of the ASU 2009-06 amendments for the year ended December 31, 2009 did not have a material impact on our consolidated financial statements.

On January 1, 2009, we adopted amendments to FASB ASC 805, Business Combinations (SFAS No. 141R, Business Combinations), issued by the FASB in December 2007. The FASB ASC 805 amendments apply to all business combinations and establish guidance for recognizing and measuring identifiable assets acquired, liabilities assumed, noncontrolling interests in the acquiree and goodwill. Most of these items are recognized at their full fair value on the acquisition date, including acquisitions where the acquirer obtains control but less than 100% ownership in the acquiree. The FASB ASC 805 amendments also require expensing restructuring and acquisition-related costs as incurred and establish disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. Per FASB ASC 805-10-65-1, these amendments to FASB ASC 805 are effective for business combinations with an acquisition date in fiscal years beginning after December 15, 2008. We did not complete any business acquisitions during the year ended December 31, 2009.

 

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On January 1, 2009, we adopted FASB ASC 810-10-65 and 810-10-45-16 (SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements), which amended accounting and reporting standards for noncontrolling ownership interests in subsidiaries. As a result of the adoption of the FASB ASC 810-10-65 and 810-10-45-16 amendments, noncontrolling ownership interest in consolidated subsidiaries is now presented in the consolidated balance sheet within partners’ capital as a separate component from the parent’s equity. Consolidated net income now includes earnings attributable to both the parent and the noncontrolling interests. EPU is based on earnings attributable to only the parent company and did not change upon adoption. In addition, FASB ASC 810-10-65 provides guidance on accounting for changes in the parent’s ownership interest in a subsidiary, including transactions where control is retained and where control is relinquished and requires additional disclosure of information related to amounts attributable to the parent for income from continuing operations, discontinued operations, extraordinary items and reconciliations of the parent and noncontrolling interests’ equity of a subsidiary. The provisions are applied prospectively to transactions involving noncontrolling interests, including noncontrolling interests that arose prior to the effective date, as of the beginning of 2009, the year of adoption. However, the presentation of noncontrolling interests within partners’ capital and the inclusion of earnings attributable to the noncontrolling interests in consolidated net income requires retrospective application to all periods presented. The adoption of FASB ASC 810-10-65 and 810-10-45-16 for the years ended December 31, 2009, 2008 and 2007 did not have material impact on our consolidated financial statements. For more information, please read “Item 8. Financial Statements —Note 18. Noncontrolling Interest” of this Annual Report on Form 10-K.

On January 1, 2009, we adopted FASB ASC 260-10-55-102 through 55-110, Master Limited Partnerships (EITF No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings Per Share, to Master Limited Partnerships), which considers whether the IDR of a master limited partnership represents a participating security when considered in the calculation of EPU under the two-class method. FASB ASC 260-10-55-102 through 55-110 also considers whether the partnership agreement contains any contractual limitations concerning distributions to IDR holders that would impact the amount of earnings to allocate to the IDR holders for each reporting period. If distributions are contractually limited to the IDR holders’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the IDR holders. We believe our partnership agreement contractually limits our distributions to available cash and therefore, undistributed earnings are no longer allocated to the IDR holder. Accordingly, the adoption impacts our presentation of EPU in periods when Net Income of ARLP exceeds the aggregate distributions because undistributed earnings are no longer allocated to the IDR holder. FASB ASC 260-10-55-102 through 55-110 required retrospective application for all periods presented. As a result of adoption, we no longer allocate earnings in excess of distributions to the IDR holder and EPU for the years ended December 31, 2008, 2007, 2006, and 2005 have been restated. For more information, please read “Item 8. Financial Statements —Note 12. Net Income Per Limited Partner Unit” of this Annual Report on Form 10-K.

On January 1, 2009, we adopted the provisions of FASB ASC 260-10-55-25 (FSP No. EITF No. 03-6-1 Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities), which affects entities that accrue cash dividends on share-based payment awards during the awards’ service period when the dividends are not required to be returned if the employees forfeit the award. Outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common unitholders and are considered participating securities. Because the awards are considered participating securities, the issuing entity is required to apply the two-class method of computing EPU. As a result of adoption, we now include an allocation of undistributed and distributed earnings to outstanding unvested awards under our Long-Term Incentive Plan (“LTIP”) in the calculation of our basic EPU. FASB ASC 260-10-55-25 required retrospective application for all periods presented. In addition, EPU for the years ended December 31, 2008, 2007, and 2006 have been restated. For more information, please read “Item 8. Financial Statements — Note 12. Net Income Per Limited Partner Unit” of this Annual Report on Form 10-K.

Beginning with the quarterly interim period ended June 30, 2009, we adopted amendments to FASB ASC 855, Subsequent Events (SFAS No. 165, Subsequent Events), issued by the FASB in May 2009. The amendments to FASB ASC 855 establish the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The amendments to FASB ASC 855 also require disclosure of the date through which an entity has evaluated subsequent events and the basis for that date, that is, whether that date represents the date the financial statements were issued or were available to be issued. In February 2010, the FASB issued FASB ASU 2010-09, which amended the guidance in FASB ASC 855 and removed the requirement to disclose the date through which an entity evaluated its subsequent events. The adoption of the FASB ASC 855 and FASB ASU 2010-09 amendments did not impact our consolidated financial statements.

 

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In December 2008, FASB ASC 715, Compensation-Retirement Benefits was amended (FSP SFAS No. 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets) to require more detailed annual disclosures about employers’ plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. These amendments were effective for our fiscal year ending December 31, 2009. The requirements did not have a material impact on our consolidated financial statements. For more information, please read “Item 8. Financial Statements and Supplementary Data — Note 13. Employee Benefit Plans” of this Annual Report on Form 10K.

New Accounting Standards Issued and Not Yet Adopted

In June 2009, the FASB issued amendments to FASB ASC 810, Consolidation (SFAS No. 167, Amendments to FASB Interpretation No. 46(R)), which changes the consolidation guidance applicable to a variable interest entity (“VIE”). These amendments also update the guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate an entity, by requiring a qualitative analysis rather than a quantitative analysis. The qualitative analysis will include, among other things, consideration of who has the power to direct the activities of the entity that most significantly impact the entity’s economic performance and who has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. This standard also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE. Previously, FASB ASC 810 required reconsideration of whether an enterprise was the primary beneficiary of a VIE only when specific events had occurred. Qualifying special purpose entities, which were previously exempt from the application of this standard, will be subject to the provisions of this standard when it becomes effective. These amendments also require enhanced disclosures about an enterprise’s involvement with a VIE. The provisions of these amendments are effective as of the beginning of interim and annual reporting periods that begin after November 15, 2009. Based on our evaluation of the requirements of the amendments to FASB ASC 810, we will deconsolidate MAC upon adoption, effective January 1, 2010. The deconsolidation of MAC subsequent to December 31, 2009 will not have a material impact on our consolidated financials.

 

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 resulting from regulatory changes. 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 21. 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. During 2009, we entered into a contract to purchase longwall shields for our Tunnel Ridge mine from a foreign supplier for approximately £10.2 million. We paid £7.1 million to this foreign supplier through December 31, 2009, with the remaining balance to be paid out through 2011. We do not have any interest 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. We had no borrowings outstanding under the ARLP Credit Facility at December 31, 2009.

 

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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, 2009 and 2008. The carrying amounts and fair values of financial instruments are as follows (in thousands):

 

Expected Maturity Dates

as of December 31, 2009

   2010     2011     2012     2013     2014     Thereafter     Total    Fair Value
December 31,
2009

Fixed rate debt

   $ 18,000      $ 18,000      $ 18,000      $ 18,000      $ 18,000      $ 350,000      $ 440,000    $ 460,739

Weighted average interest rate

     6.82     6.75     6.68     6.61     6.52     6.65     

Expected Maturity Dates

as of December 31, 2008

   2009     2010     2011     2012     2013     Thereafter     Total    Fair Value
December 31,
2008

Fixed rate debt

   $ 18,000      $ 18,000      $ 18,000      $ 18,000      $ 18,000      $ 368,000      $ 458,000    $ 362,824

Weighted average interest rate

     6.88     6.82     6.75     6.68     6.61     6.60     

 

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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, 2009 and 2008, and the related consolidated statements of income, cash flows and Partners’ capital for each of the three years in the period ended December 31, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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.

As discussed in Notes 2 and 12 to the consolidated financial statements, the Partnership changed its method of calculating earnings per unit in 2009 and retrospectively applied to the 2008 and 2007 periods.

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, 2009, 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 26, 2010 expressed an unqualified opinion on the Partnership’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Tulsa, Oklahoma

February 26, 2010

 

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2009 AND 2008

(In thousands, except unit data)

 

     December 31,  
     2009     2008  

ASSETS

    

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 21,556      $ 244,875   

Trade receivables

     91,223        87,922   

Other receivables

     3,159        6,018   

Due from affiliates

     83        —     

Inventories

     64,357        26,510   

Advance royalties

     3,629        3,200   

Prepaid expenses and other assets

     8,801        10,070   
                

Total current assets

     192,808        378,595   

PROPERTY, PLANT AND EQUIPMENT:

    

Property, plant and equipment, at cost

     1,378,914        1,085,214   

Less accumulated depreciation, depletion and amortization

     (556,370     (468,784
                

Total property, plant and equipment, net

     822,544        616,430   

OTHER ASSETS:

    

Advance royalties

     26,802        23,828   

Other long-term assets

     9,246        11,787   
                

Total other assets

     36,048        35,615   
                

TOTAL ASSETS

   $ 1,051,400      $ 1,030,640   
                

LIABILITIES AND PARTNERS’ CAPITAL

    

CURRENT LIABILITIES:

    

Accounts payable

   $ 62,821      $ 63,236   

Due to affiliates

     27        706   

Accrued taxes other than income taxes

     10,777        11,195   

Accrued payroll and related expenses

     22,101        20,555   

Accrued interest

     2,918        3,454   

Workers’ compensation and pneumoconiosis benefits

     9,886        9,377   

Current capital lease obligation

     324        351   

Other current liabilities

     11,062        11,911   

Current maturities, long-term debt

     18,000        18,000   
                

Total current liabilities

     137,916        138,785   

LONG-TERM LIABILITIES:

    

Long-term debt, excluding current maturities

     422,000        440,000   

Pneumoconiosis benefits

     34,344        31,436   

Accrued pension benefit

     19,696        19,952   

Workers’ compensation

     53,845        47,828   

Asset retirement obligations

     53,116        56,204   

Due to affiliates

     1,148        420   

Long-term capital lease obligation

     460        784   

Other liabilities

     7,895        5,039   
                

Total long-term liabilities

     592,504        601,663   
                

Total liabilities

     730,420        740,448   
                

COMMITMENTS AND CONTINGENCIES

    

PARTNERS’ CAPITAL:

    

Alliance Resource Partners, L.P. (“ARLP”) Partners’ Capital:

    

Limited Partners - Common Unitholders 36,661,029 and 36,613,458 units outstanding, respectively

     630,165        604,998   

General Partners’ deficit

     (293,153     (295,834

Accumulated other comprehensive loss

     (17,149     (19,899
                

Total ARLP Partners’ Capital

     319,863        289,265   

Noncontrolling interest

     1,117        927   
                

Total Partners’ Capital

     320,980        290,192   
                

TOTAL LIABILITIES AND PARTNERS’ CAPITAL

   $ 1,051,400      $ 1,030,640   
                

See notes to consolidated financial statements.

 

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Table of Contents

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007

(In thousands, except unit and per unit data)

 

     Year Ended December 31,  
     2009     2008     2007  

SALES AND OPERATING REVENUES:

      

Coal sales

   $ 1,163,871      $ 1,093,059      $ 960,354   

Transportation revenues

     45,733        44,755        37,688   

Other sales and operating revenues

     21,427        18,735        35,292   
                        

Total revenues

     1,231,031        1,156,549        1,033,334   
                        

EXPENSES:

      

Operating expenses (excluding depreciation, depletion and amortization)

     797,527       </