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ALLIANCE RESOURCE PARTNERS LP - Annual Report: 2010 (Form 10-K)

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, 2010

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.    x  Yes    ¨  No

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

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

Indicate by check mark 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).    x  Yes    ¨  No

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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 $924,310,997 as of June 30, 2010, 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 28, 2011, 36,775,741 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

     34   
Item 2.   

Properties

     35   
Item 3.   

Legal Proceedings

     37   
Item 4.   

Reserved

     38   
PART II   
Item 5.   

Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

     39   
Item 6.   

Selected Financial Data

     40   
Item 7.   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     42   
Item 7A.   

Quantitative and Qualitative Disclosures about Market Risk

     70   
Item 8.   

Financial Statements and Supplementary Data

     72   
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

     112   
Item 11.   

Executive Compensation

     117   
Item 12.   

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

     131   
Item 13.   

Certain Relationships and Related Transactions, and Director Independence

     132   
Item 14.   

Principal Accountant Fees and Services

     134   
PART IV   
Item 15.   

Exhibits and Financial Statement Schedules

     135   

 

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FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report on Form 10-K may constitute “forward-looking statements.” These statements are based on our beliefs as well as assumptions made by, and information currently available to, us. When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements. 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:

 

   

changes in competition in coal markets and our ability to respond to such changes;

 

   

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

 

   

risks associated with the expansion of our operations and properties;

 

   

the impact of recent health care legislation;

 

   

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;

 

   

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

 

   

liquidity constraints, including those resulting from any future unavailability of financing;

 

   

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 earned on our coal sales;

 

   

unexpected changes in raw material costs;

 

   

unexpected changes in the availability 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 or projections 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, black lung benefits 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;

 

   

uncertainties in estimating and replacing our 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.”

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

 

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forward-looking statements, you should also keep in mind the risk factors described in Item 1A. “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;

 

   

our website http://www.arlp.com; 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 the fourth largest coal producer in the eastern U.S. At December 31, 2010, we had approximately 697.4 million tons of coal reserves in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia. In 2010, we produced 28.9 million tons of coal and sold 30.3 million tons of coal, of which 8.0% was low-sulfur coal, 20.7% was medium-sulfur coal and 71.3% was high-sulfur coal. In 2010, we sold 91.5% of our total tons to electric utilities, of which 93.5% 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, 2010:

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 restrictions 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 http://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 Securities Exchange Act of 1934, as amended (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

 

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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.

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

   2010      2009      2008      2007      2006  
     (tons in millions)  

Illinois Basin:

              

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

     23.7         20.7         20.3         17.9         16.9   

Central Appalachian:

              

Pontiki and MC Mining complexes

     2.3         2.6         3.2         3.2         3.5   

Northern Appalachian:

              

Mettiki and Tunnel Ridge complexes

     2.9         2.5         2.9         3.2         3.3   
                                            

Total

     28.9         25.8         26.4         24.3         23.7   
                                            

 

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

LOGO

Illinois Basin Operations

Our Illinois Basin mining operations are located in western Kentucky, southern Illinois and southern Indiana. As of February 1, 2011, we had 2,487 employees and we 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 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.

 

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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, or via connection with CSX, to customers or to various transloading facilities, including our Mt. Vernon transloading facility, for sale to customers capable of receiving barge deliveries. A failure of the vertical hoist conveyor system temporarily halted production from the Pattiki mine for a period of approximately two months beginning May 13, 2010 and resulted in limited production from the mine until full production was resumed on January 3, 2011.

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 128.5 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, which is an underground mining complex utilizing continuous mining units employing room-and-pillar mining techniques. Production began in August 2009 and expanded to eight continuous mining units in 2010. River View’s 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. Total capital expenditures required to develop the River View mine to its current capacity were approximately $252.0 million, of which $52.5 million was incurred in 2010. 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.”) Although development of the project is market dependent, we currently expect production to begin in 2014. 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”).

Sebree Reserves. We control, through our subsidiaries, Alliance Resource Properties, LLC (“Alliance Resource Properties”) and ARP Sebree, LLC, undeveloped reserves in Webster County, Kentucky, which we refer to as the “Sebree Reserves”. We are in the process of permitting the Sebree property for future development through our subsidiary Sebree Mining, LLC (“Sebree”).

 

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Central Appalachian Operations

Our Central Appalachian mining operations are located in eastern Kentucky. As of February 1, 2011, we had 474 employees and we 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 2010 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 and that unit remained idle throughout 2010.

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 2010 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 employed 391 employees, as of February 1, 2011, 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, but operated throughout 2010.

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 domestic and export metallurgical coal markets.

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.

 

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Tunnel Ridge Complex. Our subsidiary, Tunnel Ridge, LLC (“Tunnel Ridge”), controls, through a coal lease agreement with our special general partner, approximately 97.4 million tons of proven and probable high-sulfur coal in the Pittsburgh No. 8 coal seam in West Virginia and Pennsylvania. In 2008, Tunnel Ridge began construction of the mining complex, which will be an underground, longwall mine, and development mining began in 2010. During 2010, we had incidental production of approximately 115,000 tons, which we expect to increase to approximately 550,000 tons to 750,000 tons of incidental production in 2011 as development mining continues. We expect to begin longwall mining operations at Tunnel Ridge in the first quarter of 2012, with annual production capacity of approximately 5.5 to 6.0 million tons. Capital expenditures required for development of Tunnel Ridge are estimated to be in the range of approximately $295 million to $305 million, of which approximately $200.0 million has been incurred as of December 31, 2010. 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.”)

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 continues 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 is regulatory and market dependent, and its timing is open-ended pending obtaining all required regulatory approvals and 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 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 2010, the terminal loaded approximately 2.5 million tons for customers of Pattiki, Gibson, Elk Creek, and for third parties.

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 2010, we sold 54,699 tons classified as brokerage coal.

Matrix Group

Our subsidiaries, Matrix Design Group, LLC and Alliance Design Group, LLC (collectively, “Matrix Group”), provide a variety of mine products and services for our mining operations and to unrelated parties. We acquired this business in September 2006. Matrix Group’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 and proximity detection systems. In 2010, our financial results were not significantly impacted by Matrix Group’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 2010 and historically have represented less than one percent of our total revenues. In addition, our affiliate, Mid-America Carbonates, LLC

 

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(“MAC”), which is a joint venture in which White County Coal participates, manufactures and sells rock dust to us and to unrelated parties. In 2010, 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.

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 2010, approximately 92.4% and 89.0% 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 2011 to 2016. As of January 28, 2011, our nominal commitment under long-term contracts was approximately 31.1 million tons in 2011, 27.3 million tons in 2012, 24.1 million tons in 2013 and 19.0 million tons in 2014. The commitment of coal under contract is an approximate number because, in some instances, our contracts contain provisions that could cause the nominal 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 commitment can otherwise change because of reopener provisions contained in certain of these long-term contracts.

The provisions of long-term contracts are the results of both bidding procedures and extensive negotiations with each customer. As a result, the provisions of these contracts vary significantly in many respects, including, among others, price adjustment features, price and contract reopener terms, permitted sources of supply, force majeure provisions, coal qualities and quantities. Virtually all of our long-term contracts are subject to price adjustment provisions, which permit an increase or decrease periodically in the contract price to reflect changes in specified price indices or items such as taxes, royalties or actual production costs. These provisions, however, may not assure that the contract price will reflect every change in production or other costs. Failure of the parties to agree on a price pursuant to an adjustment or a reopener provision can, in some instances, 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 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, rejection or suspension of shipments 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 two largest customers in 2010 were Tennessee Valley Authority and Louisville Gas and Electric Company. During 2010, we derived approximately 29.2% of our total revenues from these two customers and at least 10.0% of our total revenues from each of the two. 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, Foresight Energy LLC 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

 

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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, we export a portion of our coal into the international metallurgical coal market. The prices we are able to obtain for our export coal are influenced by a number of factors, such as global economic conditions, weather patterns and political instability, among others. Further, 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 4.0% to 45.0% 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 61.7% of our 2010 sales volume was initially shipped from the mines by rail with 17.5% shipped from the mines by truck and 20.8% shipped from the mines by barge. In 2010, the largest volume transporter of our coal shipments was the CSX, which moved approximately 36.7% 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.

Regulation and Laws

The coal mining industry is subject to extensive 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. For more information, please see risk factors described in Item 1A. “Risk Factors” below.

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.

 

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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.

The permitting process for certain mining operations can extend over several years and can be subject to judicial challenge, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We cannot assure you that we will not experience difficulty or delays in obtaining mining permits in the future.

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

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, most of the states where we operate also have state programs for mine safety and health regulation and enforcement. Federal and state safety and health regulations affecting the coal mining industry are perhaps the most comprehensive and rigorous system for protection of employee safety and have 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.

The FMSHA has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability, or liability without fault, and FMSHA requires imposition of a civil penalty for each cited violation. Negligence and gravity assessments, and other factors can result in the issuance of various types of orders, including orders requiring withdrawal from the mine or the affected area, and some orders can also result in the imposition of civil penalties. The FMSHA also contains criminal liability provisions. For example, criminal liability may be imposed upon corporate operators who knowingly and willfully authorize, order or carry out violations of the FMSHA, or its mandatory health and safety standards.

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;

 

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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.

MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards. Among these new proposed regulations is MSHA’s proposed rule titled “Lowering Miner’s Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors.” The rule, which is currently in the comment phase, would require a 50% reduction in the allowable respirable coal mine dust exposure limits and require each operation to significantly increase the number of respirable coal mine dust samples taken. The rule would also increase oversight by MSHA regarding coal mine dust and ventilation issues at each mine, including the approval process for ventilation plans at each mine. MSHA also introduced an Emergency Temporary Standard in 2010 that required the application and continued maintenance of a significantly increased amount of rock dust throughout underground coal mines.

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. Additionally, in 2010, the 111th Congress introduced federal legislation seeking to impose extensive additional safety and health requirements on coal mining. While the legislation was passed by the House of Representatives, the legislation was not voted on in the Senate and did not become law. On January 26, 2011, the same legislation was reintroduced in the 112th Congress by Senators Jay Rockefeller (D-W.Va.), Tom Harkin (D-Iowa), Patty Murray (D-Wash.) and Joe Manchin III (D-W.Va.).

Although we are unable to quantify the full impact, implementing and complying with these new state and federal safety laws and regulations have had, and are expected to continue to have, an adverse impact on our results of operation and financial position.

Black Lung Benefits Act

The Federal Black Lung Benefits Act (“BLBA”) requires businesses that conduct current mining operations to make payments of black lung benefits to coal miners with black lung disease and to some survivors of a miner who dies from this disease. 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. Congress and state legislatures regularly consider various items of black lung legislation, which, if enacted, could adversely affect our business, results of operations and financial position.

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.

 

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The Patient Protection and Affordable Care Act (“PPACA”), signed into law on March 23, 2010, includes provisions, retroactive to 2005, which would (1) provide an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim, without requiring proof that the death was due to pneumoconiosis, or black lung, and (2) establish a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. This legislation has had and is expected to have an adverse impact on our results of operation and financial position.

Workers’ Compensation

We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers’ compensation laws also compensate survivors or workers who suffer employment related deaths. 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 of 1977 (“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. 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.

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.

 

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The Office of Surface Mining Reclamation (“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 prohibits mining disturbances within 100 feet of streams if there would be a negative effect on water quality. OSM intends to propose a series of Stream Protection Rules in 2011 and will finalize those rules in 2012. We are unable to predict the impact, if any, of these actions by the OSM, although the actions potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities near streams, and additional enforcement actions. In addition, Congress has proposed, and may in the future propose, legislation to restrict the placement of mining material in streams. The requirements of the revised SBZ Rule or future legislation, if adopted, will likely be stricter than the prior SBZ Rule and may adversely affect our business and operations.

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 bond 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 our ability to produce coal, which could affect our profitability and cash flow.

As of December 31, 2010, we had approximately $68.4 million in surety bonds outstanding to secure the performance of our reclamation obligations.

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, as well as regulations promulgated by the U.S. Environmental Protection Agency (“EPA”), 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. A significant 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. In 2010, we sold 91.5% of our total tons to electric utilities, of which 93.5% was sold to utility plants with installed pollution control devices.

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. As a result of the program, many power plants have been or will be required to install additional emission control measures, such as selective catalytic reduction devices. Installation of additional emission control measures will make it more costly to operate coal-fired power plants, potentially making coal a less attractive fuel.

 

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Additionally, in March 2005, the EPA issued the final Clean Air Interstate Rule (“CAIR”) which would have permanently capped nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. 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. 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. The court established a deadline of November 2011 for the EPA to issue a final rule requiring Maximum Achievable Control Technology standards (“MACT”) for power plants, which are likely to impose stricter limitations on mercury emissions from power plants than the vacated CAMR. The EPA has stated that it intends to propose air toxics standards for coal- and oil-fired electric generating units by March 10, 2011. 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. Also, the EPA expects to issue a final “Transport Rule”, which sets a pollution limit on nitrogen oxide and sulfur dioxide emissions in 31 states and the District of Columbia, in Spring 2011. Under the proposed Transport Rule, some coal-fired power plants might be required to install additional pollution control equipment which could lead to decreased demand for low-sulfur coal. Also, on April 29, 2010, the EPA proposed new MACT for several classes of boilers and process heaters, including large coal-fired boilers and process heaters, which would require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury. Certain states have adopted or proposed mercury control regulations that are more stringent than the federal requirements. The Obama Administration has also indicated a desire to negotiate an international treaty to reduce mercury pollution. More stringent regulation of mercury or other emissions by the EPA, state regulators, Congress, or pursuant to an international treaty may decrease the future demand for coal, but we are unable to predict the magnitude of any such impact with any reasonable degree of certainty.

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 (“NAAQS”) should be revised. Pursuant to this process, the EPA has adopted more stringent NAAQS for fine particulate matter, ozone, nitrogen oxide and sulfur dioxide. As a result, some states will be required to amend their existing state implementation plans (“SIPs”) to attain and maintain compliance with the new air quality standards and other states will be required to develop new SIPs for areas that were previously in “attainment” but do not attain the new standards. In addition, under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants. Attainment dates for the new standards range between 2013 and 2030, depending on the severity of the non-attainment. In July 2009, the U.S. Court of Appeals for the District of Columbia vacated part of a rule implementing the ozone NAAQS and remanded certain other aspects of the rule to the EPA for further consideration. Notwithstanding the decision, we expect that additional emissions control requirements may be imposed on new and expanded coal-fired power plants and industrial boilers in the years ahead. 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.

A regional haze program initiated by the EPA to protect and to improve visibility at and around national parks, national wilderness areas and international parks may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions. These requirements could limit the demand for coal in some locations.

The Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities 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 coal could be affected.

Carbon Dioxide Emissions

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide, which is considered a “greenhouse gas” or “GHG.” Future regulation of greenhouse gas emissions in the U.S. could occur pursuant to future U.S. treaty commitments, new domestic legislation or regulation by the EPA. President Obama has

 

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expressed support for a mandatory cap and trade program to restrict or regulate emissions of greenhouse gases and Congress has recently considered various proposals to reduce greenhouse gas emissions and it is possible federal legislation could be adopted in the future. Many states and regions have adopted greenhouse gas initiatives and certain governmental bodies, including the State of California, have or are considering the imposition of fees or taxes based on the emission of greenhouse gases by certain facilities, including coal-fired electric generating facilities. Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal could be negatively impacted which would have an adverse effect on our operations.

Even in the absence of new federal legislation, the EPA has begun to regulate greenhouse gas emissions pursuant to the CAA based on the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts v. EPA that the EPA has authority to regulate greenhouse gas emissions.

In 2009, the EPA issued a final rule declaring 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”). Several groups have filed petitions asking the EPA to reconsider the Endangerment Finding. Further, several groups have filed petitions asking the United States Court of Appeals for the District of Columbia Circuit to review the legality of the EPA’s Endangerment Finding.

In May 2010, the EPA issued its final “tailoring rule” for greenhouse gas emissions, a policy aimed at shielding small emission sources from Clean Air Act permitting requirements. The EPA’s rule phases in various greenhouse-gas-related permitting requirements beginning in January 2011. Until June 30, 2011, facilities that must already obtain New Source Review permits for other pollutants will be required to include greenhouse gases in their permits if they increase their emissions of the gases by at least 75,000 tons of carbon dioxide equivalent per year. Beginning July 1, 2011, the EPA will extend these requirements to new construction projects that emit at least 100,000 tons per year of greenhouse gases and existing facilities that increase their emissions by at least 75,000 tons per year. Sources that are “smaller,” those with emissions of less than 50,000 tons of greenhouse gases per year, will not be regulated until at least April 30, 2016, and may in fact be permanently excluded from the permitting requirements. In December 2010, the EPA issued its plan to update pollution standards for fossil fuel power plants and petroleum refineries. The EPA has stated that it intends to propose standards for power plants in July 2011 and for refineries in December 2011 and will issue final standards in May 2012 and November 2012, respectively. Lawsuits challenging the tailoring rule have already been brought, and as a result of such challenges, the rule may be modified or vacated in whole or in part. On June 28, 2010, 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 additional source categories, including all underground mines subject to quarterly methane sampling by MSHA. Underground mines subject to this rule, including ours, were required to begin monitoring greenhouse gas emissions on January 1, 2011 and must begin reporting to the EPA on March 31, 2012.

There have been an increasing number of protests of and challenges to the permitting of new coal-fired power plants by environmental organizations and state regulators for concerns related to greenhouse gas emissions. For instance, various state regulatory authorities have rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with greenhouse gas emissions from these plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fueled power plants without limits on greenhouse gas emissions have been appealed to the EPA’s Environmental Appeals Board. In addition, over 30 states have currently adopted mandatory “renewable portfolio standards,” which require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until between 2020 and 2030. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers, they may reduce the demand for coal-fired power, and may affect long-term demand for our coal. Finally, a federal appeals court has allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, while a second federal appeals court dismissed a similar case on procedural grounds. In the former case, the U.S. Supreme Court has agreed to hear the appeal of the lower court’s decision.

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.

 

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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 U.S. Army Corps of Engineers (“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. Our coal mining operations typically require such permits to authorize activities such as the creation of slurry ponds and stream impoundments. Although the CWA has long authorized the EPA to review Section 404 permits issued by the Corps of Engineers, the EPA has only recently begun reviewing Section 404 permits issued by the Corps of Engineers for coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

For instance, even though the State of West Virginia has been delegated the authority to issue permits for coal mines in that state, the EPA is taking a more active role in its review of National Pollutant Discharge Elimination System (“NPDES”) permit applications for coal mining operations in Appalachia. The EPA has stated that it plans to review all applications for NPDES permits. Indeed, interim final guidance issued by the EPA on April 1, 2010, encourages EPA Regions 3, 4 and 5 to (1) object to the issuance of state program NPDES permits where the Region does not believe that the proposed permit satisfies the requirements of the CWA, and (2) exercise a greater degree of oversight with regard to state issued general Section 404 permits.

In addition, on April 1, 2010, the EPA issued a guidance document on water quality requirements for coal mines in Appalachia. This guidance follows up on the June 11, 2009 Enhanced Coordination Process Memoranda for the issuance of Section 404 permits whereby the EPA undertook a new level of review of 404 permits than it had previously undertaken. Ultimately, the EPA identified 79 coal-related applications for 404 permits that would need to go through that process. The EPA’s actions in issuing the Enhanced Coordination Process Memoranda and the guidance are being challenged in a lawsuit pending before the U.S. District Court for the District of Columbia in a case captioned National Mining Assoc. v. U.S. Environmental Protection Agency. In a ruling issued on January 18, 2011, the District Court held that these measures “are legislative rules that were adopted in violation of notice and comment requirements.” The court would not grant the motion for a preliminary injunction to enjoin further use of these measures but also refused to dismiss the Complaint as the EPA had sought.

Not only is the EPA reviewing new permits before they are issued, the EPA on January 14, 2011 exercised its “veto” power to withdraw or restrict the use of previously issued permits in connection with the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action is the first time that such power was exercised with regard to a previously permitted coal mining project.

 

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These initiatives have extended the time required to obtain some permits required for coal mining and have caused the costs of obtaining and complying with those permits to increase substantially. It is possible that some of our projects may not be able to obtain these permits or may experience delays in securing, utilizing or renewing permits because of the manner in which these rules are being interpreted and applied.

Total Maximum Daily Load (“TMDL”), regulations under the CWA, establish a process to calculate the maximum amount of a pollutant that a water body can receive and still meet state water quality standards, and to allocate pollutant loads among the point and non-point pollutant sources discharging into that water body. This process applies to those waters that states have designated as impaired (i.e., as not meeting present water quality standards). Industrial dischargers, including coal mines, will be required to meet new TMDL allocations for these stream segments. The adoption of new TMDL-related allocations for our coal mines could require more costly water treatment and could adversely affect our coal production.

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.

On June 21, 2010, the EPA released a proposed rule to regulate the disposal of certain coal combustion by-products (“CCB”). The proposed rule sets forth two proposed very different approaches for regulating CCB under RCRA. The first option calls for regulation of CCB as a hazardous waste under Subtitle C, which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option utilizes Subtitle D, which gives the EPA authority to set performance standards for waste management facilities and would be enforced primarily through citizen suits. The proposal leaves intact the Bevill exemption for beneficial uses of CCB. If CCB is not classified as hazardous waste, it is not anticipated that regulation of CCB will have any material effect on the amount of coal used by electricity generators. However, if CCB were re-classified as hazardous waste, regulations would likely restrict ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCB, including coal ash, may lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal. 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.

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”). We are also required to comply with the Safe Drinking Water Act, the Toxic Substance Control Act, and the Emergency Planning and Community Right-to-Know Act. The costs of compliance with these regulations should not have a material adverse effect on our business, financial condition or results of operations.

 

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Employees

To conduct our operations, as of February 1, 2011, we employed 3,558 full-time employees, including 3,352 employees involved in active mining operations, 71 employees in other operations, and 135 corporate employees. Our work force is entirely union-free. We believe that relations with our employees are generally good.

Administrative Services

On April 1, 2010, effective January 1, 2010, ARLP entered into an amended and restated administrative services agreement (“Administrative Services Agreement”) with our managing general partner, the Intermediate Partnership, AGP, AHGP and Alliance Resource Holdings, II (“ARH II”). The Administrative Services Agreement superseded the administrative services agreement signed in connection with the AHGP IPO in 2006. 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, 2010 of $0.3 million from AHGP and $0.2 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, 2010, 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, 2010, AHGP owned approximately 42.3% 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, 2010, AHGP held approximately 42.3% 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.”

We depend on the leadership and involvement of Joseph W. Craft III and other key personnel for the success of our business.

We depend on the leadership and involvement of Mr. Craft, a Director and President and Chief Executive Officer of our managing general partner. Mr. Craft has been integral to our success, due in part to his ability to identify and develop internal growth projects and accretive acquisitions, make strategic decisions and attract and retain key personnel. The loss of his leadership and involvement or the services of any members of our senior management team could have a material adverse effect on our business, financial condition and results of operations.

Several key personnel, including Messrs. Craft, Charles R. Wesley and Thomas M. Wynne, received substantial amounts of the proceeds from the AHGP IPO in May 2006. As a result of these cash payments, there is an increased risk that key personnel will retire or resign in the future.

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.

 

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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;

 

   

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.

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.

 

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

 

   

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.

 

   

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

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

During the latter half of 2007 as well as throughout much of 2008 and 2009, financial markets in the U.S. Europe and Asia experienced a period of volatility and declines in security prices, 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. While national and global economies have more recently exhibited signs of improvement, the re-emergence of 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. may not fully recover or may decline if economic conditions deteriorate, which may negatively impact the revenues, margins and profitability of our business;

 

   

any inability of our customers to raise capital could adversely affect their ability to honor their obligations to us; and

 

   

our future ability to access the capital markets may be restricted as a result of future economic conditions, which could materially impact our ability to grow 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.

 

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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.

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 2010 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 2010, we sold approximately 92.4% 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 environmental regulations rendering use of our coal inconsistent with the customer’s environmental compliance 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.

 

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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 much of our coal. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. A substantial portion of our coal has a high-sulfur content, which may result in increased sulfur dioxide emissions when combusted. Accordingly, these laws and regulations may affect demand and prices for our low- and high-sulfur coal. There is also continuing pressure on state and federal regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants. In addition, the EPA has proposed a rule that could result in regulation of CCB as a hazardous waste. 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 or by-products, further reducing demand for our coal. Please read “Item 1. Business—Regulation and Laws—Air Emissions,” “—Carbon Dioxide Emissions” and “—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 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, and the EPA has begun to regulate greenhouse gas emissions pursuant to the CAA. In addition, it is possible federal legislation could be adopted in the future to restrict greenhouse gas emissions, as President Obama has expressed support for a mandatory cap and trade program to restrict or regulate emissions of greenhouse gases and Congress has recently considered various proposals to reduce greenhouse gas emissions. Many states and regions have adopted greenhouse gas initiatives. Also, there have been an increasing number of protests of, and challenges to, the permitting of new coal-fired power plants by environmental organizations and state regulators for concerns related to greenhouse gas emissions. 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.

Plaintiffs in recent federal court litigation have attempted 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. In December 2010, the U.S. Supreme Court granted the petition for certiorari filed by the defendants and therefore could determine in this case whether companies accused of emitting greenhouse gases can be held liable under public nuisance laws.

 

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Proliferation of successful climate change litigation could adversely impact demand for our coal and 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 2010, we derived approximately 29.2% of our total revenues from two customers and at least 10.0% of our 2010 total revenues from each of the two. If we were to lose either 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

 

   

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 2010, we completed our annual property and casualty insurance renewal with various insurance coverages effective as of October 1, 2010. The aggregate maximum limit in the commercial property program is $75.0

 

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million per occurrence, excluding a $1.5 million deductible for property damage, a 60-day waiting period for business interruption and a $10 million overall aggregate deductible. We can make no assurances that we will not experience significant insurance claims in the future that 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.”

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

 

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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.”

The EPA has recently begun reviewing permits required for the discharge of overburden from mining operations under Section 404 of the CWA. Various initiatives by the EPA regarding these permits have increased the time required to obtain and the costs of complying with such permits. In addition, the EPA recently exercised its “veto” power to withdraw or restrict the use of previously issued permits in connection with one of the largest surface mining operations in Central Appalachia. As a result of these developments, we may be unable to obtain or experience delays in securing, utilizing or renewing Section 404 permits required for our operations, which could have an adverse effect on our results of operation and financial position. 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.

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.

 

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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.

Despite recent improvements, financial markets remain volatile and persistent weaknesses continue to plague global economies. These conditions continue to negatively impact the debt and equity capital markets and could adversely impact our credit ratings or our ability to remain in compliance with the financial covenants under our current debt agreements, which in turn 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.

 

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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.

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.

 

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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, revolving credit facility and term loan agreement. At December 31, 2010, our total long-term indebtedness outstanding was $704.0 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.

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.

 

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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 publicly-traded 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 could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

In addition, 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. 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 we were subject to federal income tax as a corporation or any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced and the value of our common units could be negatively impacted.

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.

 

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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.

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 U.S. Treasury Department 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. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

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

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a

 

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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.

The Obama administration has indicated a desire to eliminate certain key U.S. federal income tax provisions currently applicable to coal companies, including the percentage depletion allowance with respect to coal properties. No legislation with that effect has been proposed and elimination of those provisions would not impact our financial statements or results of operations. However, elimination of the provisions could result in unfavorable tax consequences for our unitholders and, as a result, could negatively impact our unit price.

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 technically 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. The IRS has recently announced a relief procedure whereby the IRS may allow a publicly-traded partnership that has technically terminated to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

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 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, 2010, we had approximately 697.4 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 U.S. 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, 2010, about our mining operations:

 

Operations

  Mine Type     Heat Content
(BTUs per
pound)
    Proven and Probable Reserves     Reserve Assignment     Reserve Control  
      Pounds S02 per MMBTU      
      <1.2     1.2-2.5     >2.5     Total     Assigned     Unassigned     Owned     Leased  
   

(tons in millions)

 

Illinois Basin Operations

                   

Dotiki (KY)

    Underground        12,200        —          —          55.5        55.5        55.5        —          21.2        34.3   

Warrior (KY)

    Underground        12,600        —          —          113.9        113.9        65.2        48.7        24.9        89.0   

Hopkins (KY)

    Underground        12,200        —          —          38.1        38.1        23.0        15.1        8.1        30.0   
    / Surface        11,500        —          —          7.8        7.8        7.8        —          7.8        —     

River View (KY)

    Underground        11,600        —          —          128.5        128.5        128.5        —          12.6        115.9   

Sebree (KY)

    Underground        11,400        —          —          23.9        23.9        —          23.9        —          23.9   

Pattiki (IL)

    Underground        11,500        —          —          60.4        60.4        60.4        —          0.1        60.3   

Gibson (North) (IN)

    Underground        11,600        —          19.1        3.0        22.1        22.1        —          0.4        21.7   

Gibson (South) (IN)

    Underground        11,500        —          12.4        36.0        48.4        —          48.4        16.3        32.1   
                                                                   

Region Total

        —          31.5        467.1        498.6        362.5        136.1        91.4        407.2   
                                                                   

Central Appalachian Operations

                   

Pontiki (KY)

    Underground        13,000        —          8.1        —          8.1        8.1        —          —          8.1   

MC Mining (KY)

    Underground        12,600        14.6        0.5        1.5        16.6        16.6        —          4.2        12.4   
                                                                   

Region Total

        14.6        8.6        1.5        24.7        24.7        —          4.2        20.5   
                                                                   

Northern Appalachian Operations

                   

Mettiki (MD)

    Underground        13,200        —          2.1        5.9        8.0        8.0        —          —          8.0   

Mountain View (WV)

    Underground        13,200        —          5.1        6.9        12.0        12.0        —          —          12.0   

Tunnel Ridge (PA/WV)

    Underground        12,600        —          —          97.4        97.4        97.4        —          —          97.4   

Penn Ridge (PA)

    Underground        12,500        —          —          56.7        56.7        56.7        —          —          56.7   
                                                                   

Region Total

        —          7.2        166.9        174.1        174.1        —          —          174.1   
                                                                   

Total

        14.6        47.3        635.5        697.4        561.3        136.1        95.6        601.8   
                                                                   

% of Total

        2.1     6.8     91.1     100.0     80.5     19.5     13.7     86.3
                                                                   

Our reserve estimates are prepared from geological data assembled and analyzed by our staff of geologists and engineers. This data is obtained through our extensive, ongoing exploration drilling and in-mine channel sampling programs. Our drill spacing criteria adhere to standards as defined by the 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.

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 audit of our reserves and calculation methods in August 2010.

 

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Reserves represent that part of a mineral deposit that can be economically and legally extracted or produced, and reflect estimated losses involved in producing a saleable product. All of our reserves are steam coal, except for reserves at Mettiki that can be delivered to the steam or metallurgical markets. The 14.6 million tons of reserves listed as <1.2 pounds of SO2 per million British thermal units (“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. British thermal units (“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—6.3 million tons, Pattiki—4.8 million tons, Hopkins County Coal—3.1 million tons, River View—19.6 million tons, Sebree—1.2 million tons, Gibson (North)—2.5 million tons, Gibson (South)—5.6 million tons, Warrior—12.1 million tons, Mettiki—2.9 million tons; Tunnel Ridge—3.4 million tons, Penn Ridge—3.4 million tons, Pontiki—8.6 million tons, and 64.3 million tons of coal located near the River View complex, for total non-reserve coal deposits of 137.8 million tons.

We lease most of our reserves and generally have the right to maintain leases in force until the exhaustion of mineable and merchantable coal located within the leased premises or a larger 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:

 

          Tons Produced     

Transportation

   Equipment  

Operations

  

Location

   2010      2009      2008              
          (in millions)              

Illinois Basin Operations

                 

Dotiki

   Kentucky      3.9         4.2         4.7      

CSX, PAL, truck, barge

     CM   

Warrior

   Kentucky      5.8         6.2         5.1      

CSX, PAL, truck, barge

     CM   

Hopkins

   Kentucky      3.3         4.0         4.0      

CSX, PAL, truck, barge

     CM, DL   

River View

   Kentucky      5.9         0.5         —        

Barge

     CM   

Pattiki

   Illinois      1.7         2.5         2.7      

CSX, EVW, barge

     CM   

Gibson (North)

   Indiana      3.1         3.3         3.8      

CSX, NS, truck, barge

     CM   
                                   

Region Total

        23.7         20.7         20.3         
                                   

Central Appalachian Operations

                 

Pontiki

   Kentucky      0.9         1.1         1.5      

NS, truck, barge

     CM   

MC Mining

   Kentucky      1.4         1.5         1.7      

CSX, truck, barge

     CM   
                                   

Region Total

        2.3         2.6         3.2         
                                   

Northern Appalachian Operations

                 

Mettiki

   Maryland      0.4         0.3         0.4      

Truck, CSX

     CM, CS   

Mountain View

   West Virginia      2.4         2.2         2.5      

Truck, CSX

     LW, CM   

Tunnel Ridge

   West Virginia      0.1         —           —        

Barge

     LW, CM   
                                   

Region Total

        2.9         2.5         2.9         
                                   

TOTAL

        28.9         25.8         26.4         
                                   

 

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

 

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. 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. 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

 

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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.

A bench trial of the case was concluded in November 2009. During November 2010, the court entered judgment for the Plaintiffs and awarded damages of $3.8 million comprising royalty payments through August 31, 2009 with prejudgment interest, plus royalties for the period of September 1, 2009 through the date of judgment (which total approximately $0.5 million, including prejudgment interest), and ordered the Alliance Defendants to pay royalties on coal mined in the future from property covered by the assigned leases. The Alliance Defendants have appealed the judgment to the Illinois Fifth District Appellate Court. The Plaintiffs’ cross-appealed claiming the court should have awarded them the present value of future royalties. Both appeals are pending. We continue to believe the Plaintiff’s 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. By order filed February 26, 2010, the Fifth Circuit granted the Defendants’ petition for rehearing en banc and, on May 28, 2010, dismissed the appeal. The Plaintiffs’ petitioned the U.S. Supreme Court to issue a Writ of Mandamus ordering the Fifth Circuit to reinstate the appeal, which the Supreme Court denied on January 10, 2011, effectively ending the litigation. As a result, this complaint will not have an adverse effect on our business, financial position or results of operations. If, however, tort claims brought in other cases against corporate defendants for liability arising from greenhouse gas emissions are successful, demand for our coal could be adversely impacted.

 

ITEM 4. RESERVED

 

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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, 2011, the closing market price for the common units was $73.78 per unit. As of February 23, 2011, there were 36,775,741 common units outstanding. There were approximately 35,643 record holders and beneficial owners (held in street name) of common units at December 31, 2010.

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 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)

1st Quarter 2010

   $ 45.72       $ 37.51       $0.790 (paid May 14, 2010)

2nd Quarter 2010

   $ 52.45       $ 37.96       $0.810 (paid August 13, 2010)

3rd Quarter 2010

   $ 60.95       $ 43.00       $0.830 (paid November 12, 2010)

4th Quarter 2010

   $ 66.11       $ 55.99       $0.860 (paid February 14, 2011)

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, 2010, 2009, 2008, 2007 and 2006.

 

(in millions, except per unit and per ton data)                               
     Year Ended December 31,  
     2010     2009     2008     2007     2006  

Statements of Income

          

Sales and operating revenues:

          

Coal sales

   $ 1,551.5      $ 1,163.9      $ 1,093.1      $ 960.3      $ 895.8   

Transportation revenues

     33.6        45.7        44.7        37.7        39.9   

Other sales and operating revenues

     24.9        21.4        18.7        35.3        31.9   
                                        

Total revenues

     1,610.0        1,231.0        1,156.5        1,033.3        967.6   
                                        

Expenses:

          

Operating expenses (excluding depreciation, depletion and amortization)

     1,009.9        797.6        801.9        685.1        627.8   

Transportation expenses

     33.6        45.7        44.7        37.7        39.9   

Outside coal purchases

     17.1        7.5        23.8        22.0        19.2   

General and administrative

     50.8        41.1        37.2        34.4        30.9   

Depreciation, depletion and amortization

     146.9        117.5        105.3        85.3        66.5   

Gain from sale of coal reserves

     —          —          (5.2     —          —     

Net gain from insurance settlement and other (1)

     —          —          (2.8     (11.5     —     
                                        

Total operating expenses

     1,258.3        1,009.4        1,004.9        853.0        784.3   
                                        

Income from operations

     351.7        221.6        151.6        180.3        183.3   

Interest expense (net of interest capitalized)

     (30.1     (30.8     (22.1     (11.7     (12.2

Interest income

     0.2        1.0        3.7        1.7        3.0   

Other income

     0.9        1.3        0.9        1.4        0.9   
                                        

Income before income taxes and cumulative effect of accounting change

     322.7        193.1        134.1        171.7        175.0   

Income tax expense (benefit)

     1.7        0.7        (0.5     1.6        2.4   
                                        

Income before cumulative effect of accounting change

     321.0        192.4        134.6        170.1        172.6   

Cumulative effect of accounting change (2)

     —          —          —          —          0.1   
                                        

Net income

     321.0        192.4        134.6        170.1        172.7   

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”)

   $ 321.0      $ 192.2      $ 134.2      $ 170.4      $ 172.9   
                                        

General Partners’ interest in Net Income of ARLP

   $ 73.2      $ 60.7      $ 45.7      $ 31.3      $ 24.6   
                                        

Limited Partners’ interest in Net Income of ARLP

   $ 247.8      $ 131.5      $ 88.5      $ 139.1      $ 148.3   
                                        

Basic net income of ARLP per limited partner unit

   $ 6.68      $ 3.56      $ 2.39      $ 3.78      $ 4.03   
                                        

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

   $ 6.68      $ 3.56      $ 2.39      $ 3.78      $ 4.03   
                                        

Distributions paid per limited partner unit

   $ 3.205      $ 2.95      $ 2.53      $ 2.20      $ 1.92   
                                        

Weighted average number of units outstanding-basic

     36,710,431        36,655,555        36,604,707        36,548,150        36,425,350   
                                        

Weighted average number of units outstanding-diluted

     36,710,431        36,655,555        36,604,707        36,548,150        36,425,350   
                                        

Balance Sheet Data:

          

Working capital

   $ 348.7      $ 54.9      $ 239.8      $ 25.9      $ 37.4   

Total assets

     1,501.3        1,051.4        1,030.6        701.7        635.0   

Long-term obligations (4)

     704.2        422.5        440.8        137.1        127.5   

Total liabilities (5)

     1,045.5        730.4        740.4        384.0        385.6   

Partners’ capital (5)

     455.8        321.0        290.2        317.7        249.3   

Other Operating Data:

          

Tons sold

     30.3        25.0        27.2        24.7        24.4   

Tons produced

     28.9        25.8        26.4        24.3        23.7   

Revenues per ton sold (6)

   $ 52.04      $ 47.41      $ 40.88      $ 40.31      $ 38.02   

Cost per ton sold (7)

   $ 35.58      $ 33.85      $ 31.72      $ 30.02      $ 27.78   

Other Financial Data:

          

Net cash provided by operating activities

   $ 520.6      $ 282.7      $ 261.0      $ 244.0      $ 250.9   

Net cash used in investing activities

     (295.0     (320.1     (184.1     (178.7     (137.7

Net cash provided by (used in) financing activities

     92.7        (186.6     166.8        (101.0     (108.5

EBITDA (8)

     499.5        340.4        257.8        267.0        250.8   

Maintenance capital expenditures (9)

     90.5        96.1        77.7        76.3        67.8   

 

(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.

 

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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 on January 1, 2006.
(3) Basic and diluted earnings per unit (“EPU”) have been restated for the years ending December 31, 2008, 2007 and 2006 due to the adoption of FASB ASC 260-10-55-102 through 55-110, Master Limited Partnerships. Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive units calculated under the treasury stock method if their effect is anti-dilutive. For the years ended December 31, 2010, 2009, 2008, 2007 and 2006, long-term incentive plan (“LTIP”), Supplemental Executive Retirement Plan (“SERP”) and Directors compensation units of 232,042, 176,743, 165,175, 252,061 and 385,032 respectively, were considered anti-dilutive.
(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, 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”) financial 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,  
   2010     2009     2008     2007     2006  

Cash flows provided by operating activities

   $ 520,588      $ 282,741      $ 261,041      $ 244,012      $ 250,923   

Non-cash compensation expense

     (4,051     (3,582     (3,931     (3,925     (4,112

Asset retirement obligations

     (2,579     (2,678     (2,827     (2,419     (2,101

Coal inventory adjustment to market

     (498     (3,030     (452     (21     (319

Net gain (loss) on foreign currency exchange

     (274     653        —          —          —     

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

     (234     (136     911        3,189        1,188   

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 vertical hoist conveyor system

     (1,204     —          —          —          —     

Other

     (1,448     (537     (366     (811     (1,119

Net effect of working capital changes

     (42,402     36,440        (19,661     7,898        (5,317

Interest expense, net

     29,862        29,798        18,418        9,952        9,175   

Income tax expense (benefit)

     1,741        708        (480     1,669        2,443   
                                        

EBITDA

     499,501        340,377        257,812        266,989        250,761   

Depreciation, depletion and amortization

     (146,881     (117,524     (105,278     (85,310     (66,489

Interest expense, net

     (29,862     (29,798     (18,418     (9,952     (9,175

Income tax (expense) benefit

     (1,741     (708     480        (1,669     (2,443

Cumulative effect of accounting change

     —          —          —          —          112   
                                        

Net income

     321,017        192,347        134,596        170,058        172,766   

Net (income) loss attributable to noncontrolling interest

     —          (190     (420     332        161   
                                        

Net income of ARLP

   $ 321,017      $ 192,157      $ 134,176      $ 170,390      $ 172,927   
                                        

 

(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 2010, our total production was 28.9 million tons and our total sales were 30.3 million tons. The coal we produced in 2010 was approximately 8.0% low-sulfur coal, 20.7% medium-sulfur coal and 71.3% 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, 2010, had approximately 697.4 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.

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

 

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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 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 the 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 our union-free workforce are related to higher productivity and are not necessarily reflected in our direct costs. 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 River View mine, Tunnel Ridge development project and Mt. Vernon transloading facility are located on the Ohio River, and as indicated in Item 2. “Properties”, most of our operations have access to barge loading facilities.

Our primary business strategy is to create sustainable, capital-efficient growth in available cash to maximize 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 within the coal industry and MLP sector.

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 mining complex, which initiated operations in 2009, the Sebree property, the Gibson South property and certain properties of Alliance Resource Properties and its wholly-owned subsidiary, ARP Sebree, LLC. We are in the process of permitting the Gibson South property and the Sebree 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, a mining complex currently under construction at Tunnel Ridge, and the Penn Ridge property. In May 2010, incidental production began from mine development activities at Tunnel Ridge, however, longwall production is not anticipated until early 2012. 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.”

 

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Other and Corporate segment includes marketing and administrative expenses, Matrix Design Group, LLC (“Matrix Design”), Alliance Design Group, LLC (“Alliance Design”) (collectively, Matrix Design and Alliance Design are referred to as the “Matrix Group”), the Mt. Vernon dock activities, coal brokerage activity, our equity investment in MAC and certain properties of Alliance Resource Properties.

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.

Saleable Tons Produced Per Unit Shift. We review saleable 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 (a non-GAAP financial measure) 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 (a non-GAAP financial measure) 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 2010, approximately 91.5% of our sales tonnage was consumed by electric utilities, with the balance shipped to third-party resellers, industrial consumers and cogeneration plants. In 2010, approximately 92.4% of our sales tonnage, including approximately 94.5% 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 2010, approximately 91.8% 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.

Health Care Reform

On March 23, 2010, President Obama signed into law the PPACA. Additionally, on March 30, 2010, President Obama signed into law a reconciliation measure, the Health Care and Education Reconciliation Act of 2010.

 

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Implementation of the PPACA and the Health Care and Education Reconciliation Act (collectively, the “Health Care Act”) will result in comprehensive changes to health care in the U.S. Implementation of this legislation is planned to occur in phases, with standard plan changes taking effect beginning in 2010, but to a greater extent with the 2011 benefit plan year and extending through 2018.

The Health Care Act has both short-term and long-term implications on benefit plan eligibility, coverage requirements, and benefit standards and limitations. In the short term, our health care costs are expected to increase due to raising the maximum age and easing of eligibility limitations for covered dependents. The Health Care Act also prevents the group health plan from limiting benefit payments for participants who meet or exceed annual or lifetime dollar limits per covered individual. We do not currently expect raising the maximum age and easing of eligibility limitations for covered dependents to significantly increase our annual health care costs beginning in 2011. In addition, we currently expect removing the lifetime maximum could have an additional impact on us that we are unable to reasonably estimate at this time. While historically few participants have reached the plan lifetime maximum limit of $1 million, future federal and state mandates are expected to impact large claims costs and make this a potentially greater risk in the future. In the long term, our plan’s health care costs are expected to increase for various reasons due to the Health Care Act, including the potential impact of an excise tax on “high cost” plans (beginning in 2018), among other standard requirements. We have chosen not to “grandfather” our health care plan as allowed under the Health Care Act. This decision allows us to make benefit modifications that encourage participants to use high value, lower cost medical care options such as on-site medical services, generic preferred medications, and urgent care centers instead of emergency rooms.

We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of the Health Care Act and reporting required thereunder. Until these regulations or interpretations are published, we are unable to reasonably estimate the further impact of such federal mandate requirements on our future health care costs.

The Health Care Act also amended previous legislation related to coal workers’ pneumoconiosis, or black lung, providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims. The impact of these changes to our current population of beneficiaries and claimants resulted in an estimated $8.3 million increase to our black lung obligation at December 31, 2010. This increase to our obligation excludes the impact of potential re-filing of closed claims and potential filing rates for employees who terminated more than seven years ago as we do not have sufficient information to determine what, if any, claims will be filed until regulations are issued.

We will continue to evaluate the potential impact of the legislation on our self-insured long term disability plan, black lung liabilities, results of operations and internal controls as governmental agencies issue interpretations regarding the meaning and scope of the Health Care Act. However, we believe it is likely that our costs will increase as a result of these provisions, which may have an adverse impact on our results of operations and cash flows.

The Dodd–Frank Act

On July 21, 2010, President Obama signed into law the Dodd–Frank Wall Street Reform and Consumer Protection Act (“Dodd–Frank Act”). The Dodd–Frank Act gives regulators new resolution authority, creates a new council to monitor and address systemic risk, changes the mandate of the Federal Reserve, imposes significant new regulations on banking organizations, makes significant changes to the rules that affect the process of financing business enterprises and creates a new governmental authority, the Bureau of Consumer Financial Protection, to regulate retail financial products and services, among many other provisions.

The additional regulations imposed by the Dodd–Frank Act on financial institutions may result in increased costs associated with future borrowings and decreased availability of credit. However, we are presently unable to determine the significance of any potential increase in our borrowing costs or potential liquidity constraints, if any. The Dodd–Frank Act also requires public mining companies to report certain safety information regarding citations, penalties and pending legal actions in each periodic report filed with the SEC and to file current reports on Form 8-K for certain safety matters. We are continuing to evaluate the effect of the Dodd–Frank Act on the Partnership’s operations.

 

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Analysis of Historical Results of Operations

2010 Compared with 2009

We reported record Net Income of ARLP of $321.0 million in 2010 compared to $192.2 million in 2009. This increase of $128.8 million was principally due to increased tons sold and improved contract pricing resulting in an average coal sales price of $51.21 per ton sold, as compared to $46.60 per ton sold in 2009. We sold 30.3 million tons and produced 28.9 million tons in 2010 compared to 25.0 million tons sold and 25.8 million tons produced in 2009. This increase in tons sold and produced primarily reflects increased production from our River View mine and resulted in higher operating expenses during 2010, particularly impacting materials and supplies expenses, sales-related expenses and labor and labor-related expenses. Expenses were further impacted by increased depreciation, depletion and amortization.

 

     December 31,      December 31,  
   2010      2009      2010      2009  
     (in thousands)      (per ton sold)  

Tons sold

     30,295         24,975         N/A         N/A   

Tons produced

     28,860         25,838         N/A         N/A   

Coal sales

   $ 1,551,539       $ 1,163,871       $ 51.21       $ 46.60   

Operating expenses and outside coal purchases

   $ 1,027,013       $ 805,051       $ 33.90       $ 32.23   

Coal sales. Coal sales increased 33.3% to $1.6 billion in 2010 from $1.2 billion in 2009. The increase of $387.6 million reflected the benefit of increased tons sold (contributing $247.9 million in coal sales) and higher average coal sales prices (contributing $139.7 million in additional coal sales). Average coal sales price increased $4.61 per ton sold in 2010 to $51.21 per ton compared to $46.60 per ton in 2009, primarily as a result of improved contract pricing across all regions.

Operating expenses. Operating expenses increased 26.6% to $1.0 billion in 2010 from $797.5 million in 2009 primarily due to record coal sales and production volumes. Increased River View production and Tunnel Ridge development combined to increase certain operating expenses $109.0 million during 2010 compared to 2009 and are generally included in the variances discussed further below. In addition to the impact of record volumes, operating expenses were impacted by various other factors, the most significant of which are discussed below:

 

   

Labor and benefit expenses per ton produced, excluding workers’ compensation, decreased 1.0% to $10.97 per ton in 2010 from $11.08 per ton in 2009. The decrease of $0.11 per ton was primarily attributable to lower labor cost per ton resulting from production at our River View mine, a decrease in the cost of training new employees in the Illinois Basin and lower pension plan expense, partially offset by increased mine development labor at our Tunnel Ridge mine, heightened regulatory oversight, particularly at our Central Appalachian mines, and production disruptions at our Dotiki, Gibson and Pattiki mines during 2010;

 

   

Workers’ compensation expenses per ton produced decreased to $0.72 per ton in 2010 from $0.96 per ton in 2009. The decrease of $0.24 per ton primarily reflected favorable reserve adjustments in the fourth quarter of 2010 related to our annual actuary analysis for claims related to prior years, partially offset by a non-cash charge that resulted from a decrease in the discount rate from 5.27% at the end of 2009 to 4.70% at the end of 2010;

 

   

Material and supplies expenses per ton produced increased 9.7% to $10.55 per ton in 2010 from $9.62 per ton in 2009. The increase of $0.93 per ton resulted from increased costs for certain products and services, primarily roof support (increase of $0.22 per ton), outside services expenses (increase of $0.19 per ton), power and fuel used in the mining process (increase of $0.17 per ton), contract labor used in the mining process (increase of $0.12 per ton) and rock dust (increase of $0.09 per ton) in addition to the negative cost impact of heightened regulatory oversight;

 

   

Maintenance expenses per ton produced decreased 1.1% to $3.63 per ton in 2010 from $3.67 per ton in 2009. The decrease of $0.04 per ton resulted primarily from the benefit of newer equipment and increased production at our River View mining complex, partially offset by higher maintenance at our Mettiki mine reflecting increased longwall and continuous mining run days and higher maintenance costs associated with our mine development project at Tunnel Ridge;

 

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Mine administration expenses increased $14.9 million in 2010 compared to 2009, primarily due to increased legal expenses and related contingency accruals, higher third-party product sales by Matrix Design and increased regulatory costs;

 

   

Contract mining expenses increased $5.6 million in 2010 compared to 2009. The increase primarily reflects the restart of a third-party mining operation in our Northern Appalachian region during February 2010 that was previously idled in May 2009 and increased production from other existing contract mining operations in Northern Appalachia, both in response to increased demand in the export coal market;

 

   

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 2010 compared to 2009, primarily as a result of increased average coal sales prices across all regions;

 

   

Operating expenses increased due to a reduction in coal inventory of 1.0 million tons in 2010 reflecting higher coal sales, in comparison to 2009 during which coal inventory increased 1.1 million tons; and

 

   

Operating expenses in 2010 included $1.2 million for the retirement of certain assets resulting from the failure of the vertical hoist conveyor system at our Pattiki mine. For more information, please read “Part II. Item 8. Financial Statements – Note 4. Pattiki Vertical Hoist Conveyor System Failure” of this Annual Report on Form 10-K.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, products and services provided by MAC (in 2009 only), Matrix Design and other outside services and administrative services revenue from affiliates. Other sales and operating revenues increased to $24.9 million in 2010 from $21.4 million in 2009. The increase of $3.5 million was primarily attributable to increased Matrix Design product sales, partially offset by lower transloading revenues and decreased rock dust revenues reflecting the deconsolidation of MAC. For more information about MAC, please read “Part II. Item 8. Financial Statements – Note 18. Noncontrolling Interest” of this Annual Report on Form 10-K.

Outside coal purchases. Outside coal purchases increased to $17.1 million in 2010 from $7.5 million in 2009. The increase of $9.6 million was primarily attributable to an increase in outside coal purchases related to our Northern Appalachian region in response to improved demand in the export coal markets and increased coal brokerage activity partially offset by decreased outside coal purchases in the Central Appalachian region due to the lack of attractive sales opportunities in the coal spot markets that were available in the first quarter of 2009.

General and administrative. General and administrative expenses in 2010 increased to $50.8 million compared to $41.1 million in 2009. The increase of $9.7 million was primarily attributable to increased incentive compensation expense and retirement plan expense.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased to $146.9 million in 2010 compared to $117.5 million in 2009. The increase of $29.4 million was primarily attributable to additional depreciation expense associated with our River View mine in addition to continuing capital expenditures related to infrastructure improvements and efficiency projects.

Interest expense. Interest expense, net of capitalized interest, decreased to $30.1 million in 2010 from $30.8 million in 2009. The decrease of $0.7 million was principally attributable to reduced interest expense resulting from annual principal repayments made during August 2010 and 2009 of $18.0 million on our original senior notes issued in 1999, partially offset by increased interest expense for borrowings under our revolving credit facility during 2010, each of which is discussed in more detail below under “—Debt Obligations.”

Interest income. Interest income decreased to $0.2 million in 2010 from $1.0 million in 2009. The decrease of $0.8 million resulted from reduced interest income earned on short-term investments, which were substantially liquidated throughout 2009.

 

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Transportation revenues and expenses. Transportation revenues and expenses each decreased to $33.6 million in 2010 from $45.7 million in 2009. The decrease of $12.1 million was primarily attributable to reduced tonnage in 2010 for which we arranged the transportation compared to 2009. The cost of transportation services are passed through to our customers. Consequently, we do not realize any gain or loss on transportation revenues.

Income tax expense. Income tax expense increased to $1.7 million in 2010 from $0.7 million in 2009. The increase of $1.0 million was primarily due to higher net income in 2010 from our Matrix Design operation.

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. Effective January 1, 2010, we deconsolidated MAC based on amendments to the provisions of FASB ASC 810, Consolidation. 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 2010 Segment Adjusted EBITDA increased 44.3% to $550.3 million from 2009 Segment Adjusted EBITDA of $381.5 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)  
     2010     2009    

Segment Adjusted EBITDA

        

Illinois Basin

   $ 460,592      $ 315,542      $ 145,050        46.0

Central Appalachia

     36,714        41,149        (4,435     (10.8 )% 

Northern Appalachia

     46,702        15,552        31,150        (1

Other and Corporate

     6,311        9,621        (3,310     (34.4 )% 

Elimination

     —          (370     370        (1
                          

Total Segment Adjusted EBITDA (2)

   $ 550,319      $ 381,494      $ 168,825        44.3
                          

Tons sold

        

Illinois Basin

     24,763        19,660        5,103        26.0

Central Appalachia

     2,221        2,641        (420     (15.9 )% 

Northern Appalachia

     3,256        2,660        596        22.4

Other and Corporate

     55        14        41        (1

Elimination

     —          —          —          —     
                          

Total tons sold

     30,295        24,975        5,320        21.3
                          

Coal sales

        

Illinois Basin

   $ 1,176,275      $ 846,940      $ 329,335        38.9

Central Appalachia

     164,834        179,369        (14,535     (8.1 )% 

Northern Appalachia

     207,057        136,412        70,645        51.8

Other and Corporate

     3,373        1,150        2,223        (1

Elimination

     —          —          —          —     
                          

Total coal sales

   $ 1,551,539      $ 1,163,871      $ 387,668        33.3
                          

Other sales and operating revenues

        

Illinois Basin

   $ 1,357      $ 1,151      $ 206        17.9

Central Appalachia

     199        191        8        4.2

Northern Appalachia

     3,520        3,316        204        6.2

Other and Corporate

     41,681        39,260        2,421        6.2

Elimination

     (21,815     (22,491     676        3.0
                          

Total other sales and operating revenues

   $ 24,942      $ 21,427      $ 3,515        16.4
                          

Segment Adjusted EBITDA Expense

        

Illinois Basin

   $ 717,040      $ 532,549      $ 184,491        34.6

Central Appalachia

     128,318        138,412        (10,094     (7.3 )% 

Northern Appalachia

     163,876        124,176        39,700        32.0

Other and Corporate

     38,743        30,789        7,954        25.8

Elimination

     (21,815     (22,122     307        1.4
                          

Total Segment Adjusted EBITDA Expense (3)

   $ 1,026,162      $ 803,804      $ 222,358        27.7
                          

 

(1) Percentage increase or decrease was greater than or equal to 100%.
(2) Segment Adjusted EBITDA (a non-GAAP financial measure) 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, which are discussed above under “—Analysis of Historical Results of Operations”, 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, the most comparable GAAP financial measure (in thousands):

 

     Year Ended December 31,  
     2010     2009  

Segment Adjusted EBITDA

   $ 550,319      $ 381,494   

General and administrative

     (50,818     (41,117

Depreciation, depletion and amortization

     (146,881     (117,524

Interest expense, net

     (29,862     (29,798

Income tax expense

     (1,741     (708
                

Net income

     321,017        192,347   

Net income attributable to noncontrolling interest

     —          (190
                

Net income of ARLP

   $ 321,017      $ 192,157   
                

 

(3) Segment Adjusted EBITDA Expense (a non-GAAP financial measure) 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, the most comparable GAAP financial measure (in thousands):

 

     Year Ended December 31,  
     2010     2009  

Segment Adjusted EBITDA Expense

   $ 1,026,162      $ 803,804   

Outside coal purchases

     (17,078     (7,524

Other income

     851        1,247   
                

Operating expense (excluding depreciation, depletion and amortization)

   $ 1,009,935      $ 797,527   
                

 

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Illinois Basin – Segment Adjusted EBITDA increased 46.0% to $460.6 million in 2010 from $315.5 million in 2009. The increase of $145.1 million was primarily attributable to increased tons sold, which increased 26.0% to 24.8 million tons sold in 2010, as well as improved contract pricing resulting in a higher average coal sales price of $47.50 per ton during 2010 compared to $43.08 per ton in 2009. Coal sales increased 38.9% to $1.2 billion in 2010 compared to $846.9 million in 2009. The increase of $329.3 million primarily reflects increased sales from our River View mine (which commenced operations in August of 2009 and continued to expand production during 2010), increased sales from coal inventories in the region and the negative impact of weather disruptions in 2009 at our Dotiki, Warrior and Elk Creek mines, partially offset by production disruptions at our Dotiki, Gibson and Pattiki mines during 2010. Total Segment Adjusted EBITDA Expense in 2010 increased 34.6% to $717.0 million from $532.5 million in 2009 and increased $1.87 per ton sold to $28.96 from $27.09 per ton sold, primarily as a result of certain cost increases described above under consolidated operating expenses as well as a $1.2 million loss on the retirement of certain assets related to the failure of the vertical hoist conveyor system at our Pattiki mine, the aforementioned production disruptions at our Dotiki, Gibson and Pattiki mines and increased sales from coal inventories in the region. For more information on our Pattiki mine, please read “Part II. Item 8. Financial Statements – Note 4. Pattiki Vertical Hoist Conveyor System Failure” of this Annual Report on Form 10-K.

Central Appalachia – Segment Adjusted EBITDA decreased $4.4 million, or 10.8%, to $36.7 million in 2010, compared to $41.1 million in 2009. The decrease was primarily the result of lower sales volumes due to the impact of heightened regulatory oversight, reduced coal demand in the spot market during 2010, lower clean coal recovery due to mining conditions and the continued impact of idling one mining unit at Pontiki beginning in July 2009, partially offset by improved contract pricing in 2010 that resulted in an increase in the average coal sales price of $6.28 per ton to $74.19 per ton in 2010, as compared to $67.91 per ton in 2009. Segment Adjusted EBITDA Expense per ton sold during 2010 increased to $57.76 compared to $52.41 per ton sold, an increase of $5.35 per ton sold, reflecting certain cost increases described above under consolidated operating expenses, as well as the impact of lower coal sales volumes and decreased coal production in response to lower spot market demand and lower productivity due to Pontiki’s transition from the depleted Pond Creek coal seam into the thinner Van Lear coal seam beginning in 2009. Although Segment Adjusted EBITDA Expense per ton sold increased, Segment Adjusted EBITDA Expense for 2010 decreased 7.3% to $128.3 million from $138.4 million in 2009 primarily as a result of lower coal sales offset in part by higher expenses per ton as described above.

Northern Appalachia – Segment Adjusted EBITDA increased to $46.7 million in 2010, compared to $15.6 million in 2009. The increase of $31.1 million was primarily attributable to a higher average sales price of $63.60 per ton sold in 2010 compared to $51.28 per ton sold in 2009, and a 22.4% increase in tons sold to 3.3 million tons in 2010, both resulting from improved demand in the export coal markets, as well as the benefit of increased production days and additional contract miner production. Segment Adjusted EBITDA Expense for 2010 increased 32.0% to $163.9 million from $124.2 million in 2009 and increased $3.66 on a per ton sold basis to $50.34 from $46.68 per ton sold, primarily as a result of higher coal sales volumes, higher costs associated with producing metallurgical quality coal, lower coal recoveries due to adverse geologic conditions, as well as other cost increases described above under consolidated operating expenses, including non-capitalized costs incurred related to our Tunnel Ridge mine development project.

Other and Corporate – Segment Adjusted EBITDA decreased to $6.3 million in 2010 from $9.6 million in 2009. The decrease of $3.3 million was primarily attributable to the impact of the deconsolidation of MAC effective January 1, 2010, lower EBITDA associated with Matrix Group safety equipment sales to our other subsidiaries (which are eliminated upon consolidation), a loss in 2010 compared to a gain in 2009 associated with United Kingdom (“UK”) currency previously held for equipment purchases from a UK supplier and lower Mt. Vernon outside transloading revenues and affiliate administrative service revenues, partially offset by higher EBITDA resulting from increased third-party safety equipment sales and services revenue at Matrix Design. Other sales and operating revenues increased 6.2% to $41.7 million for 2010 compared to $39.3 million for 2009. The increase of $2.4 million was primarily attributable to increased services revenue and sales of mine safety equipment by the Matrix Group. Segment Adjusted EBITDA Expense increased 25.8% to $38.7 million for 2010, primarily due to increased expenses associated with higher services revenue and safety equipment sales by the Matrix Group, higher coal brokerage expenses associated with increased brokerage coal sales offset in part by the impact of the deconsolidation of MAC mentioned above. For more information about MAC, please read “Part II. Item 2. Financial Statements – Note 18. Noncontrolling Interest” of this Annual Report on Form 10-K.

 

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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, the 2008 operating results included significant non-recurring gains of $9.9 million related to the sale of non-core coal reserves and the settlement of claims. 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.

 

     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;

 

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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;

 

   

Operating expenses incurred in 2009 relating to our River View and Tunnel Ridge mine development projects increased $18.7 million over 2008. These 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 hoist conveyor 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, 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 2008, partially offset by reduced interest expense resulting from annual principal repayments made during August 2009 and 2008 of $18.0 million on our original 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 costs of transportation services are a pass-through to our customers; consequently, we do not realize any gain or loss on our transportation revenues.

 

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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. Effective January 1, 2010, we deconsolidated MAC based on amendments to the provisions of FASB ASC 810, Consolidation. 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 (a non-GAAP financial measure) 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, which are discussed above under “—Analysis of Historical Results of Operations”, 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, the most comparable GAAP financial measure (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 attributable to noncontrolling interest

     (190     (420
                

Net Income of ARLP

   $ 192,157      $ 134,176   
                

 

(3) Segment Adjusted EBITDA Expense (a non-GAAP financial measure) 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, the most comparable GAAP financial measure (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 hoist conveyor incident in 2008. 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.

Pattiki Vertical Hoist Conveyor System Failure

On May 13, 2010, White County Coal’s Pattiki mine was temporarily idled following the failure of the vertical hoist conveyor system used in conveying raw coal out of the mine. Our operating expenses for the twelve months ended December 31, 2010 include $1.2 million for retirement of certain assets related to the failed vertical hoist conveyor system in addition to other repair and clean-up expenses that were not significant on a consolidated or segment basis. We reviewed our commercial property (including business interruption) insurance policies and, as the loss on the vertical hoist conveyor system did not exceed our deductible for property damage, we do not expect any recovery under such policies.

 

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While the Pattiki mine was temporarily idled, we expanded coal production at our other coal mines in the region, including the addition of the seventh and eighth production units at the River View mine, to partially offset the loss of production from the Pattiki mine. Consequently, the temporary idling of the Pattiki mine did not have a material adverse impact on our results of operations and cash flows. On July 19, 2010, the Pattiki mine resumed limited production while White County Coal continued to assess the effectiveness and reliability of the repaired vertical hoist conveyor system. On January 3, 2011, the Pattiki mine returned to full production capacity.

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”.

Cash Flows

Cash provided by operating activities was $520.6 million in 2010 compared to $282.7 million in 2009. The increase in cash provided by operating activities was principally attributable to higher net income, a reduction in coal inventory costs during 2010 as compared to a significant increase during 2009 and increases in certain operating liabilities, such as accounts payable, accrued taxes other than income taxes, accrued payroll and related expenses. These increases in cash provided by operating activities were partially offset by increases in certain operating assets, such as accounts receivable.

Net cash used in investing activities was $295.0 million in 2010 compared to $320.1 million in 2009. The decrease in cash used for investing activities was primarily attributable to decreased capital expenditures due to the completion of our River View mine development and Warrior infrastructure additions in 2009, partially offset by an increase in Tunnel Ridge capital expenditures in 2010 and timing differences in accounts payable and accrued liabilities compared to 2009.

Net cash provided by financing activities was $92.7 million in 2010 compared to net cash used in financing activities of $186.6 million in 2009. The increase in cash provided by financing activities was primarily attributable to the proceeds from the $300 million term loan completed on December 29, 2010 (see “–Debt Obligations”) partially offset by increased distributions paid to partners in 2010.

 

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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 future 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, 2010 (in thousands):

 

Contractual

Obligations

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

Long-term debt

   $ 722,000       $ 18,000       $ 96,000       $ 463,000       $ 145,000   

Future interest obligations(1)

     174,038         35,022         66,101         48,663         24,252   

Operating leases

     4,775         1,901         1,130         734         1,010   

Capital leases(2)

     1,107         515         592         —           —     

Purchase obligations for capital projects

     86,788         86,788         —           —           —     

Coal purchase commitments

     14,070         14,070         —           —           —     

Reclamation obligations(3)

     130,978         2,182         3,502         3,488         121,806   

Workers’ compensation and pneumoconiosis benefit(3)

     327,845         14,281         21,125         17,579         274,860   
                                            
   $ 1,461,601       $ 172,759       $ 188,450       $ 533,464       $ 566,928   
                                            

 

(1) Interest on variable rate long-term debt was calculated using rates elected by us at December 31, 2010 for the remaining term of outstanding borrowings.
(2) Includes amounts classified as interest and maintenance cost.
(3) Future commitments for reclamation obligations, workers’ compensation and pneumoconiosis are shown at undiscounted amounts.

We expect to contribute $5.0 million to the defined benefit pension plan (“Pension Plan”) during 2011. We estimate our income tax cash requirements to be approximately $1.3 million in 2011.

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, 2010 (in thousands):

 

     Reclamation
Obligation
     Workers’
Compensation
Obligation
     Other      Total  

Surety bonds

   $ 68,430       $ 39,924       $ 11,665       $ 120,019   

Letters of credit

     —           29,697         9,548         39,245   

Capital Expenditures

Capital expenditures decreased to $289.9 million in 2010 compared to $328.2 million in 2009. See our discussion of “Cash Flows” above concerning this decrease in capital expenditures.

We currently project average estimated annual maintenance capital expenditures over the next five years of approximately $4.70 per ton produced. Our anticipated total capital expenditures for 2011 are estimated in a range of $320.0 to $360.0 million. Management anticipates funding 2011 capital requirements with our December 31, 2010 cash and cash equivalents of $339.6 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.

 

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Insurance

During September 2010, we completed our annual property and casualty insurance renewal with various insurance coverages effective October 1, 2010. The aggregate maximum limit in the commercial property program is $75.0 million per occurrence excluding a $1.5 million deductible for property damage, a 60-day waiting period for business interruption and a $10.0 million overall aggregate deductible. The aforementioned property and casualty insurance coverages, effective October 1, 2010, replaced our prior year 14.7% participation rate with the deductibles mentioned above. We can make no assurances that we will not experience significant insurance claims in the future that 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 entered into a $150.0 million revolving credit facility (“ARLP Credit Facility”) dated September 25, 2007, which matures in 2012. The ARLP Credit Facility was decreased to $142.5 million of availability on October 6, 2010 due to a defaulting lender, as discussed below. 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, before carry forward considerations and exclusion of capital expenditures related to acquisitions, are $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 2011 is approximately $531.9 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, 2010, we had $11.6 million of letters of credit outstanding with $130.9 million available for borrowing under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility as of December 31, 2010. We utilize the ARLP Credit Facility, as appropriate, to meet working capital requirements, anticipated capital expenditures, scheduled debt payments or distribution payments. We incur an annual commitment fee of 0.25% on the undrawn portion of the ARLP Credit Facility.

Lehman Commercial Paper, Inc. (“Lehman”), a subsidiary of Lehman Brothers Holding, Inc., held a 5%, or $7.5 million, commitment in the original $150 million ARLP Credit Facility. Lehman filed for protection under Chapter 11 of the Federal Bankruptcy Code in early October 2008. On February 11, 2010, the ARLP Partnership gave its lenders a notice of borrowing under the ARLP Credit Facility and, in response to that notice, Lehman notified the ARLP Partnership 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 on October 6, 2010, was removed as a commitment holder under the ARLP Credit Facility. Consequently, availability for borrowing under the ARLP Credit Facility was reduced by $7.5 million on October 6, 2010. The ARLP Credit Facility is underwritten by a syndicate of eleven financial institutions (excluding Lehman) with no individual institution representing more than 11.9% of the $142.5 million revolving credit facility. In the event any other financial institution in the ARLP Partnership’s syndicate does not fund its future borrowing requests, the ARLP Partnership’s borrowing available under the ARLP Credit Facility would be reduced. The obligations of the lenders under the ARLP Credit Facility are individual obligations and the failure of one or more lenders does not relieve the remaining lenders of their funding obligations.

Senior Notes. Our Intermediate Partnership has $72.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in four remaining equal annual installments of $18.0 million with interest payable semi-annually (“Senior Notes”).

 

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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.

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.

Term Loan. On December 29, 2010, our Intermediate Partnership entered into a term loan agreement (the “Term Loan Agreement”) with various financial institutions for a term loan (the “Loan”) in the aggregate principal amount of $300 million. The Loan bears interest at a variable rate plus an applicable margin which fluctuates depending upon whether we elect the Loan (or a portion thereof) to bear interest on the Base Rate or the Eurodollar Rate (as defined in the Term Loan Agreement). We elected the Eurodollar Rate on December 30, 2010 which, with applicable margin, was 2.3% as of January 5, 2011. Interest for the period between initial funding of the Loan on December 29, 2010 and January 5, 2011, was calculated based on the Base Rate plus the applicable margin. Interest is payable quarterly with principal due as follows: $15 million due per quarter beginning March 31, 2013 through December 31, 2013, $18.75 million due per quarter beginning March 31, 2014 through September 30, 2015 and the balance of $108.75 million due on December 31, 2015. We have the option to prepay the Loan at any time in whole or in part subject to terms and conditions described in the Term Loan Agreement. Upon a “change of control” (as defined in the Term Loan Agreement), the unpaid principal amount of the loan, all interest thereon and all other amounts payable under the Term Loan Agreement will become due and payable.

The net proceeds of the Loan will be used for the general corporate, business or working capital purposes of the Intermediate Partnership and its subsidiaries, including, without limitation, (a) for capital expenditures and acquisitions (including mineral reserve acquisitions), and (b) for cash distributions to the ARLP Partnership to be used by the ARLP Partnership for any business or corporate purpose deemed appropriate by the ARLP Partnership (or its managing general partner). We incurred debt issuance costs of approximately $1.4 million in 2010 associated with the Term Loan Agreement, $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, 2008 Senior Notes and the Term Loan Agreement (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 the following: (i) debt to cash flow ratio of not more than 3.0 to 1.0 and (ii) cash flow to interest expense ratio of not less than 4.0 to 1.0 in each case, during the four most recently ended fiscal quarters. The ARLP Credit Facility, Senior Notes and the 2008 Senior Notes limit our Intermediate Partnership’s maximum annual capital expenditures, excluding acquisitions, as described above. The Credit Amendment did not change the required debt to cash flow or cash flow to interest expense ratios. The debt to cash flow ratio and cash flow to interest expense ratio were 1.4 to 1.0 and 16.5 to 1.0, for the trailing twelve months ended December 31, 2010. Actual capital expenditures were $289.9 million for the year ended December 31, 2010. We were in compliance with the covenants of the ARLP Debt Arrangements as of December 31, 2010.

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, 2010, we had $30.7 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.

 

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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 audit committee of the MGP Board of Directors (“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.

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. 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.

 

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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 $67.7 million and $63.2 million for these costs at December 31, 2010 and 2009, respectively. A one-percentage-point reduction in the discount rate would have increased the liability at December 31, 2010 approximately $4.9 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 discount rates. We had accrued liabilities of $45.7 million and $34.9 million for these benefits at December 31, 2010 and 2009, respectively. A one-percentage-point reduction in the discount rate would have increased the expense recognized for the year ended December 31, 2010 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.

The discount rate for workers’ compensation and black lung is derived by applying the Citigroup Pension Discount Curve to the projected liability payout. Other assumptions, such as development patterns, mortality, disability incidence and medical costs, are based upon standard actuarial tables adjusted for our actual historical experiences whenever possible. We review all actuarial assumptions annually for reasonableness and consistency and update such factors when underlying assumptions, such as discount rates, change or when sustained changes in our historical experiences indicate a shift in our trend assumptions are warranted. For more information please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Health Care Reform,” above.

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, 2010 and 2009, determined by the above factors and an asset allocation assumption of 60.0% invested in domestic equity securities with an expected long-term rate of return of 8.46%, 20.0% invested in international equities with an expected long-term rate of return of 8.85% and 20.0% invested in fixed income securities with an expected long-term rate of return of 4.88%. 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. The actual return on plan assets was 10.4% and 23.7% for the years ended December 31, 2010 and 2009, respectively. Lowering the expected long-term rate of return assumption by 1.0% (from 8.35% to 7.35%) at December 31, 2009 would have increased our pension expense for the year ended December 31, 2010 by approximately $0.4 million; and

 

   

Our weighted average discount rate used to determine our pension liability was 5.56% and 5.88% at December 31, 2010 and 2009, respectively. Our weighted average discount rate used to determine our pension expense was 5.88% and 6.15% at December 31, 2010 and 2009, 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

 

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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 5.88% to 5.38%) at December 31, 2009 would have increased our pension expense for the year ended December 31, 2010 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.

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, 2010 and 2009, mine development costs include $35.3 million and $16.4 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 $58.2 million and $55.9 million for these costs are recorded at December 31, 2010 and 2009, respectively. The liability for asset retirement and closing procedures is sensitive to changes in cost estimates and estimated mine lives.

 

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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 an increase of $0.8 million for the year ended December 31, 2010 and a decrease in the liability of $4.9 million for the year ended December 31, 2009. These adjustments to the liability for the years ended December 31, 2010 and 2009 were primarily attributable to fluctuations in refuse site reclamation disturbances at our Hopkins County Coal operation, increased surface disturbances as a result of the new mine development work at Tunnel Ridge and River View and the impact of favorable permit requirements regarding reduced liner and cover necessary for refuse storage at Gibson County Coal and a reduction in the impoundment cover material acreage at Pontiki and MC Mining, as well as overall general changes in inflation and discount rates, current estimates of the costs and scope of remaining reclamation work and projected mine life estimates for coal reserve increases and decreases across all operations.

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 $72.8 million and $68.0 million at December 31, 2010 and 2009. We estimate that the aggregate undiscounted cost of final mine closure is approximately $131.0 million at December 31, 2010. 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.

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 28, 2011, 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

On April 1, 2010, effective January 1, 2010, ARLP entered into the Administrative Services Agreement with our managing general partner, our Intermediate Partnership, AHGP and its general partner AGP, and Alliance Resource Holdings II, Inc. (“ARH II”), the indirect parent of SGP. The Administrative Services Agreement superseded the administrative services agreement signed in connection with the AHGP IPO in 2006. 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 $0.3 million, $0.4 million and $0.4 million for the years ended December 31, 2010, 2009 and 2008, respectively, from AHGP and $0.2 million, $0.5 million and $0.5 million from ARH II for the years ended December 31, 2010, 2009 and 2008, respectively.

 

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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 $1.3 million, $1.1 million and $0.3 million for the years ended December 31, 2010, 2009 and 2008, respectively. The increase from 2008 to 2009 was primarily attributable 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.

Managing General Partner Contribution

During 2008, an affiliated entity controlled by Joseph W. Craft III, contributed 25,898 AHGP common units, valued at approximately $0.6 million at the time of contribution and $0.8 million of cash to AHGP for the purpose of funding certain expenses associated with our employee compensation programs. Upon AHGP’s receipt of this contribution it immediately contributed the same to its subsidiary MGP, our managing general partner, which in turn contributed the same to our subsidiary Alliance Coal. Concurrent with this contribution, Alliance Coal distributed the 25,898 AHGP common units to certain employees and recognized compensation expense of $1.4 million for the year ended December 31, 2008. 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.

Mid-America Carbonates

In September 2007, MAC entered into a $1.5 million Revolving Credit Agreement (“Revolver”) with ARLP. 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 expired on December 31, 2010. At December 31, 2010, MAC owed ARLP $1.6 million under the Revolver, which is classified as Due from Affiliates on our consolidated balance sheets. MAC repaid the amount due under the Revolver in January 2011.

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 $0.8 million, $0.7 million and $0.7 million for the years ended December 31, 2010, 2009 and 2008, respectively, 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, 2010 and 2009.

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, 2010, 2009 and 2008, respectively. As of December 31, 2010, $2.1 million of advance minimum royalties paid under the lease is available for recoupment, and management expects that it will be recouped against future production.

SGP

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

 

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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, 2010, 2009 and 2008. As of December 31, 2010, $17.9 million of advance minimum royalties paid under the lease is available for recoupment and management expects that it will be recouped against future production. In August 2010, the lease was amended to include approximately 34.4 million additional clean tons of recoverable coal reserves in the proven and probable categories.

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, 2010, 2009 and 2008, 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. Pursuant to the lease, we made monthly payments of approximately $0.2 million through January 2011. Lease expense incurred for each of the years ended December 31, 2010, 2009 and 2008 was $2.6 million, respectively. Effective February 1, 2011, the lease was amended to extend the term through January 2017 and modify other terms, including reducing the monthly payments to approximately $50,000.

We have agreements with two banks to provide letters of credit in an aggregate amount of $31.1 million. At December 31, 2010, we had $30.7 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 and does not impact our consolidated financial statements.

Accruals of Other Liabilities

We had accruals for other liabilities, including current obligations, totaling $196.9 million and $170.3 million at December 31, 2010 and 2009. These accruals were chiefly comprised of workers’ compensation benefits, black lung benefits, and costs associated with asset retirement obligations. These obligations are self-insured except for certain excess insurance coverage for workers’ compensation. 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 Benefits.”

Pension Plan

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

Our pension expense was $2.2 million, $4.6 million and $1.9 million for the years ended December 31, 2010, 2009 and 2008. 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 5.88% and 6.15% for the years ended December 31, 2010 and 2009, respectively. The actual return on plan assets was 10.4% and 23.7% for the years ended December 31, 2010 and 2009, 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, 2010, our expected long-term rate of return assumption was 8.35% determined by the above factors and based on an asset allocation assumption of 60.0% invested in domestic equity securities, with an expected long-term rate of return of 8.46%, 20.0% invested in international equities with an expected long-term rate of return of 8.85% and 20.0% invested in fixed income securities, with an expected long-term rate of return of 4.88%. 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

 

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primary benchmark for establishing the discount rate. At December 31, 2010, 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 5.88% at December 31, 2009 to 5.56% at December 31, 2010.

As of December 31, 2010, our Pension Plan was underfunded by approximately $13.3 million. We estimate that our Pension Plan expense and cash contributions will be approximately $2.2 million and $5.0 million, respectively, in 2011. 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, 2009 would have increased our pension expense for the year ended December 31, 2010 by approximately $0.4 million. Lowering the discount rate assumption by 0.5% (from 5.88% to 5.38%) at December 31, 2009 would have increased our pension expense for the year ended December 31, 2010 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 December 2009, the FASB issued Accounting Standards Update (“ASU”) 2009-17, Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities (“ASU 2009-17”). ASU 2009-17 codified Statement of Financial Accounting Standards (“SFAS”) No. 167, Amendments to FASB Interpretation No. 46(R)), which changed the consolidation guidance applicable to a variable interest entity (“VIE”). ASU 2009-17 updated the guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate such VIE, by requiring a qualitative analysis rather than a quantitative analysis. The qualitative analysis includes, among other things, consideration of whether the enterprise has the power to direct the activities of the entity that most significantly impact the entity’s economic performance and has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. ASU 2009-17 also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE. Previously, FASB ASC 810, Consolidation, 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, are now subject to the provisions of ASU 2009-17. In addition, ASU 2009-17 also requires enhanced disclosures about an enterprise’s involvement with a VIE. The provisions of ASU 2009-17 were effective as of the beginning of interim and annual reporting periods that began after November 15, 2009. Based on our evaluation of ASU 2009-17, we deconsolidated MAC upon adoption, effective January 1, 2010. The deconsolidation of MAC did not have a material impact on our consolidated financial statements.

In January 2010, the FASB issued ASU 2010-06, Improving Disclosures About Fair Value Measurements (“ASU 2010-06”). ASU 2010-06 amended guidance on certain aspects of FASB ASC 820, Fair Value Measurements and Disclosures, to add new requirements for disclosures of transfers into and out of Level 1 and 2 measurements and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements, all on a gross basis. ASU 2010-06 also clarifies existing fair value disclosures regarding the level of disaggregation and the inputs and valuation techniques used to measure fair value. The provisions of ASU 2010-06 were effective for the first reporting period beginning after December 15, 2009, except for the requirement to provide Level 3 activity of purchases, sales, issuances, and settlements on a gross basis, which will be effective for fiscal years beginning after December 15, 2010. The adoption of ASU 2010-06 did not have an impact on our consolidated financial statements.

New Accounting Standards Issued and Not Yet Adopted

In December 2010, the FASB issued ASU 2010-29, Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations (“ASU 2010-29”). ASU 2010-29 amended ASC 805,

 

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Business Combinations, to specify that if a public entity presents comparative financial statements and a business combination has occurred during the current reporting period, then the public entity should disclose revenues and earnings of the combined entity as though the business combination that occurred during the current year had occurred at the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures under ASC 805 to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenues and earnings. The adoption of the ASU 2010-29 amendments are effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. We do not anticipate the adoption of ASU 2010-29 on January 1, 2011 to have a material impact on our consolidated financial statements.

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

We have significant long-term coal supply agreements as evidenced by approximately 92.4% of our sales tonnage, including approximately 94.5% of our medium- and high-sulfur coal sales tonnage, being sold under long-term contracts. 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.” As of January 28, 2011, our nominal commitment under long-term contracts was approximately 31.1 million tons in 2011, 27.3 million tons in 2012, 24.1 million tons in 2013 and 19.0 million tons in 2014.

We have exposure to price risk for supplies that are used directly or indirectly in the normal course of coal production such as diesel fuel, steel, explosives and other supplies. We manage our risk for these items through strategic sourcing contracts for normal quantities required by our operations. We do not utilize any commodity price-hedges or other derivatives related to these risks.

Credit Risk

In 2010, approximately 91.5% of our sales tonnage was consumed by electric utilities. Therefore, our credit risk is primarily with domestic electric power generators. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor outstanding accounts receivable against established credit limits. When deemed appropriate by our credit management department, we will take steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps may include obtaining letters of credit or cash collateral, requiring prepayments for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay.

Exchange Rate Risk

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 £10.2 million to this foreign supplier through December 31, 2010, thus fulfilling our obligation.

Interest Rate Risk

Borrowings under the ARLP Credit Facility and Term Loan Agreement 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 do not utilize any interest rate derivative instruments related to our outstanding debt. We had no borrowings under the ARLP Credit Facility and $300.0 million outstanding under Term Loan Agreement at December 31, 2010. A one percentage point increase in the interest rates related to the Term Loan Agreement would result in an annualized increase in 2011 interest expense of $3.0 million, based on borrowing levels at December 31, 2010. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $20.1 million in the estimated fair value of these borrowings.

 

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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, 2010 and 2009. The carrying amounts and fair values of financial instruments are as follows (in thousands):

 

Expected Maturity Dates

as of December 31, 2010

  2011     2012     2013     2014     2015     Thereafter     Total     Fair Value
December 31,
2010
 

Fixed rate debt

  $ 18,000      $ 18,000      $ 18,000      $ 18,000      $ 205,000      $ 145,000      $ 422,000      $ 509,483   

Weighted average interest rate

    6.75     6.68     6.61     6.52     6.54     6.72    

Variable rate debt

  $ —        $ —        $ 60,000      $ 75,000      $ 165,000      $ —        $ 300,000      $ 300,000   

Weighted average interest rate (1)

    2.30     2.30     2.30     2.30     2.30      

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    

 

(1) Interest rate on variable rate debt equal to the rate elected by us at December 31, 2010, held constant for the remaining term of the outstanding borrowing.

 

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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, 2010 and 2009, and the related consolidated statements of income, cash flows, and Partners’ capital for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2010, 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 28, 2011 expressed an unqualified opinion on the Partnership’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Tulsa, Oklahoma

February 28, 2011

 

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2010 AND 2009

(In thousands, except unit data)

 

 

     December 31,  
     2010     2009  

ASSETS

    

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 339,562      $ 21,556   

Trade receivables

     112,942        91,223   

Other receivables

     2,537        3,159   

Due from affiliates

     1,912        83   

Inventories

     31,548        64,357   

Advance royalties

     4,812        3,629   

Prepaid expenses and other assets

     10,024        8,801   
                

Total current assets

     503,337        192,808   

PROPERTY, PLANT AND EQUIPMENT:

    

Property, plant and equipment, at cost

     1,598,130        1,378,914   

Less accumulated depreciation, depletion and amortization

     (648,883     (556,370
                

Total property, plant and equipment, net

     949,247        822,544   

OTHER ASSETS:

    

Advance royalties

     27,439        26,802   

Other long-term assets

     21,255        9,246   
                

Total other assets

     48,694        36,048   
                

TOTAL ASSETS

   $ 1,501,278      $ 1,051,400   
                

LIABILITIES AND PARTNERS’ CAPITAL

    

CURRENT LIABILITIES:

    

Accounts payable

   $ 63,339      $ 62,821   

Due to affiliates

     573        27   

Accrued taxes other than income taxes

     13,901        10,777   

Accrued payroll and related expenses

     30,773        22,101   

Accrued interest

     2,491        2,918   

Workers’ compensation and pneumoconiosis benefits

     8,518        9,886   

Current capital lease obligation

     295        324   

Other current liabilities

     16,715        11,062   

Current maturities, long-term debt

     18,000        18,000   
                

Total current liabilities

     154,605        137,916   

LONG-TERM LIABILITIES:

    

Long-term debt, excluding current maturities

     704,000        422,000   

Pneumoconiosis benefits

     45,039        34,344   

Accrued pension benefit

     13,296        19,696   

Workers’ compensation

     59,796        53,845   

Asset retirement obligations

     56,045        53,116   

Due to affiliates

     1,954        1,148   

Long-term capital lease obligation

     165        460   

Other liabilities

     10,595        7,895   
                

Total long-term liabilities

     890,890        592,504   
                

Total liabilities

     1,045,495        730,420   
                

COMMITMENTS AND CONTINGENCIES

    

PARTNERS’ CAPITAL:

    

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

    

Limited Partners - Common Unitholders 36,716,855 and 36,661,029 units outstanding, respectively

     761,875        630,165   

General Partners’ deficit

     (287,371     (293,153

Accumulated other comprehensive loss

     (18,721     (17,149
                

Total ARLP Partners’ Capital

     455,783        319,863   

Noncontrolling interest

     —          1,117   
                

Total Partners’ Capital

     455,783        320,980   
                

TOTAL LIABILITIES AND PARTNERS’ CAPITAL

   $ 1,501,278      $ 1,051,400   
                

See notes to consolidated financial statements.

 

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

(In thousands, except unit and per unit data)

 

 

     Year Ended December 31,  
     2010     2009     2008  

SALES AND OPERATING REVENUES:

      

Coal sales

   $ 1,551,539      $ 1,163,871      $ 1,093,059   

Transportation revenues

     33,584        45,733        44,755   

Other sales and operating revenues

     24,942        21,427        18,735   
                        

Total revenues

     1,610,065        1,231,031        1,156,549   
                        

EXPENSES:

      

Operating expenses (excluding depreciation, depletion and amortization)

     1,009,935        797,527        801,854   

Transportation expenses

     33,584        45,733        44,755   

Outside coal purchases

     17,078        7,524        23,776   

General and administrative

     50,818        41,117        37,176   

Depreciation, depletion and amortization

     146,881        117,524        105,278   

Gain from sale of coal reserves

     —          —          (5,159

Net gain from insurance settlement and other

     —          —          (2,790
                        

Total operating expenses

     1,258,296        1,009,425        1,004,890   
                        

INCOME FROM OPERATIONS

     351,769        221,606        151,659   

Interest expense (net of interest capitalized of $888, $1,291 and $808, respectively)

     (30,062     (30,847     (22,145

Interest income

     200        1,049        3,727   

Other income

     851        1,247        875   
                        

INCOME BEFORE INCOME TAXES

     322,758        193,055        134,116   

INCOME TAX EXPENSE (BENEFIT)

     1,741        708        (480
                        

NET INCOME

     321,017        192,347        134,596   

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST

     —          (190     (420
                        

NET INCOME ATTRIBUTABLE TO ALLIANCE RESOURCE PARTNERS, L.P. (“NET INCOME OF ARLP”)

   $ 321,017      $ 192,157      $ 134,176   
                        

GENERAL PARTNERS’ INTEREST IN NET INCOME OF ARLP

   $ 73,172      $ 60,639      $ 45,697   
                        

LIMITED PARTNERS’ INTEREST IN NET INCOME OF ARLP

   $ 247,845      $ 131,518      $ 88,479   
                        

BASIC NET INCOME OF ARLP PER LIMITED PARTNER UNIT

   $ 6.68      $ 3.56      $ 2.39   
                        

DILUTED NET INCOME OF ARLP PER LIMITED PARTNER UNIT

   $ 6.68      $ 3.56      $ 2.39   
                        

DISTRIBUTIONS PAID PER LIMITED PARTNER UNIT

   $ 3.205      $ 2.95      $ 2.53   
                        

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING–BASIC

     36,710,431        36,655,555        36,604,707   
                        

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING–DILUTED

     36,710,431        36,655,555        36,604,707   
                        

See notes to consolidated financial statements.

 

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

(In thousands)

 

 

     Year Ended December 31,  
     2010     2009     2008  

CASH FLOWS FROM OPERATING ACTIVITIES:

      

Net income

   $ 321,017      $ 192,347      $ 134,596   

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depreciation, depletion and amortization

     146,881        117,524        105,278   

Non-cash compensation expense

     4,051        3,582        3,931   

Asset retirement obligations

     2,579        2,678        2,827   

Coal inventory adjustment to market

     498        3,030        452   

Loss on retirement of vertical hoist conveyor system

     1,204        —          —     

Net (gain) loss on foreign currency transaction

     274        (653     —     

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

     234        136        (911

Gain from sale of coal reserves

     —          —          (5,159

Other

     1,448        537        366   

Changes in operating assets and liabilities:

      

Trade receivables

     (21,780     (3,301     4,745   

Other receivables

     (689     2,838        (1,711

Inventories

     31,412        (40,917     (960

Prepaid expenses and other assets

     (1,223     1,269        (971

Advance royalties

     (1,820     (3,403     (4,244

Accounts payable

     8,055        (6,142     5,617   

Due to affiliates

     1,062        (34     (1,373

Accrued taxes other than income taxes

     3,124        (418     104   

Accrued payroll and related benefits

     8,670        1,546        5,375   

Pneumoconiosis benefits

     3,647        2,908        2,044   

Workers’ compensation

     4,583        6,526        4,931   

Other

     7,361        2,688        6,104   
                        

Total net adjustments

     199,571        90,394        126,445   
                        

Net cash provided by operating activities

     520,588        282,741        261,041   
                        

CASH FLOWS FROM INVESTING ACTIVITIES:

      

Property, plant and equipment:

      

Capital expenditures

     (289,874     (328,162     (176,482

Changes in accounts payable and accrued liabilities

     (7,480     5,727        10,046   

Proceeds from sale of property, plant and equipment

     381        8        2,708   

Proceeds from sale of coal reserves

     —          —          7,159   

Purchase of marketable securities

     —          (4,527     —     

Proceeds from marketable securities

     —          4,527        —     

Payment for acquisition of coal reserves and other assets

     —          —          (29,800

Receipts on prior advances on Gibson rail project

     1,982        2,295        2,244   
                        

Net cash used in investing activities

     (294,991     (320,132     (184,125
                        

CASH FLOWS FROM FINANCING ACTIVITIES:

      

Proceeds from issuance of long-term debt

     —          —          350,000   

Payments on long-term debt

     (18,000     (18,000     (18,000

Borrowings under term loan

     300,000        —          —     

Borrowings under revolving credit facilities

     95,000        —          88,850   

Payments under revolving credit facilities

     (95,000     —          (116,850

Payments on capital lease obligation

     (324     (351     (377

Payment of debt issuance costs

     (1,417     (339     (1,721

Net settlement of employee withholding taxes on vesting of Long-Term Incentive Plan

     (1,265     (791     —     

Cash contributions by General Partners

     43        31        866   

Distributions paid to Partners

     (186,354     (167,131     (135,927
                        

Net cash provided by (used in) financing activities

     92,683        (186,581     166,841   
                        

EFFECT OF CURRENCY TRANSLATION ON CASH

     (274     653        —     

NET CHANGE IN CASH AND CASH EQUIVALENTS

     318,006        (223,319     243,757   

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

     21,556        244,875        1,118   
                        

CASH AND CASH EQUIVALENTS AT END OF PERIOD

   $ 339,562      $ 21,556      $ 244,875   
                        

See notes to consolidated financial statements, including Note 15 for supplemental cash flow information.

 

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

(In thousands, except unit data)

 

 

    Number of
Limited
Partner
Units
    Limited
Partners’
Capital
    General
Partners’
Capital
(Deficit)
    Accumulated
Other
Comprehensive
Income (Loss)
    Noncontrolling
Interest
    Total
Partners’
Capital
 

Balance at January 1, 2008

    36,550,659      $ 607,777      $ (290,669   $ 109      $ 507      $ 317,724   

Comprehensive income:

           

Net income

    —          88,479        45,697        —          420        134,596   

Actuarially determined long-term liability adjustments

    —          —          —          (20,008     —          (20,008
                 

Total comprehensive income

              114,588   

Issuance of units to Long-Term Incentive Plan participants upon vesting

    62,799        (1,181     —          —          —          (1,181

Common unit–based compensation under Long-Term Incentive Plan

    —          3,311        —          —          —          3,311   

Common control acquisition (Note 3)

    —          —          (9,809     —          —          (9,809

General Partners contribution

    —          —          1,486        —          —          1,486   

Distributions on common unit-based compensation

    —          (793     —          —          —          (793

Distributions to Partners

    —          (92,595     (42,539     —          —          (135,134
                                               

Balance at December 31, 2008

    36,613,458        604,998        (295,834     (19,899     927        290,192   

Comprehensive income:

           

Net income

    —          131,518        60,639        —          190        192,347   

Actuarially determined long-term liability adjustments

    —          —          —          2,750        —          2,750   
                 

Total comprehensive income

              195,097   

Issuance of units to Long-Term Incentive Plan participants upon vesting

    47,571        (791     —          —          —          (791

Common unit–based compensation under Long-Term Incentive Plan

    —          3,582        —          —          —          3,582   

General Partner contributions

    —          —          31        —          —          31   

Distributions on common unit-based compensation

    —          (1,026     —          —          —          (1,026

Distributions to Partners

    —          (108,116     (57,989     —          —          (166,105
                                               

Balance at December 31, 2009

    36,661,029        630,165        (293,153     (17,149     1,117        320,980   

Comprehensive income:

           

Net income

    —          247,845        73,172        —          —          321,017   

Actuarially determined long-term liability adjustments

    —          —          —          (1,572     —          (1,572
                 

Total comprehensive income

              319,445   

Deconsolidation of MAC (Note 18)

    —          —          —          —          (1,117     (1,117

Issuance of units to Long-Term Incentive Plan participants upon vesting

    55,826        (1,265     —          —          —          (1,265

Common unit–based compensation under Long-Term Incentive Plan

    —          4,051        —          —          —          4,051   

General Partner contributions

    —          —          43        —          —          43   

Distributions on common unit-based compensation

    —          (1,286     —          —          —          (1,286

Distributions to Partners

    —          (117,635     (67,433     —          —          (185,068
                                               

Balance at December 31, 2010

    36,716,855      $ 761,875      $ (287,371   $ (18,721   $ —        $ 455,783   
                                               

See notes to consolidated financial statements.

 

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

 

 

1. ORGANIZATION AND PRESENTATION

Significant Relationships Referenced in Notes to Consolidated Financial Statements

 

   

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.

Organization

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

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

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

 

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The accompanying consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of December 31, 2010 and 2009, and results of our operations, cash flows and changes in partners’ capital for each of the three years in the period ended December 31, 2010. All of our intercompany transactions and accounts have been eliminated.

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

EstimatesThe preparation of consolidated financial statements in conformity with generally accepted accounting principles (“GAAP”) of the United States (“U.S.”) requires management to make estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements. Actual results could differ from those estimates.

Fair Value of Financial InstrumentsThe carrying amounts for accounts receivable, marketable securities, and accounts payable approximate fair value because of the short maturity of those instruments. At December 31, 2010 and 2009, the estimated fair value of long-term debt, including current maturities, was approximately $809.5 million and $460.7 million, respectively (Note 9).

Cash and Cash EquivalentsCash and cash equivalents include cash on hand and on deposit, including highly liquid investments with maturities of three months or less. We had no restricted cash and cash equivalents at December 31, 2010 and 2009.

Cash ManagementThe cash flows from operating activities section of our Consolidated Statements of Cash Flows reflect an adjustment for $10 million representing book overdrafts at December 31, 2008. We had no book overdrafts at December 31, 2010 and 2009, respectively.

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

Property, Plant and EquipmentExpenditures which extend the useful lives of existing plant and equipment assets are capitalized. Maintenance and repairs that do not extend the useful life or increase productivity of the asset are charged to operating expense as incurred. Exploration expenditures are charged to operating expense as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves. Depreciation and amortization are computed principally on the straight-line method based upon the estimated useful lives of the assets or the estimated life of each mine, whichever is less, ranging from 1 to 23 years. Depreciable lives for mining equipment and processing facilities range from 1 to 23 years. Depreciable lives for land and depletable lives for mineral rights range from 2 to 23 years. Depreciable lives for buildings, office equipment and improvements range from 2 to 23 years. Gains or losses arising from retirements are included in current operations. Depletion of mineral rights is provided on the basis of tonnage mined in relation to estimated recoverable tonnage which equals estimated proven and probable reserves. Therefore, our mineral rights are depleted based on only proven and probable reserves derived in accordance with Industry Guide 7. At December 31, 2010 and 2009, land and mineral rights include $33.0 million and $22.5 million, respectively, representing the carrying value of coal reserves attributable to properties where we are not currently engaged in mining operations or leasing to third-parties, and therefore, the coal reserves are not currently being depleted. We believe that the carrying value of these reserves will be recovered.

Mine Development CostsMine 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. 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, 2010 and 2009, mine development costs include $35.3 million and $16.4 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.

 

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

Intangible Assets—Costs allocated to contracts with covenants not to compete (“Non-Compete Agreements”) are amortized on a straight-line basis over the life of the Non-Compete Agreements. Amortization expense associated with Non-Compete Agreements was $1.1 million, $0.5 million and $0.5 million for the years ending December 31, 2010, 2009 and 2008, respectively. Our Non-Compete Agreements are included in other long-term assets on our consolidated balance sheets at December 31, 2010 and 2009. Our Non-Compete Agreements at December 31, are summarized as follows (in thousands):

 

     2010     2009  

Non-Compete Agreements, original cost

   $ 13,689      $ 4,153   

Accumulated amortization

     (2,419     (1,330
                

Non-Compete Agreements, net

   $ 11,270      $ 2,823   
                

Amortization expense related to Non-Compete Agreements is estimated to be $1.3 million per year in 2011-2015.

Advance RoyaltiesRights to coal mineral leases are often acquired and/or maintained through advance royalty payments. Where royalty payments represent prepayments recoupable against future production, they are recorded as an asset, with amounts expected to be recouped within one year classified as a current asset. As mining occurs on these leases, the royalty prepayments are charged to operating expenses. We assess the recoverability of royalty prepayments based on estimated future production. Royalty prepayments estimated to be nonrecoverable are expensed. Our advance royalties at December 31, are summarized as follows (in thousands):

 

     2010      2009  

Advance royalties, affiliates (Note 19)

   $ 19,955       $ 16,811   

Advance royalties, third-parties

     12,296         13,620   
                 

Total advance royalties

   $ 32,251       $ 30,431   
                 

Asset Retirement ObligationsWe record a liability for the estimated cost of future mine asset retirement and closing procedures on a present value basis when incurred and a corresponding amount is capitalized by increasing the carrying amount of the related long-lived asset. Those costs relate to permanently sealing portals at underground mines and to reclaiming the final pits and support acreage at surface mines. Examples of these types of costs, common to both types of mining, include, but are not limited to, removing or covering refuse piles and settling ponds, water treatment obligations, and dismantling preparation plants, other facilities and roadway infrastructure. Amortization of the related asset is recorded on a units of production method generally based upon the estimated life of the mine (Note 16).

WorkersCompensation and Pneumoconiosis (Black Lung) BenefitsWe are generally self-insured for workers’ compensation benefits, including black lung benefits. We accrue a workers’ compensation liability for the estimated present value of workers’ compensation and black lung benefits based on our actuarial determined calculations (Note 17).

Income Taxes—We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities accrues to the unitholders. Although publicly-traded partnerships as a general rule will be taxed as corporations, we qualify for an exemption because at least 90% of our income consists of qualifying income, as defined in Section 7704(c) of the Internal Revenue Code. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. Individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in our consolidated financial statements. Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each

 

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unitholder’s tax attributes in our partnership is not available to us. Our subsidiary, Alliance Service, is subject to federal and state income taxes. Our tax counsel has provided an opinion that ARLP, the Intermediate Partnership and Alliance Coal will each be treated as a partnership. However, as is customary, no ruling has been or will be requested from the Internal Revenue Service (“IRS”) regarding our classification as a partnership for federal income tax purposes.

Revenue Recognition—Revenues from coal sales are recognized when title passes to the customer as the coal is shipped. Some coal supply agreements provide for price adjustments based on variations in quality characteristics of the coal shipped. In certain cases, a customer’s analysis of the coal quality is binding and the results of the analysis are received on a delayed basis. In these cases, we estimate the amount of the quality adjustment and adjust the estimate to actual when the information is provided by the customer. Historically such adjustments have not been material. Non-coal sales revenues primarily consist of transloading fees, administrative service revenues from our affiliates, mine safety services and products, rock dust sales (in 2009 and 2008 only) and other handling and service fees. Transportation revenues are recognized in connection with us incurring the corresponding costs of transporting coal to customers through third-party carriers for which we are directly reimbursed through customer billings. We had no allowance for doubtful accounts for trade receivables at December 31, 2010 and 2009, respectively.

Pension BenefitsOur defined benefit pension obligation and the related benefit cost are accounted for in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 715, Compensation-Retirement Benefits. Pension cost and obligations are actuarially determined and are affected by assumptions including expected return on plan assets, discount rates, compensation increases, employee turnover rates and health care cost trend rates. We evaluate our assumptions periodically and make adjustments to these assumptions and the recorded liability as necessary (Note 13).

Common Unit-Based CompensationWe account for compensation expense attributable to non-vested restricted common units granted under the Long-Term Incentive Plan (“LTIP”) based on requirements of FASB ASC 718, Compensation-Stock Compensation. Accordingly, the fair value of award grants are determined on the grant date of the award and this value is recognized as compensation expense on a pro-rata basis, as appropriate over the requisite service period, and the corresponding liability is classified as equity and included in Limited Partners Capital in the consolidated financial statements (Note 14).

Net Income Per UnitBasic net income per limited partner unit is determined by dividing Net Income of ARLP available to Limited Partners by the weighted average number of outstanding common units. Diluted net income per unit is based on the combined weighted average number of common units and common unit equivalents outstanding (Note 12).

New Accounting Standards Issued and Adopted—In December 2009, the FASB issued Accounting Standards Update (“ASU”) 2009-17, Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities (“ASU 2009-17”). ASU 2009-17 codified Statement of Financial Accounting Standards No. 167, Amendments to FASB Interpretation No. 46(R)), which changed the consolidation guidance applicable to a variable interest entity (“VIE”). ASU 2009-17 updated the guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate such VIE, by requiring a qualitative analysis rather than a quantitative analysis. The qualitative analysis includes, among other things, consideration of whether the enterprise has the power to direct the activities of the entity that most significantly impact the entity’s economic performance and has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. ASU 2009-17 also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE. Previously, FASB ASC 810, Consolidation, 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, are now subject to the provisions of ASU 2009-17. In addition, ASU 2009-17 also requires enhanced disclosures about an enterprise’s involvement with a VIE. The provisions of ASU 2009-17 were effective as of the beginning of interim and annual reporting periods that began after November 15, 2009. Based on our evaluation of ASU 2009-17, we deconsolidated Mid-America Carbonates, LLC (“MAC”) upon adoption, effective January 1, 2010 (Note 18). The deconsolidation of MAC did not have a material impact on our consolidated financial statements.

In January 2010, the FASB issued ASU 2010-06, Improving Disclosures About Fair Value Measurements (“ASU 2010-06”). ASU 2010-06 amended guidance on certain aspects of FASB ASC 820, Fair Value Measurements and Disclosures, to add new requirements for disclosures of transfers into and out of Level 1 and 2 measurements and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements, all on a gross

 

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basis. ASU 2010-06 also clarifies existing fair value disclosures regarding the level of disaggregation and the inputs and valuation techniques used to measure fair value. The provisions of ASU 2010-06 were effective for the first reporting period beginning after December 15, 2009, except for the requirement to provide Level 3 activity of purchases, sales, issuances, and settlements on a gross basis, which will be effective for fiscal years beginning after December 15, 2010. The adoption of ASU 2010-06 did not have an impact on our consolidated financial statements.

New Accounting Standards Issued and Not Yet AdoptedIn December 2010, the FASB issued ASU 2010-29, Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations (“ASU 2010-29”). ASU 2010-29 amended ASC 805, Business Combinations, to specify that if a public entity presents comparative financial statements and a business combination has occurred during the current reporting period, then the public entity should disclose revenues and earnings of the combined entity as though the business combination that occurred during the current year had occurred at the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures under ASC 805 to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenues and earnings. The adoption of the ASU 2010-29 amendments are effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. We do not anticipate the adoption of ASU 2010-29 on January 1, 2011 to have a material impact on our consolidated financial statements.

 

3. ACQUISITIONS

SGP Land Acquisition

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, LLC (“SGP Land”). SGP Land is a subsidiary of our special general partner and is indirectly owned by Mr. Craft. Because the acquisition was between entities under common control, it was accounted for at historical cost. 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 mineral leases and sublease agreements, pursuant to which we had paid advance royalties of approximately $8.0 million that had not yet been recouped against production royalties. 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 paid to the base lessors, were eliminated upon consolidation of the Partnership’s financial statements. The purchase price of $13.3 million cash paid at closing was primarily attributable to the historical cost basis of the mineral rights included in property, plant and equipment. We financed this acquisition using a combination of existing cash on hand and borrowings under our revolving credit facility.

The SGP Land transaction was a related-party transaction and, as such, was reviewed by the board of directors of our managing general partner (“Board of Directors”) and its conflicts committee (“Conflicts Committee”). Based upon the review, the Conflicts Committee determined that the transaction reflected market-clearing terms and conditions customary in the coal industry. As a result, the Board of Directors and its Conflicts Committee approved the SGP Land transaction as fair and reasonable to us and our limited partners. Because the SGP Land acquisition was between entities under common control, it was accounted for at historical cost.

 

4. PATTIKI VERTICAL HOIST CONVEYOR SYSTEM FAILURE

On May 13, 2010, White County Coal’s Pattiki mine was temporarily idled following the failure of the vertical hoist conveyor system used in conveying raw coal out of the mine. Our operating expenses for the twelve months ended December 31, 2010 include $1.2 million for retirement of certain assets related to the failed vertical hoist conveyor system in addition to other repair and clean-up expenses that were not significant on a consolidated or segment basis. We reviewed our commercial property (including business interruption) insurance policies and, as the loss on the vertical hoist conveyor system did not exceed our deductible for property damage, we do not expect any recovery under such policies.

While the Pattiki mine was temporarily idled, we expanded coal production at our other coal mines in the region, including the addition of the seventh and eighth production units at the River View mine, to partially offset the loss of production from the Pattiki mine. Consequently, the temporary idling of the Pattiki mine did not have a material adverse

 

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impact on our results of operations and cash flows. On July 19, 2010, the Pattiki mine resumed limited production while White County Coal continued to assess the effectiveness and reliability of the repaired vertical hoist conveyor system. On January 3, 2011, the Pattiki mine returned to full production capacity.

 

5. INVENTORIES

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

 

     2010      2009  

Coal

   $ 11,897       $ 45,504   

Supplies (net of reserve for obsolescence of $2,244 and $1,372, respectively)

     19,651         18,853   
                 

Total inventory

   $ 31,548       $ 64,357   
                 

 

6. PROPERTY, PLANT AND EQUIPMENT

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

 

     2010     2009  

Mining equipment and processing facilities

   $ 1,056,670      $ 890,582   

Land and mineral rights

     140,432        117,380   

Buildings, office equipment and improvements

     155,621        136,713   

Construction in progress

     76,766        94,901   

Mine development costs

     168,641        139,338   
                

Property, plant and equipment, at cost

     1,598,130        1,378,914   

Less accumulated depreciation, depletion and amortization

     (648,883     (556,370
                

Total property, plant and equipment, net

   $ 949,247      $ 822,544   
                

Equipment leased by us under lease agreements which are determined to be capital leases are stated at an amount equal to the present value of the minimum lease payments during the lease term, less accumulated amortization. Equipment under capital leases totaling $1.9 million included in mining equipment and processing facilities is amortized on the straight-line method over the shorter of its useful life or the related lease term. The provision for amortization of leased properties is included in depreciation, depletion and amortization expense. Accumulated amortization related to our capital lease was $1.1 million and $0.8 million as of December 31, 2010 and 2009, respectively, and amortization expense was $0.3 million, $0.2 million and $0.3 million for the years ended December 31, 2010, 2009 and 2008, respectively.

 

7. GIBSON RAIL ADVANCES

In 2007, our subsidiary, Gibson County Coal entered into contracts with CSX Transportation, Inc. (“CSX”) and Norfolk Southern Railway Company (“NS”), pursuant to which Gibson County Coal constructed a rail loop and the railroads constructed connections and siding facilities, in order to provide Gibson County Coal access to CSX and NS railways. Although these connections and siding facilities are assets of the respective rail companies, Gibson County Coal advanced $8.2 million on a combined basis to CSX and NS during 2007 toward the cost of construction of their infrastructure. In 2010, 2009 and 2008, advances of $2.0 million, $2.3 million and $2.2 million, respectively, were repaid to Gibson County Coal by rebates from CSX and NS as coal was shipped on their respective railways. The $1.7 million and $3.7 million of advances not yet repaid as of December 31, 2010 and 2009, respectively, are recorded in other receivables and other long-term assets in our consolidated balance sheet. Gibson County Coal also received additional rebates from both CSX and NS that were not recoupment of advances.

 

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8. LONG-TERM DEBT

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

 

     2010     2009  

Credit facility

   $ —        $ —     

Senior notes

     72,000        90,000   

Series A senior notes

     205,000        205,000   

Series B senior notes

     145,000        145,000   

Term loan

     300,000        —     
                
     722,000        440,000   

Less current maturities

     (18,000     (18,000
                

Total long-term debt

   $ 704,000      $ 422,000   
                

Credit Facility. Our Intermediate Partnership entered into a $150.0 million revolving credit facility (“ARLP Credit Facility”) dated September 25, 2007, which matures in 2012. The ARLP Credit Facility was decreased to $142.5 million of availability on October 6, 2010 due to a defaulting lender, as discussed below. 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, before carry forward considerations and exclusion of capital expenditures related to acquisitions, are $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 2011 is approximately $531.9 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, 2010, we had $11.6 million of letters of credit outstanding with $130.9 million available for borrowing under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility as of December 31, 2010 and 2009. We utilize the ARLP Credit Facility, as appropriate, to meet working capital requirements, anticipated capital expenditures, scheduled debt payments or distribution payments. We incur an annual commitment fee of 0.25% on the undrawn portion of the ARLP Credit Facility.

Lehman Commercial Paper, Inc. (“Lehman”), a subsidiary of Lehman Brothers Holding, Inc., held a 5%, or $7.5 million, commitment in the original $150 million ARLP Credit Facility. Lehman filed for protection under Chapter 11 of the Federal Bankruptcy Code in early October 2008. On February 11, 2010, the ARLP Partnership gave its lenders a notice of borrowing under the ARLP Credit Facility and, in response to that notice, Lehman notified the ARLP Partnership 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 on October 6, 2010, was removed as a commitment holder under the ARLP Credit Facility. Consequently, availability for borrowing under the ARLP Credit Facility was reduced by $7.5 million on October 6, 2010. The ARLP Credit Facility is underwritten by a syndicate of eleven financial institutions (excluding Lehman) with no individual institution representing more than 11.9% of the $142.5 million revolving credit facility. In the event any other financial institution in the ARLP Partnership’s syndicate does not fund its future borrowing requests, the ARLP Partnership’s borrowing available under the ARLP Credit Facility would be reduced. The obligations of the lenders under the ARLP Credit Facility are individual obligations and the failure of one or more lenders does not relieve the remaining lenders of their funding obligations.

 

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Senior Notes. Our Intermediate Partnership has $72.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in four 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.

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.

Term Loan. On December 29, 2010, our Intermediate Partnership entered into a Term Loan Agreement, (the “Term Loan Agreement”) with various financial institutions for a term loan (the “Loan”) in the aggregate principal amount of $300 million. The Loan bears interest at a variable rate plus an applicable margin which fluctuates depending upon whether we elect the Loan (or a portion thereof) to bear interest on the Base Rate or the Eurodollar Rate (as defined in the Term Loan Agreement). We elected the Eurodollar Rate on December 30, 2010 which, with applicable margin, was 2.3% as of January 5, 2011. Interest for the period between initial funding of the Loan on December 29, 2010 and January 5, 2011, was calculated based on the Base Rate plus the applicable margin. Interest is payable quarterly with principal due as follows: $15 million due per quarter beginning March 31, 2013 through December 31, 2013, $18.75 million due per quarter beginning March 31, 2014 through September 30, 2015 and the balance of $108.75 million due on December 31, 2015. We have the option to prepay the Loan at any time in whole or in part subject to terms and conditions described in the Term Loan Agreement. Upon a “change of control” (as defined in the Term Loan Agreement), the unpaid principal amount of the loan, all interest thereon and all other amounts payable under the Term Loan Agreement will become due and payable.

The net proceeds of the Loan will be used for the general corporate, business or working capital purposes of the Intermediate Partnership and its subsidiaries, including, without limitation, (a) for capital expenditures and acquisitions (including mineral reserve acquisitions), and (b) for cash distributions to the ARLP Partnership to be used by the ARLP Partnership for any business or corporate purpose deemed appropriate by the Partnership (or its managing general partner). We incurred debt issuance costs of approximately $1.4 million in 2010 associated with the Term Loan Agreement, $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, 2008 Senior Notes and the Term Loan Agreement (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 the following: (i) debt to cash flow ratio of not more than 3.0 to 1.0 and (ii) cash flow to interest expense ratio of not less than 4.0 to 1.0 in each case, during the four most recently ended fiscal quarters. The ARLP Credit Facility, Senior Notes and the 2008 Senior Notes limit our Intermediate Partnership’s maximum annual capital expenditures, excluding acquisitions, as described above. The Credit Amendment did not change the required debt to cash flow or cash flow to interest expense ratios. The debt to cash flow ratio and cash flow to interest expense ratio were 1.4 to 1.0 and 16.5 to 1.0, for the trailing twelve months ended December 31, 2010. Actual capital expenditures were $289.9 million for the year ended December 31, 2010. We were in compliance with the covenants of the ARLP Debt Arrangements as of December 31, 2010.

 

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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, 2010, we had $30.7 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 (Note 19).

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

 

Year Ending

December 31,

      

2011

   $ 18,000   

2012

     18,000   

2013

     78,000   

2014

     93,000   

2015

     370,000   

Thereafter

     145,000   
        
   $ 722,000   
        

 

9. FAIR VALUE MEASUREMENTS

We apply the provisions of FASB ASC 820, Fair Value Measurements and Disclosures which, among other things, defines fair value, requires enhanced disclosures about assets and liabilities carried at fair value and establishes a hierarchal disclosure framework based upon the quality of inputs used to measure fair value.

Valuation techniques are based upon observable and unobservable inputs. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our own market assumptions. These two types of inputs create the following fair value hierarchy:

 

   

Level 1—Quoted prices for identical instruments in active markets.

 

   

Level 2—Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model derived valuations whose inputs are observable or whose significant value drivers are observable.

 

   

Level 3—Instruments whose significant value drivers are unobservable.

The carrying amounts for accounts receivable and accounts payable approximate fair value because of the short maturity of those instruments. At December 31, 2010 and 2009, the estimated fair value of our fixed rate term debt, including current maturities, was approximately $809.5 million and $460.7 million, respectively, based on interest rates that we believe are currently available to us for issuance of debt with similar terms and remaining maturities (see Note 8).

 

10. DISTRIBUTIONS OF AVAILABLE CASH

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

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

 

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Under the quarterly IDR provisions of our partnership agreement, our managing general partner is entitled to receive 15% of the amount we distribute in excess of $0.275 per unit, 25% of the amount we distribute in excess of $0.3125 per unit, and 50% of the amount we distribute in excess of $0.375 per unit. For the years ended December 31, 2010, 2009 and 2008, we allocated to our managing general partner incentive distributions of $66.8 million, $58.0 million and $45.3 million, respectively. The following table summarizes the quarterly per unit distribution paid during the respective quarter:

 

     Year  
     2010      2009      2008  

First Quarter

   $ 0.775       $ 0.715       $ 0.585   

Second Quarter

   $ 0.790       $ 0.730       $ 0.585   

Third Quarter

   $ 0.810       $ 0.745       $ 0.660   

Fourth Quarter

   $ 0.830       $ 0.760       $ 0.700   

On January 28, 2011, we declared a quarterly distribution of $0.86 per unit, totaling approximately $50.6 million (which includes our managing general partner’s incentive distributions), on all our common units outstanding, which was paid on February 14, 2011, to all unitholders of record on February 7, 2011.

 

11. INCOME TAXES

Our subsidiary, Alliance Service, is subject to federal and state income taxes. Alliance Service’s income is principally due to its subsidiary, Matrix Design. Alliance Service has minor temporary differences between Matrix Design’s financial reporting basis and the tax basis of its assets and liabilities. Components of income tax expense (benefit) are as follows (in thousands):

 

     Year Ended December 31,  
     2010     2009     2008  

Current:

      

Federal

   $ 1,517      $ 620      $ (312

State

     240        118        (30
                        
     1,757        738        (342

Deferred:

      

Federal

     (14     (25     (109

State

     (2     (5     (29
                        
     (16     (30     (138
                        

Income tax expense (benefit)

   $ 1,741      $ 708      $ (480
                        

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

 

     Year Ended December 31,  
     2010     2009     2008  

Income taxes at statutory rate

   $ 112,966      $ 67,569      $ 46,940   

Less: Income taxes at statutory rate on Partnership income not subject to income taxes

     (111,345     (66,939     (47,402

Increase/(decrease) resulting from:

      

State taxes, net of federal income tax

     162        70        (6

Other

     (42     8        (12
                        

Income tax expense (benefit)

   $ 1,741      $ 708      $ (480
                        

 

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12. NET INCOME PER LIMITED PARTNER UNIT

We apply the provisions of FASB ASC 260, Earnings Per Share, which were amended on January 1, 2009 by FASB ASC 260-10-55-102 through 55-110 and FASB ASC 260-10-55-25. As required by FASB ASC 260, we apply the two-class method in calculating earnings per unit (“EPU”). Net Income of ARLP is allocated to the general partners and limited partners in accordance with their respective partnership percentages, after giving effect to any special income or expense allocations, including incentive distributions to our managing general partner, the holder of the IDR pursuant to our partnership agreement, which are declared and paid following the end of each quarter (Note 10). Under the quarterly IDR provisions of our partnership agreement, our managing general partner is entitled to receive 15% of the amount we distribute in excess of $0.275 per unit, 25% of the amount we distributed in excess of $0.3125 per unit, and 50% of the amount we distribute in excess of $0.375 per unit. Our partnership agreement contractually limits our distributions to available cash and therefore, undistributed earnings of the ARLP Partnership are not allocated to the IDR holder. In addition, our outstanding unvested awards under our LTIP contain rights to nonforfeitable distributions and are therefore considered participating securities. As such, we allocate undistributed and distributed earnings to the outstanding unvested awards in our calculation of EPU.

The following is a reconciliation of Net Income of ARLP and net income used for calculating EPU and the weighted average units used in computing EPU for the years ended December 31, 2010, 2009 and 2008, respectively (in thousands, except per unit data):

 

     Year Ended December 31,  
     2010     2009     2008  

Net Income of ARLP

   $ 321,017      $ 192,157      $ 134,176   

Adjustments:

      

General partner’s priority distributions

     (68,114     (57,955     (45,326

General partners’ 2% equity ownership

     (5,058     (2,684     (1,806

General partners’ special allocation of certain general and administrative expenses

     —          —          1,435   
                        

Limited partners’ interest in Net Income of ARLP

     247,845        131,518        88,479   

Less:

      

Distributions on LTIP awards outstanding

     (1,244     (1,002     (873

Undistributed earnings attributable to LTIP awards

     (1,282     (185     —     
                        

Net Income of ARLP available to limited partners

   $ 245,319      $ 130,331      $ 87,606   
                        

Weighted average limited partner units outstanding – Basic and Diluted (1)

     36,710        36,656        36,605   
                        

Basic and Diluted Net Income of ARLP per limited partner unit (1)

   $ 6.68      $ 3.56      $ 2.39   
                        

 

(1) Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the years ended December 31, 2010 and 2009, LTIP units of 232,042 and 176,743, respectively, were considered anti-dilutive. For the year ended December 31, 2008, LTIP, Supplemental Executive Retirement Plan (“SERP”) and Directors compensation units of 165,175 were considered anti-dilutive.

During 2008, our managing general partner made a capital contributions of $1.4 million to us to fund certain expenses associated with our employee compensation programs. A special allocation of certain general and administrative expenses equal to the amount of our managing general partner’s contribution was made to our managing general partner. Net income allocated to the limited partners was not burdened by this expense (Note 19).

 

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During 2008 and 2009, accounts under the MGP Amended and Restated Deferred Compensation Plan for Directors (“Deferred Compensation Plan”) and SERP were payable to participants in cash only. As a result, the phantom units associated with these plans were not considered in the calculation of diluted units during 2008 and 2009. Effective January 1, 2011, settlement of accounts under these plans will be only in common units of ARLP (Note 14). As a result, phantom units associated with these plans will be considered in the calculation of diluted units effective January 2011. The non-vested LTIP grants associated with the LTIP Plan continue to entitle the LTIP participants to receive ARLP common units and accordingly are included in the calculation of basic and diluted units (to the extent of EPU dilution).

 

13. EMPLOYEE BENEFIT PLANS

Defined Contribution Plans—Our eligible employees currently participate in a defined contribution profit sharing and savings plan (“PSSP”) that we sponsor. The PSSP covers substantially all regular full-time employees. PSSP participants may elect to make voluntary contributions to this plan up to a specified amount of their compensation. We make matching contributions based on a percent of an employee’s eligible compensation and also make an additional nonmatching contribution. Our contribution expense for the PSSP was approximately $13.3 million, $11.2 million and $8.0 million for the years ended December 31, 2010, 2009 and 2008, respectively. The increase from 2009 to 2010 was primarily attributable to increased headcount and higher salaries and wages included in the matching calculation. The increase from 2008 to 2009 was primarily attributable to a greater number of PSSP participants principally due to changes in the defined benefit plan (the “Pension Plan”) described below and higher salaries and wages included in the matching calculation.

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. Effective during 2008, new employees of these participating operations are no longer eligible to participate in the Pension Plan, but are eligible to participate in the PSSP that we sponsor. Additionally, certain employees participating in the Pension Plan, for some of those participating operations, had the one-time option during 2008 to remain in the Pension Plan or participate in enhanced benefit provisions under the PSSP. The impact of the amendments to the Pension Plan was not material to the 2008 consolidated financial statements.

Beginning with the year ended December 31, 2009, we adopted amendments to FASB ASC 715, Compensation—Retirement Benefits. These amendments required us to provide more detailed annual disclosures of Pension Plan assets, concentrations of risk within Pension Plan assets, and valuation techniques used to measure the fair value of Pension Plan assets.

 

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The following sets forth changes in benefit obligations and plan assets for the years ended December 31, 2010 and 2009 and the funded status of the Pension Plan reconciled with the amounts reported in our consolidated financial statements at December 31, 2010 and 2009, respectively (dollars in thousands):

 

     2010     2009  

Change in benefit obligations:

    

Benefit obligations at beginning of year

   $ 57,790      $ 49,633   

Service cost

     2,214        2,580   

Interest cost

     2,924        3,083   

Actuarial (gain) loss

     (4,625     3,369   

Benefits paid

     (1,025     (875
                

Benefit obligation at end of year

     57,278        57,790   
                

Change in plan assets:

    

Fair value of plan assets at beginning of year

     38,094        29,681   

Employer contribution

     3,159        2,150   

Actual return on plan assets

     3,754        7,138   

Benefits paid

     (1,025     (875
                

Fair value of plan assets at end of year

     43,982        38,094   
                

Funded status at the end of year

   $ (13,296   $ (19,696
                

Amounts recognized in balance sheet:

    

Non-current liability

   $ (13,296   $ (19,696
                
   $ (13,296   $ (19,696
                

Amounts recognized in accumulated other comprehensive income consists of:

    

Net actuarial loss

   $ (11,673   $ (17,149
                

Weighted-average assumptions as of December 31,

    

Discount rate

     5.56     5.88

Expected rate of return on plan assets

     8.35     8.35

Weighted-average assumptions used to determine net periodic benefit cost for the year ended December 31,

    

Discount rate

     5.88     6.15

Expected return on plan assets

     8.35     8.35

The actuarial gain component of the change in benefit obligation in 2010 was primarily attributable to an update in assumptions related to Pension Plan participant retirement age. The actuarial loss component of the change in benefit obligation in 2009 was primarily attributable to a decrease in the discount rate assumption.

The 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. The Pension Plan’s expected long-term rate of return of 8.35% is determined by the above factors and an asset allocation assumption of 60.0% invested in domestic equity securities with an expected long-term rate of return of 8.46%, 20.0% invested in international equities with an expected long-term rate of return of 8.85% and 20.0% invested in fixed income securities with an expected long-term rate of return of 4.88%. Expected long-term rate of return is based on a 20 year average annual total return for each investment group. The actual return on plan assets was 10.4% and 23.7% for the years ended December 31, 2010 and 2009, respectively.

 

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     2010     2009     2008  
           (in thousands)        

Components of net periodic benefit cost:

      

Service cost

   $ 2,214      $ 2,580      $ 2,555   

Interest cost

     2,924        3,083        2,726   

Expected return on plan assets

     (3,270     (2,518     (3,368

Amortization of net loss

     366        1,499        30   
                        

Net periodic benefit cost

   $ 2,234      $ 4,644      $ 1,943   
                        

 

     2010     2009  
     (in thousands)  

Other changes in plan assets and benefit obligation recognized in accumulated other comprehensive income:

    

Net actuarial gain

   $ (5,110   $ (1,251

Reversal of amortization item:

    

Net actuarial gain

     (366     (1,499
                

Total recognized in accumulated other comprehensive income

     (5,476     (2,750

Net periodic benefit cost

     2,234        4,644   
                

Total recognized in net periodic benefit cost and accumulated other comprehensive loss

   $ (3,242   $ 1,894   
                

Estimated future benefit payments as of December 31, 2010 are as follows (in thousands):

 

Year Ending

December 31,

      

2011

   $ 1,174   

2012

     1,378   

2013

     1,627   

2014

     1,907   

2015

     2,219   

2016-2020

     17,086   
        
   $ 25,391   
        

We expect to contribute $5.0 million to the Pension Plan in 2011. The estimated net actuarial loss for the Pension Plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost during the 2011 fiscal year is $0.5 million.

As permitted under ASC 715, Compensation—Retirement Benefits, the amortization of any prior service cost is determined using a straight-line amortization of the cost over the average remaining service period of employees expected to receive benefits under the Pension Plan.

The Compensation Committee maintains a Funding and Investment Policy Statement (“Policy Statement”) for the Pension Plan. The Policy Statement provides that the assets of the Pension Plan be invested in a prudent manner based on the stated purpose of the Pension Plan and diversified among a broad range of investments including domestic and international equity securities, domestic fixed income securities and cash equivalents. The Pension Plan allows for the utilization of options in a “collar strategy” to limit potential exposure to market fluctuations. The investment goal of the Pension Plan is to ensure that the assets provide sufficient resources to meet or exceed the benefit obligations as determined under terms and conditions of the Pension Plan. The Policy Statement provides that the Pension Plan shall be funded by employer contributions in amounts determined in accordance with generally accepted actuarial standards. The investment objectives as established by the Policy Statement are, first, to increase the value of the assets under the Pension Plan and, second, to control the level of risk or volatility of investment returns associated with Pension Plan investments.

 

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We had unfunded benefit obligations of approximately $13.3 million and $20.0 million at December 31, 2010 and 2009. In general, increases in benefit obligations will be offset by employer contributions and market returns. However, general market conditions may result in market losses. When the Pension Plan experiences market losses, significant variations in the funded status of the Pension Plan can, and often do, occur. Actuarial methods utilized in determining required future employer contributions take into account the long-term effect of market losses and result in increased future employer contributions, thus offsetting such market losses. Conversely, the long-term effect of market gains will result in decreased future employer contributions. Total account performance is to be reviewed at least annually, using a dynamic benchmark approach to track investment performance.

The Compensation Committee has selected an investment manager to implement the selection and on-going evaluation of Pension Plan investments. The investments shall be selected from the following assets classes, which includes mutual funds, collective funds, or the direct investment in individual stocks, bonds or cash equivalent investments, including: (a) money market accounts, (b) U.S. Government bonds, (c) corporate bonds, (d) large, mid, and small capitalization stocks, and (e) international stocks. The Policy Statement provides the following guidelines and limitations, subject to exceptions authorized by the Compensation Committee under unusual market conditions: (i) the maximum investment in any one stock should not exceed 10.0% of the total stock portfolio, (ii) the maximum investment in any one industry should not exceed 30.0% of the total stock portfolio, and (iii) the average credit quality of the bond portfolio should be at least AA with a maximum amount of non-investment grade debt of 10.0%.

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

 

     Percentage of Total Portfolio  
     Minimum     Target     Maximum  

Domestic equity securities

     50     70     90

Foreign equity securities

     0     10     20

Fixed income securities/cash

     5     20     40

Domestic equity securities primarily include investments in individual common stocks or registered investment companies that hold positions in companies that are based in the U.S. Foreign equity securities primarily include investments in individual common stocks or registered investment companies that hold positions in companies based outside the U.S. Fixed income securities primarily include individual bonds or registered investment companies that hold positions in U.S. Treasuries, U.S. government obligations, corporate bonds, mortgage backed securities and preferred stocks. Short-term market conditions may result in actual asset allocations that fall outside the minimum or maximum guidelines reflected in the Policy Statement.

 

Asset allocations as of December 31,    2010     2009  

Domestic equity securities

     59     57

Foreign equity securities

     21     15

Fixed income securities/cash

     20     28
                
     100     100
                

We consider multiple factors in our investment strategy. The following factors have been taken into consideration with respect to the Pension Plan’s long-term investment goals and objectives and in the establishment of the Pension Plan’s target investment allocation:

 

   

The long-term nature of providing retirement income benefits to Pension Plan participants;

 

   

The projected annual funding requirements necessary to meet the benefit obligations;

 

   

The current level of benefit payments to Pension Plan participants and beneficiaries; and

 

   

Ongoing analysis of economic conditions and investment markets.

 

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As required by FASB ASC 715, the following information discloses the fair values of our Pension Plan assets, by asset category, consist of the following for the periods indicated (in thousands):

 

     December 31, 2010      December 31, 2009  
     Quoted Prices in
Active Markets for
Identical Assets

(Level 1)
     Significant
Observable
Inputs

(Level 2)
    Significant
Unobservable
Inputs

(Level 3)
     Quoted Prices in
Active Markets for
Identical Assets

(Level 1)
     Significant
Observable
Inputs

(Level 2)
    Significant
Unobservable
Inputs

(Level 3)
 

Cash and cash equivalents

   $ 839       $ —        $ —         $ 688       $ —        $ —     

Equity securities (a):

               

U.S. large-cap growth

     6,151         —          —           5,515         —          —     

U.S. large-cap value

     5,922         —          —           5,331         —          —     

International large-cap core

     2,725         —          —           2,702         —          —     

Fixed income securities:

               

U.S. Treasury securities (b)

     1,552         —          —           1,812         —          —     

Corporate bonds (c)

     —           1,754        —           —           1,105        —     

Preferred stock (a)

     184         —          —           134         —          —     

Taxable municipal bonds (c)

     —           271        —           —           219        —     

International bonds (c)

     —           673        —           —           343        —     

Equity mutual funds (d):

               

U.S. large-cap growth

     —           225        —           —           —          —     

U.S. large-cap value

     —           747        —           —           866        —     

U.S. mid-cap growth

     —           4,172        —           —           2,739        —     

U.S. mid-cap value

     —           4,059        —           —           3,862        —     

U.S. small cap growth

     —           2,627        —           —           1,781        —     

U.S. small cap value

     —           2,195        —           —           1,529        —     

International

     —           4,020        —           —           2,516        —     

Emerging Markets

     —           2,534        —           —           517        —     

Fixed income mutual funds (d):

               

U.S. treasury and agency

     —           —          —           —           739        —     

Corporate bond

     —           879        —           —           808        —     

Mortgage backed-securities

     —           722        —           —           1,332        —     

Intermediate investment grade bond

     —           1,016        —           —           2,804        —     

High yield bond

     —           644        —           —           564        —     

International bond

     —           297        —           —           230        —     

Stock market index options (e):

               

Puts

     —           212        —           —           26        —     

Calls

     —           (438     —           —           (68     —     
                                                   

Total

   $ 17,373       $ 26,609      $ —         $ 16,182       $ 21,912      $ —     
                                                   

 

(a) Equity securities include investments in publicly-traded common stock and preferred stock. Publicly-traded common stocks are traded on a national securities exchange and investments in common and preferred stocks are valued using quoted market prices multiplied by the number of shares owned.
(b) U.S. Treasury securities include agency and treasury debt. These investments are valued using dealer quotes in an active market.
(c) Bonds are valued utilizing a market approach that includes various valuation techniques and sources such as value generation models, broker quotes in active and non-active markets, benchmark yields and securities, reported trades, issuer spreads, and/or other applicable reference data. The corporate bonds and notes category is primarily comprised of U.S. dollar denominated, investment grade securities. Less than 5 percent of the securities have a rating below investment grade. We classified our investments in bond fixed income securities as Level 2 measurements at December 31, 2010 and reclassified prior year amounts for consistency with our current year presentation.
(d) Mutual funds are valued daily in actively traded markets by an independent custodian for the investment manager. For purposes of calculating the value, portfolio securities and other assets for which market quotes are readily available are valued at market value. Market value is generally determined on a basis of last reported sales prices, or if not sales are reported, based on quotes obtained from a quotation reporting system, established market makers, or pricing services. Investments initially valued in currencies other than the U.S. dollars are converted to the U.S. dollar using exchange rates obtained from pricing services.
(e) Options are valued utilizing a market approach that includes various valuation techniques and sources such as value generation models, broker quotes in active and non-active markets, reported trades, issuer spreads, and/or other applicable reference data.

Pension Plan assets for which the fair value is based on quoted prices in active markets for identical assets are considered to be valued with Level 1 inputs in the fair value hierarchy. Pension Plan assets for which the fair value is based on quoted prices for similar instruments in active markets or quoted prices for identical or similar instruments in markets that are not active are considered to be valued with Level 2 inputs in the fair value hierarchy.

 

14. COMPENSATION PLANS

We have the LTIP for certain of our employees and officers of our managing general partner and its affiliates who perform services for us. The LTIP awards are of non-vested “phantom” or notional units, which upon satisfaction of vesting requirements, entitle the LTIP participant to receive ARLP common units. Annual grant levels and vesting provisions for designated participants are recommended by our President and Chief Executive Officer, subject to the review and approval of the Compensation Committee. The aggregate number of units reserved for issuance under the LTIP was 1.2 million prior to October 23, 2009. On October 23, 2009, the LTIP was amended to increase the number of common units available for issuance from 1.2 million to 3.6 million.

 

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On January 26, 2010, the Compensation Committee determined that the vesting requirements for the 2007 grants of 88,975 restricted units (which are net of 4,500 forfeitures) had been satisfied as of January 1, 2010. As a result of this vesting, on February 12, 2010, we issued 55,826 unrestricted common units to LTIP participants. The remaining units were settled in cash to satisfy the tax withholding obligations for the LTIP participants. On January 25, 2011, the Compensation Committee authorized additional grants up to 110,000 restricted units, of which 106,330 were granted.

During the years ended December 31, 2010 and 2009, the three months ended December 31, 2008 and the nine months ended September 30, 2008, we issued grants of 138,130 units, 9,625 units, 141,145 units and 93,600 units, respectively. Grants issued during the year ended December 31, 2010 vest on January 1, 2013. Grants issued during the year ended December 31, 2009 and the three months ended December 31, 2008 vest on January 1, 2012. Grants issued during the nine months ended September 30, 2008 vest on January 1, 2011. Vesting of all grants is subject to the satisfaction of certain financial tests that management currently believes it is probable will be satisfied. As of December 31, 2010, 9,777 of these outstanding LTIP grants have been forfeited. On January 25, 2011, the Compensation Committee determined that the vesting requirements for the 2008 grants of 91,100 restricted units (which is net of 2,500 forfeitures) had been satisfied as of January 1, 2011. As a result of this vesting, on February 11, 2011, we issued 58,886 unrestricted common units to the LTIP participants. The remaining units were settled in cash to satisfy the individual tax obligations of the LTIP participants. After consideration of the January 1, 2011 vesting and subsequent issuance of 58,886 common units, 2.3 million units remain available for issuance in the future, assuming that all grants issued in 2009 and 2010 and currently outstanding are settled with common units, without reduction for tax withholding, and no future forfeitures occur.

For the years ended December 31, 2010, 2009 and 2008, our LTIP expense was $4.1 million, $3.6 million and $3.3 million, respectively. The total obligation associated with the LTIP as of December 31, 2010 and 2009 was $7.6 million and $6.8 million, respectively, and is included in limited partners’ capital in our consolidated balance sheets.

The fair value of the 2010, 2009 and 2008 grants is based upon the intrinsic value at the date of grant, which was $39.59, $25.60 and $31.27 per restricted unit, respectively, on a weighted average basis. We expect to settle the non-vested LTIP grants by delivery of ARLP common units, except for the portion of the grants that will satisfy the minimum statutory tax withholding requirements. As provided under the distribution equivalent rights provision of the LTIP, all non-vested grants include contingent rights to receive quarterly cash distributions in an amount equal to the cash distribution we make to unitholders during the vesting period.

A summary of non-vested LTIP grants as of and for the year ended December 31, 2010 is as follows:

 

Non-vested grants at January 1, 2010

     332,845   

Granted

     138,130   

Vested

     (88,975

Forfeited

     (9,277
        

Non-vested grants at December 31, 2010

     372,723   
        

As of December 31, 2010, there was $4.8 million in total unrecognized compensation expense related to the non-vested LTIP grants that are expected to vest. That expense is expected to be recognized over a weighted-average period of 1.5 years. As of December 31, 2010, the intrinsic value of the non-vested LTIP grants was $24.5 million.

We have the SERP to provide deferred compensation benefits for certain officers and key employees. All allocations made to participants under the SERP are made in the form of “phantom” ARLP units, which upon vesting, for accounts payable on or prior to January 1, 2011, were paid to participants in cash only. The SERP is administered by the Compensation Committee.

For the years ended December 31, 2010, 2009 and 2008, our SERP expense (income) was $3.0 million, $2.1 million and $(0.5) million, respectively. The increase in SERP expense in 2010 and 2009 was principally attributable to an increase in the market value of our common units from the beginning of the year to the end of the year. The SERP income for the year ended December 31, 2008 resulted from lower unit-based compensation accruals due to a decrease in market value of our common units from the beginning of the year to the end of the year. The total accrued liability associated with the SERP plan was $7.3 million and $4.7 million as of December 31, 2010 and 2009, respectively, and is included in other long-term liabilities in the consolidated balance sheets.

 

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Our directors participate in the Deferred Compensation Plan. Pursuant to the Deferred Compensation Plan, for deferred amounts, a notional account is established and credited with notional common units of ARLP, described in the plan as “phantom” units. The number of phantom units credited is determined by dividing the amount deferred by the average closing unit price for the ten trading days immediately preceding the deferral date. When quarterly cash distributions are made with respect to ARLP common units, an amount equal to such quarterly distribution is credited to the notional account as additional phantom units.

Effective for accounts that become payable after January 1, 2011, both the Deferred Compensation Plan and the SERP require that vested benefits be paid to participants in common units of ARLP only, rather than cash. As a result, during January 2011, the vested units under each plan were reclassified to partners’ capital as required under FASB ASC 718, Compensation-Stock Compensation. In addition, the effect of the phantom units associated with these plans will be considered in the calculation of EPU beginning in the March 31, 2011 quarterly period. We do not expect the inclusion of these phantom units in the calculation of EPU to have a material impact on our consolidated financial statements.

 

15. SUPPLEMENTAL CASH FLOW INFORMATION

 

     Year Ended December 31,  
     2010      2009      2008  
     (in thousands)  

Cash Paid For:

        

Interest

   $ 30,787       $ 32,186       $ 22,920   
                          

Income taxes

   $ 1,803       $ 225       $ —     
                          

Non-Cash Activity:

        

Accounts payable for purchase of property, plant and equipment

   $ 13,339       $ 20,819       $ 15,092   
                          

Non-cash contribution by General Partner

   $ —         $ —         $ 620   
                          

Market value of common units vested in Long-Term Incentive Plan before minimum statutory tax withholding requirements

   $ 3,396       $ 2,333       $ 3,658   
                          

 

16. ASSET RETIREMENT OBLIGATIONS

The majority of our operations are governed by various state statutes and the Federal Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which establish reclamation and mine closing standards. These regulations, among other requirements, require restoration of property in accordance with specified standards and an approved reclamation plan. We account for our asset retirement obligations in accordance with FASB ASC 410, Asset Retirement and Environmental Obligations, which requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred. We have estimated the costs and timing of future asset retirement obligations escalated for inflation, then discounted and recorded at the present value of those estimates.

 

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Discounting resulted in reducing the accrual for asset retirement obligations by $72.8 million and $68.0 million at December 31, 2010 and 2009, respectively. Estimated payments of asset retirement obligations as of December 31, 2010 are as follows (in thousands):

 

Year Ending

December 31,

      

2011

   $ 2,182   

2012

     2,490   

2013

     1,012   

2014

     617   

2015

     2,871   

Thereafter

     121,806   
        

Aggregate undiscounted asset retirement obligations

     130,978   

Effect of discounting

     (72,751
        

Total asset retirement obligations

     58,227   

Less: current portion

     (2,182
        

Asset retirement obligations

   $ 56,045   
        

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

 

     Year ended December 31,  
     2010     2009  

Beginning balance

   $ 55,851      $ 58,589   

Accretion expense

     2,574        2,678   

Payments

     (966     (556

Allocation of liability associated with acquisition, mine development and change in assumptions

     768        (4,860
                

Ending balance

   $ 58,227      $ 55,851   
                

For the year ended December 31, 2010, the allocation of liability associated with acquisition, mine development and change in assumptions is a net increase of $0.8 million was primarily attributable to increased refuse site reclamation disturbances at our Hopkins County Coal operation and new mine development work at Tunnel Ridge, as well as the net impact of 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. These increases were offset in part by a reduction in the impoundment cover material at Pontiki and MC Mining.

For the year ended December 31, 2009, the allocation of liability associated with acquisition, mine development and change in assumptions is a net decrease of $4.9 million, and was primarily attributable to decreased refuse site reclamation disturbances at our Hopkins County Coal operation 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.

 

17. ACCRUED WORKERS’ COMPENSATION AND PNEUMOCONIOSIS BENEFITS

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

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

 

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We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers’ compensation laws also compensate survivors or workers who suffer employment related deaths. Our liability for traumatic injury claims is the estimated present value of current workers’ compensation benefits, based on our actuarial estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including development patterns, mortality, medical costs and interest rates. The discount rate used to calculate the estimated present value of future obligations for black lung was 5.38% and 5.80% at December 31, 2010 and 2009, respectively, and for workers’ compensation was 4.70% and 5.27% at December 31, 2010 and 2009, respectively.

The black lung and workers’ compensation expense consists of the following components for the year ended December 31, 2010, 2009 and 2008 (in thousands):

 

     2010     2009     2008  

Black lung benefits:

      

Service cost

   $ 2,359      $ 2,187      $ 1,415   

Interest cost

     1,857        1,535        1,641   

Net amortization

     (176     (536     (745
                        

Total black lung

     4,040        3,186        2,311   

Workers’ compensation expense

     16,776        21,585        18,395   
                        

Total expense

   $ 20,816      $ 24,771      $ 20,706   
                        

The following is a reconciliation of the changes in workers’ compensation liability (including current and long-term liability balances) at December 31, 2010 and 2009 (in thousands):

 

     2010     2009  

Beginning balance

   $ 63,220      $ 56,671   

Accruals

     20,047        18,466   

Payments

     (9,944     (12,534

Interest accretion

     3,332        3,455   

Valuation gain

     (8,968     (2,838
                

Ending balance

   $ 67,687      $ 63,220   
                

The following is a reconciliation of the changes in black lung benefit obligations at December 31, 2010 and 2009 (in thousands):

 

     2010     2009  

Benefit obligations at beginning of year

   $ 34,855      $ 31,970   

Service cost

     2,359        2,187   

Interest cost

     1,857        1,535   

Actuarial loss (gain)

     6,871        (536

Benefits and expenses paid

     (276     (301
                

Benefit obligations at end of year

   $ 45,666      $ 34,855   
                

Summarized below is information about the amounts recognized in the accompanying consolidated balance sheets for black lung and workers’ compensation benefits at December 31, 2010 and 2009 (in thousands):

 

     2010     2009  

Black lung claims

   $ 45,666      $ 34,855   

Workers’ compensation claims

     67,687        63,220   
                

Total obligations

     113,353        98,075   

Less current portion

     (8,518     (9,886
                

Non-current obligations

   $ 104,835      $ 88,189   
                

 

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Both the black lung and workers’ compensation obligations were unfunded at December 31, 2010 and 2009.

As of December 31, 2010 and 2009, we had $69.6 million and $66.9 million, respectively, in surety bonds and letters of credit outstanding to secure workers’ compensation obligations.

The Patient Protection and Affordable Care Act, which was signed into law by President Obama on March 23, 2010, amended previous legislation related to coal workers’ black lung providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims. The impact of these changes to our current population of beneficiaries and claimants resulted in an estimated $8.3 million increase to our black lung obligation at the measurement date. As of December 31, 2010, we recorded this estimate as an increase to our black lung liability and a decrease to our actuarial gain included in accumulated other comprehensive income on our consolidated balance sheet. This increase to our obligation excludes the impact of potential re-filing of closed claims and potential filing rates for employees who terminated more than seven years ago as we do not have sufficient information to determine what, if any, claims will be filed until regulations are issued. We will continue to evaluate the impact of these changes on such claims and record any necessary changes in the period in which the impact is estimable. For more information, please read “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Health Care Reform” of this Annual Report on Form 10-K.

 

18. NONCONTROLLING INTEREST

We apply the provisions of FASB ASC 810, Consolidation, which were amended on January 1, 2010. Based on our evaluation of these amendments, we deconsolidated MAC effective January 1, 2010 (Note 2).

White County Coal and Alexander J. House (“House”) entered into a limited liability company agreement in 2006 to form MAC, which manufactures and sells rock dust. Consistent with prior years, we have a 50% ownership interest in MAC. Previously, we consolidated MAC’s financial results in accordance with FASB ASC 810. However, based on the provisions of ASU 2009-17, we concluded that we are no longer the primary beneficiary of MAC and thus deconsolidated MAC as House has the power to direct the activities that most significantly impact the entity’s economic performance.

We adopted the amendments to FASB ASC 810 on January 1, 2010. As a result, we reclassified $1.1 million from noncontrolling interest in partners’ capital to other long-term assets in our consolidated balance sheets. We did not retrospectively apply the provisions of ASU 2009-17 as allowed by the amendments. Our equity investment in MAC is $1.3 million at December 31, 2010.

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 expired on December 31, 2010. At December 31, 2010, MAC owed ARLP $1.6 million under the Revolver, which is classified as Due from Affiliates on our consolidated balance sheets. MAC repaid the amount due under the Revolver in January 2011.

 

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19. RELATED-PARTY TRANSACTIONS

The Board of Directors and its 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—On April 1, 2010, effective January 1, 2010, ARLP entered into an Amended and Restated Administrative Services Agreement (the “ Administrative Services Agreement”) with our managing general partner, our Intermediate Partnership, AHGP and its general partner AGP, and Alliance Resource Holdings II, Inc. (“ARH II”), the indirect parent of SGP. The Administrative Services Agreement superseded the administrative services agreement signed in connection with the AHGP IPO in 2006. 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 the Administrative Services Agreement of $0.3 million, $0.4 million and $0.4 million for the years ended December 31, 2010, 2009 and 2008, respectively, from AHGP and $0.2 million, $0.5 million and $0.5 million from ARH II for the years ended December 31, 2010, 2009 and 2008, respectively. Concurrent with the AHGP IPO 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 $1.3 million, $1.1 million and $0.3 million for the years ended December 31, 2010, 2009 and 2008, respectively. The increase from 2008 to 2009 was primarily attributable 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.

Managing General Partner ContributionDuring 2008, an affiliated entity controlled by Mr. Craft, contributed 25,898 AHGP common units valued at approximately $0.6 million at the time of contribution and $0.8 million of cash to AHGP for the purpose of funding certain expenses associated with our employee compensation programs. Upon AHGP’s receipt of this contribution, it immediately contributed the same to its subsidiary MGP, our managing general partner, which in turn contributed the same to our subsidiary Alliance Coal. Concurrent with this contribution, Alliance Coal distributed the 25,898 AHGP common units to certain employees and recognized compensation expense of $1.4 million. 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 (Note 12).

MAC (Note 18)In September 2007, MAC entered into a $1.5 million Revolver with ARLP. 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 expired on December 31, 2010. At December 31, 2010, MAC owed ARLP $1.6 million under the Revolver, which is classified as Due from Affiliates on our consolidated balance sheets. MAC repaid the amount due under the Revolver in January 2011.

SGP Land, LLCOn May 2, 2007, SGP Land, a subsidiary of our special general partner 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 $0.8 million, $0.7 million and $0.7 million for the years ended December 31, 2010, 2009 and 2008, respectively, 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

 

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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, 2010 and 2009.

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, 2010, 2009 and 2008, respectively. As of December 31, 2010, $2.1 million of advance minimum royalties paid under the lease is available for recoupment, and management expects that it will be recouped against future production.

SGPIn 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, 2010, 2009 and 2008. As of December 31, 2010, $17.9 million of advance minimum royalties paid under the lease is available for recoupment and management expects that it will be recouped against future production. In August 2010, the coal lease was amended to include approximately 34.4 million additional clean tons of recoverable coal reserves in the proven and probable categories.

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, 2010, 2009 and 2008.

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, 2010, 2009 and 2008 was $2.6 million. Effective February 1, 2011, the lease was amended to extend the term through January 2017 and modify other terms, including reducing the monthly payments to approximately $50,000.

We have agreements with two banks to provide letters of credit in an aggregate amount of $31.1 million (Note 8). At December 31, 2010, we had $30.7 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, and does not impact our consolidated financial statements.

 

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20. COMMITMENTS AND CONTINGENCIES

CommitmentsWe lease buildings and equipment under operating lease agreements that provide for the payment of both minimum and contingent rentals. We also have a noncancelable lease with SGP (Note 19) and a noncancelable lease for equipment under a capital lease obligation. Future minimum lease payments are as follows (in thousands):

 

           Other Operating Leases  

Year Ending December 31,

   Capital
Lease
    Affiliate      Others      Total  

2011

   $ 346      $ 456       $ 1,445       $ 1,901   

2012

     141        —           763         763   

2013

     84        —           367         367   

2014

     13        —           367         367   

2015

     —          —           367         367   

Thereafter

     —          —           1,010         1,010   
                                  

Total future minimum lease payments

   $ 584      $ 456       $ 4,319       $ 4,775   
                            

Less: amount representing interest

     (124        
                

Present value of future minimum lease payments

     460           

Less: current portion

     (295        
                

Long-term capital lease obligation

   $ 165           
                

Rental expense (including rental expense incurred under operating lease agreements) was $7.2 million, $6.0 million and $5.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Our subsidiary, Mettiki (WV), entered into a capital lease agreement with Joy Technologies Inc., d/b/a Joy Mining Machinery, a Delaware corporation, on May 22, 2006, with an in-service date of November 20, 2006. The lease is a 5-year noncancelable lease with monthly rental payments of $42,930 and has one renewal period for 2 years with monthly rental payments of $24,680. The effective interest rate on the capital lease is 6.195%.

Contractual CommitmentsIn connection with planned capital projects, we have contractual commitments of approximately $86.8 million at December 31, 2010. As of December 31, 2010, we had commitments to purchase, from external production sources, coal at an estimated cost up to $14.1 million in 2011.

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

The matters referenced in the previous paragraph include, but are not limited to, the Rector v. White County Coal, LLC lawsuit, which is a royalty dispute involving certain coal leases that had previously terminated. Plaintiffs had alleged damages of $33 million or more and had also asserted a claim for punitive damages. During November 2010, the court found in favor of the plaintiffs in the amount of $3.4 million of back royalty payments through August 2009 plus $0.4 million in related interest through the judgment date. The court also awarded plaintiffs overriding royalties on future coal production after August 2009 plus interest, which we estimate to total approximately $0.6 million through December 31, 2010 and approximately $2.1 million of royalties in the subsequent five years. The decision by the court did not have a material adverse effect on our business, financial position or results of operations. We continue to believe plaintiffs’ claims are without merit and are vigorously appealing the decision. Plaintiffs have cross appealed on the issue of future royalties, asking to be awarded the present value of the future royalties. This legal matter is also discussed in Part I, Item 3. “Legal Proceedings.”

Other—During September 2010, we completed our annual property and casualty insurance renewal with various insurance coverages effective October 1, 2010. The aggregate maximum limit in the commercial property program is $75.0 million per occurrence excluding a $1.5 million deductible for property damage, a 60-day waiting period for

 

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business interruption and a $10.0 million overall aggregate deductible. The aforementioned property and casualty insurance coverages, effective October 1, 2010, replaced our prior year 14.7% participation rate with the deductibles mentioned above. We can make no assurances that we will not experience significant insurance claims in the future that could have a material adverse effect on our business, financial condition, results of operations and ability to purchase property insurance in the future.

 

21. CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

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

 

          Year Ended December 31,  
    

Segment (Note 22)

   2010 (1)      2009      2008  

Customer A

  

Illinois Basin

   $ 279,516       $ 120,915       $ 127,439   

Customer B

  

Illinois Basin

     191,225         140,921         131,198   

Customer C

  

Northern Appalachia

     —           129,265         161,359   

Customer D

  

Illinois Basin

     —           122,961         121,550   

Trade accounts receivable from these customers totaled approximately $35.9 million and $38.0 million at December 31, 2010 and 2009, respectively. Our bad debt experience has historically been insignificant. Financial conditions of our customers could result in a material change to our bad debt expense in future periods. We have various coal agreements with our significant customers with expiration dates ranging from 2011 to 2016.

 

(1) Customer C & D are below the 10% threshold of total revenues for 2010.

 

22. SEGMENT INFORMATION

We operate in the eastern U.S. as a producer and marketer of coal to major utilities and industrial users. We aggregate multiple operating segments into four reportable segments: the Illinois Basin, Central Appalachia, Northern Appalachia and Other and Corporate. The first three reportable segments correspond to the three major coal producing regions in the eastern U.S. Similar economic characteristics for our operating segments with each of these three reportable segments include coal quality, coal seam height, mining and transportation methods and regulatory issues.

The Illinois Basin reportable segment is comprised of multiple operating segments, including 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 mining complex, which initiated operations in 2009, the Sebree property, the Gibson South property and certain properties of Alliance Resource Properties and its wholly-owned subsidiary, ARP Sebree, LLC. We are in the process of permitting the Gibson South property and the Sebree property for future mine development.

The Central Appalachian reportable segment is comprised of two operating segments, the Pontiki and MC Mining mining complexes.

The Northern Appalachian reportable segment is comprised of multiple operating segments, including Mettiki (MD)’s mining complex, Mettiki (WV)’s Mountain View mining complex, two small third-party mining operations, a mining complex currently under construction at Tunnel Ridge and the Penn Ridge property. In May 2010, incidental production began from mine development activities at Tunnel Ridge, however, longwall production is not anticipated until early 2012. We are in the process of permitting the Penn Ridge property for future mine development.

 

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Other and Corporate includes marketing and administrative expenses, Matrix Design, Alliance Design (collectively, Matrix Design and Alliance Design are referred to as the “Matrix Group”), the Mt. Vernon dock activities, coal brokerage activity, our equity investment in MAC and certain properties of Alliance Resource Properties. Reportable segment results as of and for the years ended December 31, 2010, 2009 and 2008 are presented below.

 

     Illinois
Basin
     Central
Appalachia
     Northern
Appalachia
     Other and
Corporate
     Elimination
(1)
    Consolidated  
     (in thousands)  

Reportable segment results as of and for the year ended December 31, 2010 were as follows:

  

Total revenues (2)

   $ 1,202,442       $ 165,175       $ 219,211       $ 45,052       $ (21,815   $ 1,610,065   

Segment Adjusted EBITDA Expense (3)

     717,040         128,318         163,876         38,743         (21,815     1,026,162   

Segment Adjusted EBITDA (4)

     460,592         36,714         46,702         6,311         —          550,319   

Total assets

     745,626         81,818         313,515         364,405         (4,086     1,501,278   

Capital expenditures

     149,149         10,012         128,961         1,752         —          289,874   

Reportable segment results as of and for the year ended December 31, 2009 were as follows:

  

Total revenues (2)

   $ 883,800       $ 181,029       $ 148,253       $ 40,441       $ (22,492   $ 1,231,031   

Segment Adjusted EBITDA Expense (3)

     532,549         138,412         124,176         30,789         (22,122     803,804   

Segment Adjusted EBITDA (4)

     315,542         41,149         15,552         9,621         (370     381,494   

Total assets

     725,243         86,011         199,443         43,132         (2,429     1,051,400   

Capital expenditures

     228,522         14,895         81,009         3,736         —          328,162   

Reportable segment results as of and for the year ended December 31, 2008 were as follows:

  

Total revenues (2)

   $ 748,369       $ 207,645       $ 187,603       $ 23,546       $ (10,614   $ 1,156,549   

Segment Adjusted EBITDA Expense (3)

     522,575         157,575         134,800         20,441         (10,636     824,755   

Segment Adjusted EBITDA (4)

     194,410         52,812         39,480         8,264         22        294,988   

Total assets

     543,175         88,745         136,515         262,278         (73     1,030,640   

Capital expenditures (5)

     141,843         11,303         19,986         3,350         —          176,482   

 

(1) The elimination column represents the elimination of intercompany transactions and is primarily comprised of sales from the Matrix Group and MAC (for 2009 and 2008 only, see Note 18) to our mining operations.
(2) Revenues included in the Other and Corporate column are primarily attributable to Matrix Group revenues, Mt. Vernon transloading revenues, administrative service revenues from affiliates, MAC rock dust revenues (for 2009 and 2008 only, see Note 18) and brokerage sales (2010 and 2009 only).
(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. We review Segment Adjusted EBITDA Expense per ton for cost trends.

The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to operating expenses (excluding depreciation, depletion and amortization) (in thousands):

 

     Year Ended December 31,  
     2010     2009     2008  

Segment Adjusted EBITDA Expense

   $ 1,026,162      $ 803,804      $ 824,755   

Outside coal purchases

     (17,078     (7,524     (23,776

Other income

     851        1,247        875   
                        

Operating expenses (excluding depreciation, depletion and amortization)

   $ 1,009,935      $ 797,527      $ 801,854   
                        

 

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(4) 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. 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. Consolidated Segment Adjusted EBITDA is reconciled to net income and Net Income of ARLP below (in thousands):

 

     Year Ended December 31,  
     2010     2009     2008  

Consolidated Segment Adjusted EBITDA

   $ 550,319      $ 381,494      $ 294,988   

General and administrative

     (50,818     (41,117     (37,176

Depreciation, depletion and amortization

     (146,881     (117,524     (105,278

Interest expense, net

     (29,862     (29,798     (18,418

Income tax (expense) benefit

     (1,741     (708     480   
                        

Net income

     321,017        192,347        134,596   

Net income attributable to noncontrolling interest

     —          (190     (420
                        

Net Income of ARLP

   $ 321,017      $ 192,157      $ 134,176   
                        

 

(5) Capital expenditures do not include acquisition of coal reserves and other assets in the Illinois Basin of $29.8 million for the year ended December 31, 2008 separately reported in our consolidated statements of cash flows.

 

23. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

A summary of our consolidated quarterly operating results in 2010 and 2009 is as follows (in thousands, except unit and per unit data):

 

     Quarter Ended  
     March 31,
2010
     June 30,
2010
     September 30,
2010
     December 31,
2010 (1)
 

Revenues

   $ 380,661       $ 400,343       $ 410,448       $ 418,613   

Income from operations

     82,850         92,971         81,322         94,626   

Income before income taxes

     75,156         85,884         74,196         87,522   

Net income of ARLP

     74,988         85,461         73,201         87,367   

Basic and diluted net income per limited partner unit

   $ 1.56       $ 1.82       $ 1.48       $ 1.82   

Weighted average number of units outstanding – basic and diluted

     36,690,803         36,716,855         36,716,855         36,716,855   
     Quarter Ended  
     March 31,
2009
     June 30,
2009
     September 30,
2009
     December 31,
2009 (1)
 

Revenues

   $ 329,300       $ 303,904       $ 299,644       $ 298,183   

Income from operations

     80,190         48,622         44,520         48,274   

Income before income taxes

     73,066         41,309         37,083         41,597   

Net income of ARLP

     72,511         41,460         36,444         41,742   

Basic and diluted net income per limited partner unit

   $ 1.56       $ 0.72       $ 0.57       $ 0.70   

Weighted average number of units outstanding – basic and diluted

     36,638,829         36,661,029         36,661,029         36,661,029   

 

(1) The comparability of our December 31, 2010 and 2009 quarterly results were affected by a $13.9 million and $6.4 million decrease in our workers’ compensation liability, excluding discount rate changes, due to the completion of our annual actuarial study, which reflected a favorable development in our disability emergence patterns and claims estimates, as well as improved visibility of our Mettiki (WV) claims experience.

 

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24. SUBSEQUENT EVENTS

Other than those events described in Notes 4, 10, 14 and 19, there were no other subsequent events.

 

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SCHEDULE II

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

 

     Balance At
Beginning
of Year
     Additions
Charged to
Income
     Deductions      Balance At
End of  Year
 
     (in thousands)  

2010

           

Allowance for doubtful accounts

   $ —         $ —         $ —         $ —     
                                   

2009

           

Allowance for doubtful accounts

   $ —         $ —         $ —         $ —     
                                   

2008

           

Allowance for doubtful accounts

   $ —         $ —         $ —         $ —     
                                   

 

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANT ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

 

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures. We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosures. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act) was performed as of the end of the period covered by the report. This evaluation was performed by our management, with the participation of our Chief Executive Officer and Chief Financial Officer. Based on this evaluation of our disclosure controls and procedures as of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective.

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls or our internal controls over financial reporting (“Internal Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the ARLP Partnership have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that simple errors or mistakes can occur. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based, in part, upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our disclosure controls and internal controls and make modifications as necessary; our intent in this regard is that the disclosure controls and the internal controls will be maintained as systems change and conditions warrant.

 

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Management’s Annual Report on Internal Control over Financial Reporting. Management of the ARLP Partnership is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. The ARLP Partnership’s internal control over financial reporting is designed to provide reasonable assurance to our management and Board of Directors of our managing general partner regarding the preparation and fair presentation of published financial statements. Our controls are designed to provide reasonable assurance that the ARLP Partnership’s assets are protected from unauthorized use and that transactions are executed in accordance with established authorizations and properly recorded. The internal controls are supported by written policies and are complemented by a staff of competent business process owners and an internal auditor supported by competent and qualified external resources used to assist in testing the operating effectiveness of the ARLP Partnership’s internal control over financial reporting. Management concluded that the design and operations of our internal controls over financial reporting at December 31, 2010 are effective and provide reasonable assurance the books and records accurately reflect the transactions of the ARLP Partnership.

Because of our inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal ControlIntegrated Framework. Based on its assessment, management concluded that, as of December 31, 2010, the ARLP Partnership’s internal control over financial reporting was effective based on those criteria, and management believes that we have no material internal control weaknesses in our financial reporting process.

Deloitte & Touche LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of our internal control over financial reporting as of December 31, 2010, as stated in their report which is included herein.

Changes in Internal Controls Over Financial Reporting. There has been no change in our internal controls over financial reporting (as defined in Rule 13a-15(f) or Rule 15d-15(f) in the three months ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of the Managing

General Partner and the Partners of

Alliance Resource Partners, L.P.:

We have audited the internal control over financial reporting of Alliance Resource Partners, L.P. and subsidiaries (the “Partnership”) as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2010 of the Partnership and our report dated February 28, 2011 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ Deloitte & Touche LLP

Tulsa, Oklahoma

February 28, 2011

 

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ITEM 9B. OTHER INFORMATION

Federal Mine Safety and Health Act Information

Workplace safety is fundamental to our culture. Our operating subsidiaries empower their employees to be actively involved in continuous efforts to prevent accidents. By providing a work environment that rewards safety and encourages employee participation in the safety process, our mining operations strive to be the leaders in safety performance in our industry.

We are also a leader in developing and implementing new technologies to improve safety throughout the industry. For example, our subsidiary Matrix Design recently announced the development of two innovative technologies designed to improve safety in underground mining operations – a portable, wireless communication and electronic tracking system designed to allow surface personnel the ability to communicate with and locate underground mining personnel and a proximity detection system designed to improve the safety of continuous mining units used in underground operations. Matrix Design has completed installation of its communication and tracking system at all of our operating subsidiaries and has either installed or received orders to install this vital safety system at over half of the operating underground coal mines in the U.S. In addition, Matrix Design has installed and is conducting field tests on sixteen of its proximity detection systems at eight of our operating subsidiaries’ underground coal mines.

Our industry is focused on improving employee safety and its safety performance is continuously monitored, including through the mining industry standard of “non-fatal days lost”, or “NFDL”, which reflects both the frequency and severity of injuries incurred and, we believe, is a better measure of safety performance than compliance statistics. As indicated in the chart below, these efforts have resulted in significant safety improvements as the industry average NFDL, as reported(a) by the MSHA, has decreased approximately 59% since 1998.

LOGO

 

  (a) Data compiled for all U.S. underground bituminous coal mines and related surface facilities from the MSHA report “Mine Injury and Worktime, Quarterly Closeout Edition.” Data for 1998 through 2009 reflects the “January – December, Final” report for each year. Data for 2010 reflects the “January – December, Preliminary” report.

 

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During this same time period, the combined NFDL rating of our operating subsidiaries has averaged approximately one-third better than the industry average. The average NFDL rating of our operating subsidiaries allowed us to achieve in 2010 our best annual NFDL results in our history.

Our mining operations are subject to extensive and stringent compliance standards established pursuant to the FMSHA, as amended by the MINER Act, (as amended, the “Mine Act”). MSHA monitors and rigorously enforces compliance with these standards, and our mining operations are inspected frequently. During the three and twelve months ended December 31, 2010, our mines were subject to 1,535 and 5,778 MSHA inspection days, respectively, with an average of only 0.18 and 0.20 “significant and substantial”, or “S&S”, citations written per inspection day, respectively.

We endeavor to comply at all times with all Mine Act regulations. However, the Mine Act has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability, or liability without fault. If, in the opinion of an MSHA inspector, a condition exists that violates the Mine Act or regulations promulgated thereunder, then a citation or order will be issued regardless of whether we had any knowledge of, or fault in, the existence of that condition. Many of the Mine Act standards include one or more subjective elements, so that issuance of a citation often depends on the opinions or experience of the MSHA inspector involved and the frequency of citations will vary from inspector to inspector.

The number of citations issued also is affected by the size of the mine, in that the number of citations issued generally increases with the size of the mine. Our mines typically are larger in scale than most underground coal mines in the U.S. in terms of area, production and employee hours.

We take all allegations of violations of Mine Act standards seriously, and if we disagree with the assertions of an MSHA inspector, we exercise our right to challenge those findings by “contesting” the citation or order pursuant to the procedures established by the Mine Act and its regulations. During 2010, our operating subsidiaries have contested approximately 25% of all citations and the majority of S&S citations issued by MSHA inspectors. These contest proceedings frequently result in the dismissal or modification of previously issued citations, substantial reductions in the penalty amounts originally assessed by MSHA, or both.

The Dodd–Frank Act requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Mine Act. Responding to that legislation, we report that, for the three and twelve months ended December 31, 2010, none of our operating subsidiaries (a) received any violations under section 110(b)(2) of the Mine Act for failure to make reasonable efforts to eliminate a known violation of a mandatory safety or health standard that substantially proximately caused, or reasonably could have been expected to cause, death or serious bodily injury, (b) received any MSHA written notice under Mine Act section 104(e) of a pattern of violations of mandatory health or safety standards or the potential to have such a pattern, or (c) had any legal proceedings (i.e. appeals before the Federal Mine Safety and Health Review Commission (the “Commission”)) pending. We have contests of 192 and 931 citations or orders pending before the administrative law judges of the Commission that were initiated during the three and twelve months ended December 31, 2010, respectively, and that involve all types of citations (i.e., not only S&S citations). We had one fatality during the three months ended December 31, 2010 and three fatalities during the twelve months ended December 31, 2010.

The following table sets out additional information required by the Dodd–Frank Act for the three months ended December 31, 2010. The mine data retrieval system maintained by MSHA may show information that is different than what is provided herein. Any such difference may be attributed to the need to update that information on MSHA’s system and/or other factors.

 

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                   Section 104(d)             Total Proposed  
     Section 104(a)      Section 104(b)      Citations and      Section 107(a)      Assessments  

Subsidiary Name (1)

   Citations(2)      Orders(3)      Orders(4)      Orders(5)      (in  thousands)(6)  

Illinois Basin Operations

              

Webster County Coal, LLC (KY)

     61         —           1         —         $ 39.0   

Warrior Coal, LLC (KY)

     31         —           —           —         $ 22.8   

Hopkins County Coal, LLC (KY)

     19         —           —           —         $ 12.1   

River View Coal, LLC (KY)

     25         —           —           —         $ 0 .9   

White County Coal, LLC (IL)

     18         —           —           —         $ 2.7   

Gibson County Coal, LLC (IN)

     36         —           4         —         $ 64.1   

Central Appalachian Operations

              

Pontiki Coal, LLC (KY)

     25         1         —           —         $ 60.9   

MC Mining, LLC (KY)

     43         1         2         2       $ 174.7   

Northern Appalachian Operations

              

Mettiki Coal, LLC (MD)

     —           —           —           —         $ —     

Mettiki Coal (WV), LLC

     9         —           —           —         $ 6.4   

Tunnel Ridge, LLC (PA/WV)

     8         —           —           —         $ 0.7   

The following table sets out additional information required by the Dodd–Frank Act for the twelve months ended December 31, 2010:

 

                   Section 104(d)             Total Proposed  
     Section 104(a)      Section 104(b)      Citations and      Section 107(a)      Assessments  

Subsidiary Name (1)

   Citations(2)      Orders(3)      Orders(4)      Orders(5)      (in  thousands)(6)  

Illinois Basin Operations

              

Webster County Coal, LLC (KY)

     227         —           5         —         $ 549.4   

Warrior Coal, LLC (KY)

     138         —           1         —         $ 197.5   

Hopkins County Coal, LLC (KY)

     81         1         —           —         $ 93.8   

River View Coal, LLC (KY)

     112         —           1         1       $ 64.2   

White County Coal, LLC (IL)

     120         —           4         —         $ 252.5   

Gibson County Coal, LLC (IN)

     98         —           5         —         $ 224.9   

Central Appalachian Operations

              

Pontiki Coal, LLC (KY)

     127         1         1         —         $ 401.5   

MC Mining, LLC (KY)

     148         3         2         3       $ 386.1   

Northern Appalachian Operations

              

Mettiki Coal, LLC (MD)

     10         —           —           —         $ 5.2   

Mettiki Coal (WV), LLC

     46         —           —           —         $ 41.1   

Tunnel Ridge, LLC (PA/WV)

     19         —           —           —         $ 2.7   

 

(1) The statistics reported for each of our subsidiaries listed above include all components of the mining complex involved and therefore may involve multiple MSHA identification numbers. Any S&S citations or orders issued to our subsidiary, Excel, are included in the statistics for either Pontiki Coal or MC Mining, depending on the mining complex involved.
(2) Mine Act section 104(a) citations shown above are for alleged violations of health or safety standards that could significantly and substantially contribute to a serious injury.
(3) Mine Act section 104(b) orders are for alleged failures to totally abate a citation within the period of time specified in the citation.
(4) Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e. aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.

 

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(5) Mine Act section 107(a) orders are for alleged conditions or practices which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated and result in orders of immediate withdrawal from the area of the mine affected by the condition.
(6) Amounts shown include assessments proposed by MSHA during the three months and twelve months ended December 31, 2010 on the citations and orders reflected in this chart.

 

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PART III

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE MANAGING GENERAL PARTNER

As is commonly the case with publicly-traded limited partnerships, we are managed and operated by our managing general partner. The following table shows information for executive officers and members of the Board of Directors. Executive officers and directors are elected until death, resignation, retirement, disqualification, or removal.

 

Name    Age    Position With Our Managing General Partner

Joseph W. Craft III

   60    President, Chief Executive Officer and Director

Brian L. Cantrell

   51    Senior Vice President and Chief Financial Officer

R. Eberley Davis

   53    Senior Vice President, General Counsel and Secretary

Robert G. Sachse

   62    Executive Vice President

Charles R. Wesley

   56    Executive Vice President and Director

Thomas M. Wynne

   54    Senior Vice President and Chief Operating Officer

Michael J. Hall

   66    Director and Member of Audit* and Compensation Committees

John P. Neafsey

   71    Chairman of the Board and Member of Compensation and Conflicts* Committees

John H. Robinson

   60    Director and Member of Audit, Compensation* and Conflicts Committees

Wilson M. Torrence

   69    Director and Member of Audit, Compensation and Conflicts Committees

 

* Indicates Chairman of Committee

Joseph W. Craft III has been President, Chief Executive Officer and a Director since August 1999 and has indirect majority ownership of our managing general partner. Mr. Craft also serves as President, Chief Executive Officer and Chairman of the Board of Directors of AGP, the general partner of AHGP. Previously Mr. Craft served as President of MAPCO Coal Inc. since 1986. During that period, he also was Senior Vice President of MAPCO Inc. and had previously been that company’s General Counsel and Chief Financial Officer. He is a former Chairman of the National Coal Council, a Board and Executive Committee Member and Chairman of the Safety, Health and Human Resources Committee of the National Mining Association, a Director of American Coalition for Clean Coal Electricity, a Director of BOK Financial Corporation (NASDAQ: BOKF) since April of 2007, a member of the Board of Trustees for the University of Tulsa and a Director of the Tulsa Community Foundation. Mr. Craft holds a Bachelor of Science degree in Accounting and a Juris Doctorate degree from the University of Kentucky. Mr. Craft also is a graduate of the Senior Executive Program of the Alfred P. Sloan School of Management at Massachusetts Institute of Technology. The specific experience, qualifications, attributes or skills that led to the conclusion Mr. Craft should serve as a Director include his long history of significant involvement in the coal industry, his demonstrated business acumen and his exceptional leadership of the Partnership since its inception.

Brian L. Cantrell has been Senior Vice President and Chief Financial Officer since October 2003. Mr. Cantrell also serves as Senior Vice President and Chief Financial Officer of AGP, the general partner of AHGP. Prior to his current position, Mr. Cantrell was President of AFN Communications, LLC from November 2001 to October 2003 where he had previously served as Executive Vice President and Chief Financial Officer after joining AFN in September 2000. Mr. Cantrell’s previous positions include Chief Financial Officer, Treasurer and Director with Brighton Energy, LLC from August 1997 to September 2000; Vice President—Finance of KCS Medallion Resources, Inc.; and Vice President—Finance, Secretary and Treasurer of Intercoast Oil and Gas Company. Mr. Cantrell is a Certified Public Accountant and holds a Masters of Accountancy and Bachelor of Accountancy from the University of Oklahoma.

 

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R. Eberley Davis has been Senior Vice President, General Counsel and Secretary since February 2007. Mr. Davis also serves as Senior Vice President, General Counsel and Secretary of AGP, the general partner of AHGP. Mr. Davis has over 25 years experience in the coal and energy industries. From 2003 to February 2007, Mr. Davis practiced law in the Lexington, Kentucky office of Stoll Keenon Ogden PLLC. Prior to joining Stoll Keenon Ogden, Mr. Davis was Vice President, General Counsel and Secretary of Massey Energy Company for one year. Mr. Davis also served in various positions, including Vice President and General Counsel, for Lodestar Energy, Inc. from 1993 to 2002. Mr. Davis is an alumnus of the University of Kentucky, where he received a Bachelor of Arts degree in Economics and his Juris Doctorate degree. He also holds a Masters of Business Administration degree from the University of Kentucky. Mr. Davis is a Trustee of the Energy and Mineral Law Foundation, and a member of the American, Kentucky and Fayette County Bar Associations.

Robert G. Sachse has been Executive Vice President since August 2000. Effective November 1, 2006, Mr. Sachse assumed responsibility for our coal marketing, sales and transportation functions. Mr. Sachse was also Vice Chairman of our managing general partner from August 2000 to January 2007. Mr. Sachse was Executive Vice President and Chief Operating Officer of MAPCO Inc. from 1996 to 1998 when MAPCO merged with The Williams Companies. Following the merger, Mr. Sachse had a two year non-compete consulting agreement with The Williams Companies. Mr. Sachse held various positions while with MAPCO Coal Inc. from 1982 to 1991, and was promoted to President of MAPCO Natural Gas Liquids in 1992. Mr. Sachse holds a Bachelor of Science degree in Business Administration from Trinity University and a Juris Doctorate degree from the University of Tulsa.

Charles R. Wesley has been a Director since January 2009 and Executive Vice President since March 2009. Mr. Wesley has served in a variety of capacities since joining the company in 1974, including as Senior Vice President—Operations from August 1996 through February 2009. Mr. Wesley is a former Chairman of the Board of Directors of the Kentucky Coal Association and also has served the industry as past President of the West Kentucky Mining Institute and National Mine Rescue Association Post 11, and as a director of the Kentucky Mining Institute. Mr. Wesley holds a Bachelor of Science degree in Mining Engineering from the University of Kentucky. The specific experience, qualifications, attributes or skills that led to the conclusion Mr. Wesley should serve as a Director include his long history of significant involvement in the coal industry, his successful leadership of the Partnership’s operations, and his knowledge and technical expertise in all aspects of producing and marketing coal.

Thomas M. Wynne has been Senior Vice President and Chief Operating Officer since March 2009. Mr. Wynne joined the company in 1981 as a mining engineer and has held a variety of positions with the company prior to his appointment in July 1998 as Vice President—Operations. Mr. Wynne has served the coal industry on the National Executive Committee for National Mine Rescue and previously as a member of the Coal Safety Committee for the National Mining Association. Mr. Wynne holds a Bachelor of Science degree in Mining Engineering from the University of Pittsburgh and a Masters of Business Administration degree from West Virginia University.

Michael J. Hall became a Director in March 2003. Mr. Hall is Chairman of the Board of Directors of Matrix Service Company (“Matrix”) (NASDAQ: MTRX). Previously, Mr. Hall served as President and Chief Executive Officer of Matrix from March 2005 until he retired in November 2006. Mr. Hall also served as Vice President—Finance and Chief Financial Officer, Secretary and Treasurer of Matrix from September 1998 to May 2004. Mr. Hall became a Director of Matrix in October 1998, and was elected Chairman of its Board in November 2006. Matrix is a company which provides general industrial construction and repair and maintenance services principally to the petroleum, petrochemical, power, bulk storage terminal, pipeline and industrial gas industries. Prior to working for Matrix, Mr. Hall was Vice President and Chief Financial Officer of Pexco Holdings, Inc., Vice President—Finance and Chief Financial Officer for Worldwide Sports & Recreation, Inc., an affiliated company of Pexco, and worked for T.D. Williamson, Inc., as Senior Vice President, Chief Financial and Administrative Officer, and Director of Operations—Europe, Africa and Middle East Region. Mr. Hall was a member and Chairman of the Board of Directors of Integrated Electrical Services, Inc. (NASDAQ: IESC) and served in that capacity from May 2006 to February 2011, and was a member of its audit, compensation and nominating/governance committees. Mr. Hall served as Chairman of the Board of Directors of American Performance Funds, was a member of its audit and nominating committees and served as independent trustee from July 1990 to May 2008. Mr. Hall holds a Bachelor of Science degree in Accounting from Boston College and a Masters of Business Administration from Stanford University. Mr. Hall is Chairman of the Audit Committee and a member of the Compensation Committee. Since March 2006, Mr. Hall has also been a Director and Chairman of the audit committee of AGP, the general partner of AHGP. The specific experience, qualifications, attributes or skills that led to the conclusion Mr. Hall should serve as a Director include his long history of service in senior corporate leadership positions, his significant knowledge of the energy industry, and his extensive expertise and experience in financial reporting matters gained from his service as Chief Financial Officer of public companies.

 

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John P. Neafsey has served as Chairman of the Board of Directors since June 1996. Mr. Neafsey is President of JN Associates, an investment consulting firm formed in 1993. Mr. Neafsey served as President and CEO of Greenwich Capital Markets from 1990 to 1993 and a Director since its founding in 1983. Positions that Mr. Neafsey held during a 23-year career at The Sun Company include Director; Executive Vice President responsible for Canadian operations, Sun Coal Company and Helios Capital Corporation; Chief Financial Officer; and other executive and director positions with numerous subsidiary companies. He is or has been active in a number of organizations, including the following: Director and Chairman of the audit committee for The West Pharmaceutical Services Company and former Chairman and a member of the audit and compensation committees of Constar, Inc., former Chairman and member of the audit and compensation committees of NES Rentals, Inc., Trustee Emeritus and Presidential Counselor, Cornell University, and Overseer of Cornell-Weill Medical Center. Mr. Neafsey holds Bachelor and Masters of Science degrees in Engineering and a Masters of Business Administration degree from Cornell University. Mr. Neafsey is Chairman of the Conflicts Committee and a member of the Compensation Committee. The specific experience, qualifications, attributes or skills that led to the conclusion Mr. Neafsey should serve as a Director include his extensive service in senior corporate leadership positions in both the energy and financial services industries, and his technical expertise, knowledge and experience with financial markets.

John H. Robinson became a Director in December 1999. Mr. Robinson is Chairman of Hamilton Ventures, LLC. From 2003 to 2004, he was Chairman of EPC Global, Ltd., an engineering staffing company. From 2000 to 2002, he was Executive Director of Amey plc, a British business process outsourcing company. Mr. Robinson served as Vice Chairman of Black & Veatch, Inc. from 1998 to 2000. He began his career at Black & Veatch in 1973 and was a General Partner and Managing Partner prior to becoming Vice Chairman when the firm incorporated. Mr. Robinson is a Director of Coeur d’Alene Mining Corporation and a member of its executive and audit committees and chairman of its compensation committees, and he is a Director of the Federal Home Loan Bank of Des Moines, also serving on its audit and compensation committees. Mr. Robinson is also a Director of Olsson Associates. He holds Bachelor and Masters of Science degrees in Engineering from the University of Kansas and is a graduate of the Owner-President-Management Program at the Harvard Business School. He is Chairman of the Compensation Committee and a member of the Audit and Conflicts Committees. The specific experience, qualifications, attributes or skills that led to the conclusion Mr. Robinson should serve as a Director include his significant experience in the engineering and consulting industries, his extensive service in senior corporate leadership positions in both industries and his familiarity with financial matters.

Wilson M. Torrence became a Director in January 2007. Mr. Torrence retired from Fluor Corporation in 2006 as a Senior Vice President of Project Development and Investments and since that time has performed investment and business consulting services for various clients. Mr. Torrence was employed at Fluor from 1989 to 2006 where, among other roles, he was responsible for the global Project Development, Investment and Structured Finance Group and served as Chairman of Fluor’s Investment Committee. In that position, Mr. Torrence had executive responsibility for Fluor’s global activities in developing and arranging third-party financing for some of Fluor’s clients’ construction projects. Prior to joining Fluor in 1989, Mr. Torrence was President and CEO of Combustion Engineering Corporation’s Waste to Energy Division and, during that time, also served as Chairman of the Institute of Resource Recovery, a Washington-based industry advocacy organization. Mr. Torrence began his career at Mobil Oil Corporation, where he held several executive positions, including Assistant Treasurer of Mobil’s International Marketing and Refining Division and Chief Financial Officer of Mobil Land Development Company. More recently, from October 2006 to March 2007, Mr. Torrence served as Chief Financial Officer and as a Director of Cleantech America, LLC, a private company involved in development of central station solar generating plants. Mr. Torrence holds Bachelor and Masters degrees in Business Administration from Virginia Tech University. Mr. Torrence is a member of the Audit, Compensation and Conflicts Committees. The specific experience, qualifications, attributes or skills that led to the conclusion Mr. Torrence should serve as a Director include his extensive experience in the construction and energy businesses, his senior corporate finance-related and other leadership positions and his participation in numerous financing transactions.

 

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Board of Directors

The leadership structure of our Board of Directors has been consistent since the Partnership’s inception. Our President and Chief Executive Officer is a member of our Board of Directors but is not its Chairman, and our Chairman is an independent Director. We believe this structure is appropriate for the Partnership because it allows for leadership of the Board of Directors that is independent of management, enhancing the effectiveness of the Board of Directors’ oversight.

Our Board of Directors generally administers its risk oversight function through the board as a whole. Our President and Chief Executive Officer, who reports to the Board of Directors, and the other executives named above, who report to our President and Chief Executive Officer, have day-to-day risk management responsibilities. At the Board of Director’s request, each of these executives attends the meetings of our Board of Directors, where the Board of Directors routinely receives reports on our financial results, the status of our operations and our safety performance, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management. In addition, management provides a monthly report of the Partnership’s financial and operational performance to each member of the Board of Directors, which often prompts questions or feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from the Partnership’s internal auditor, who reports directly to the Audit Committee, and reviews the Partnership’s contingencies, significant transactions and subsequent events, among other matters, with management and our independent auditors.

The Board of Directors has selected as director nominees individuals with experience, skills and qualifications relevant to the business of the Partnership, such as experience in energy or related industries or with financial markets, expertise in mining, engineering or finance, and a history of service in senior leadership positions. The Board of Directors has not established a formal process for identifying director nominees, nor does it have a formal policy regarding consideration of diversity in identifying director nominees, but has endeavored to assemble a diverse group of individuals with the qualities and attributes required to provide effective oversight of the Partnership.

Audit Committee

The Audit Committee comprises three non-employee members of the Board of Directors (currently, Mr. Hall, Mr. Robinson and Mr. Torrence). After reviewing the qualifications of the current members of the Audit Committee, and any relationships they may have with us that might affect their independence, the Board of Directors has determined that all current Audit Committee members are “independent” as that concept is defined in Section 10A of the Exchange Act, all current Audit Committee members are “independent” as that concept is defined in the applicable rules of NASDAQ Stock Market, LLC, all current Audit Committee members are financially literate, and Mr. Hall qualifies as an “audit committee financial expert” under the applicable rules promulgated pursuant to the Exchange Act.

Report of the Audit Committee

The Audit Committee of our MGP oversees our financial reporting process on behalf of the Board of Directors. Management has primary responsibility for the financial statements and the reporting process including the systems of internal controls. The Audit Committee has responsibility for the appointment, compensation and oversight of the work of our independent registered public accounting firm and assists the Board of Directors by conducting its own review of our:

 

   

filings with the SEC pursuant to the Securities Act of 1933 (the “Securities Act”) and the Exchange Act (i.e., Forms 10-K, 10-Q, and 8-K);

 

   

press releases and other communications by us to the public concerning earnings, financial condition and results of operations, including changes in distribution policies or practices affecting the holders of our units, if such review is not undertaken by the Board of Directors;

 

   

systems of internal controls regarding finance and accounting that management and the Board of Directors have established; and

 

   

auditing, accounting and financial reporting processes generally.

 

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In fulfilling its oversight and other responsibilities, the Audit Committee met nine times during 2010. The Audit Committee’s activities included, but were not limited to, (a) selecting the independent registered public accounting firm, (b) meeting periodically in executive session with the independent registered public accounting firm, (c) reviewing the Quarterly Reports on Form 10-Q for the three months ended March 31, June 30, and September 30, 2010, (d) performing a self-assessment of the committee, (e) reviewing the Audit Committee charter, and (f) reviewing the overall scope, plans and findings of our internal auditor. Based on the results of the annual self-assessment, the Audit Committee believes that it satisfied the requirements of its charter. The Audit Committee also reviewed and discussed with management and the independent registered public accounting firm this Annual Report on Form 10-K, including the audited financial statements.

Our independent registered public accounting firm, Deloitte & Touche LLP, is responsible for expressing an opinion on the conformity of the audited financial statements with generally accepted accounting principles. The Audit Committee reviewed with Deloitte & Touche LLP its judgment as to the quality, not just the acceptability, of our accounting principles and such other matters as are required to be discussed with the Audit Committee under generally accepted auditing standards.

The Audit Committee discussed with Deloitte & Touche LLP the matters required to be discussed by the Statement of Auditing Standards (“SAS”) 114, The Auditor’s Communication with Those Charged with Governance, as may be modified or supplemented. The Audit Committee received written disclosures and the letter from Deloitte & Touche LLP required by applicable requirements of the Public Company Accounting Oversight Board regarding the independent accountant’s communication with the audit committee regarding independence, and has discussed with Deloitte & Touche LLP its independence from management and the ARLP Partnership.

Based on the reviews and discussions referred to above, the Audit Committee recommended to the Board of Directors that the audited financial statements be included in the Annual Report on Form 10-K for the year ended December 31, 2010 for filing with the SEC.

 

Members of the Audit Committee:
Michael J. Hall, Chairman
John H. Robinson
Wilson M. Torrence

Code of Ethics

We have adopted a code of ethics with which our President and Chief Executive Officer and our senior financial officers (including our principal financial officer and our principal accounting officer or controller) are expected to comply. The code of ethics is publicly available on our website under “Investor Information” at www.arlp.com and is available in print without charge to any unitholder who requests it. Such requests should be directed to Investor Relations at (918) 295-7674. If any substantive amendments are made to the code of ethics or if there is a grant of a waiver, including any implicit waiver, from a provision of the code to our President and Chief Executive Officer, chief financial officer, chief accounting officer or controller, we will disclose the nature of such amendment or waiver on our website or in a report on Form 8-K.

Communications with the Board

Unitholders or other interested parties can contact any director or committee of the Board of Directors by writing to them c/o Senior Vice President, General Counsel and Secretary, P. O. Box 22027, Tulsa, Oklahoma 74121-2027. Comments or complaints relating to our accounting, internal accounting controls or auditing matters will also be referred to members of the Audit Committee. The Audit Committee has procedures for (a) receipt, retention and treatment of complaints received by us regarding accounting, internal accounting controls, or auditing matters and (b) the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters.

 

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Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act, as amended, requires directors, executive officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC initial reports of ownership and reports or changes in ownership of such equity securities. Such persons are also required to furnish us with copies of all Section 16(a) forms they file. Based upon a review of the copies of the forms furnished to us and written representations from certain reporting persons, we believe that during 2010 none of our officers and directors were delinquent with respect to any of the filing requirements under Rule 16(a) other than Mr. Robinson who did not timely file a Form 4 related to his sale of 4,300 units in March 2010, but has since filed a Form 4 with respect to this transaction.

Reimbursement of Expenses of our Managing General Partner and its Affiliates

Our managing general partner does not receive any management fee or other compensation in connection with its management of us. Our managing general partner is reimbursed by us for all expenses incurred on our behalf. Please see “Item 13.—Certain Relationships and Related Transactions, and Director Independence—Administrative Services.”

 

ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Introduction

The Compensation Committee oversees the compensation of our managing general partner’s executive officers, including the President and Chief Executive Officer, our principal executive officer, the Senior Vice President and Chief Financial Officer, our principal financial officer, and the three most highly compensated executive officers in 2010, each of whom is named in the Summary Compensation Table (collectively, our “Named Executive Officers”). Our Named Executive Officers are employees of our operating subsidiary, Alliance Coal. Certain of our Named Executive Officers devote a portion of their time to the business of one or more related parties and, to the extent they do so, Alliance Coal is reimbursed for such services by those related parties pursuant to an administrative services agreement. Please see “Item 13.—Certain Relationships and Related Transactions, and Director Independence—Administrative Services. We do not have employment agreements with any of our Named Executive Officers.

Compensation Objectives and Philosophy

The compensation of our Named Executive Officers is designed to achieve two key objectives: (i) provide a competitive compensation opportunity to allow us to recruit and retain key management talent, and (ii) motivate and reward the executive officers for creating sustainable, capital-efficient growth in available cash to maximize our distributions to our unitholders. In making decisions regarding executive compensation, the Compensation Committee reviews current compensation levels of other companies in the coal industry and other peers, considers our President and Chief Executive Officer’s assessment of each of the other executives, and uses its discretion to determine an appropriate total compensation package of base salary and short-term and long-term incentives. The Compensation Committee intends for each executive officer’s total compensation to be competitive in the marketplace and to effectively motivate the officer. Based upon its review of our overall executive compensation program, the Compensation Committee believes the program is appropriately applied to our managing general partner’s executive officers and is necessary to attract and retain the executive officers who are essential to our continued development and success, to compensate those executive officers for their contributions and to enhance unitholder value. Moreover, the Compensation Committee believes the total compensation opportunities provided to our managing general partner’s executive officers create alignment with our long-term interests and those of our unitholders. As a result, we do not maintain unit ownership requirements for our Named Executive Officers.

Setting Executive Compensation

Role of the Compensation Committee

The Compensation Committee discharges the Board of Directors’ responsibilities relating to our managing general partner’s executive compensation program. The Compensation Committee oversees our compensation and benefit plans

 

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and policies, administers our incentive bonus and equity participation plans, and reviews and approves annually all compensation decisions relating to our Named Executive Officers. The Compensation Committee is empowered by the Board of Directors and by the Compensation Committee’s charter to make all decisions regarding compensation for our Named Executive Officers without ratification or other action by the Board of Directors. The Compensation Committee has authority to secure services for executive compensation matters, legal advice, or other expert services, both from within and outside the company. While the Compensation Committee is empowered to delegate all or a portion of its duties to a subcommittee, it has not done so.

The Compensation Committee comprises of all of our directors who have been determined to be “independent” by the Board of Directors in accordance with applicable NASDAQ Stock Market, LLC and SEC regulations, presently Messrs. Robinson, Hall, Neafsey and Torrence.

Role of Executive Officers

Each year, the President and Chief Executive Officer submits recommendations to the Compensation Committee for adjustments to the salary, bonuses and long-term equity incentive awards payable our Named Executive Officers, excluding himself. The President and Chief Executive Officer bases his recommendations on his assessment of each executive’s performance, experience, demonstrated leadership, job knowledge and management skills. The Compensation Committee considers the recommendations of the President and Chief Executive Officer as one factor in making compensation decisions regarding our Named Executive Officers. Historically, and in 2010, the Compensation Committee and the President and Chief Executive Officer have been substantially aligned on decisions regarding compensation of the Named Executive Officers. As executive officers are promoted or hired during the year, the President and Chief Executive Officer makes compensation recommendations to the Compensation Committee and works closely with the Compensation Committee to ensure that all compensation arrangements for executive officers are consistent with our compensation philosophy and are approved by the Compensation Committee. At the direction of the Compensation Committee, the President and Chief Executive Officer and the Senior Vice President, General Counsel and Secretary attend certain meetings of the Compensation Committee.

Role of Compensation Consultants

The Compensation Committee engaged Mercer (US) Inc. (“Mercer”) as an outside compensation consultant to assist it in collecting and analyzing peer group compensation information and in assessing the competitiveness of our compensation program in 2010. Mercer took instructions from and reported to the Chairman of the Compensation Committee. Mercer reviewed published survey data and peer group proxy information, and provided a comparative analysis of competitive practices regarding base salaries, short-term incentives, total cash compensation, long-term incentives and total direct compensation.

Mercer analyzed survey sources published by Mercer and Watson Wyatt to collect compensation data for companies of similar size based on annual revenue. Mercer’s peer group proxy analysis included Peabody Energy Corp, CONSOL Energy Inc., Arch Coal, Inc., Massey Energy Company, Alpha Natural Resources Inc., Foundation Coal Holdings Inc., Patriot Coal Corp., International Coal Group Inc., James River Coal Company and Westmoreland Coal Company. This peer group was selected by Mercer and approved by the Compensation Committee. Mercer did not provide any non-executive compensation services for us or our managing general partner during 2010.

Use of Peer Group Comparisons and Survey Data

The Compensation Committee believes that it is important to review and compare our performance with that of peer companies in the coal industry, and reviews the composition of the peer group annually. In setting executive compensation in 2010, the Compensation Committee reviewed the compensation information compiled by Mercer. The Compensation Committee uses the peer group and survey data as a point of reference for comparative purposes, but it is not the determinative factor for the compensation of our Named Executive Officers. The Compensation Committee exercises discretion in determining the nature and extent of the use of comparative pay data.

Consideration of Equity Ownership

Mr. Craft, the President and Chief Executive Officer, is evaluated and treated differently with respect to compensation than our other Named Executive Officers. Mr. Craft and his related entities own significant equity positions in AHGP, which owns MGP, the IDR in ARLP and, as of December 31, 2010, 42.3% of ARLP’s outstanding common units. Because

 

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of these ownership positions, the interests of Mr. Craft are directly aligned with those of our unitholders. Mr. Craft has not received an increase in base salary since 2002 and has not received a bonus under our short-term incentive plan (“STIP”) or any grants of LTIP awards since 2005.

Compensation Components

Overview

The principal components of compensation for our Named Executive Officers include:

 

   

base salary;

 

   

annual cash incentive bonus awards under the STIP; and

 

   

awards of restricted units under the LTIP.

The relative amount of each component is not based on any formula, but rather is based on the recommendation of the President and Chief Executive Officer, subject to the discretion of the Compensation Committee to make any modifications it deems appropriate.

Each of our Named Executive Officers also receives supplemental retirement benefits through the SERP. In addition, all executive officers are entitled to customary benefits available to our employees generally, including group medical, dental, and life insurance and participation in our profit sharing and savings plan (“PSSP”). Our PSSP is a defined contribution plan and includes an employer matching contribution of 75% on the first 3% of eligible compensation (as defined by the IRS) contributed by the employee, an employer non-matching contribution of 0.75% of eligible compensation, and an employer supplemental contribution of 5% of eligible compensation.

Base Salary

When reviewing base salaries, the Compensation Committee’s policy is to consider the individual’s experience, tenure and performance, the individual’s level of responsibility, the position’s complexity and its importance to us in relation to other executive positions, our financial performance, and competitive pay practices. The Compensation Committee also considers comparative compensation data of companies in our peer group and the recommendation of the President and Chief Executive Officer of our managing general partner. Base salaries are reviewed annually to ensure continuing consistency with market levels, and adjustments to base salaries are made as needed to reflect movement in the competitive market as well as individual performance.

Annual Cash Incentive Bonus Awards

The STIP is designed to assist us in attracting, retaining and motivating qualified personnel by rewarding management, including our Named Executive Officers, and selected other salaried employees with cash awards for our achievement of an annual financial performance target. The annual performance target is recommended by the President and Chief Executive Officer and approved by the Compensation Committee, typically in January of each year. The performance measure is subject to equitable adjustment in the sole discretion of the Compensation Committee to reflect the occurrence of any significant events during the year.

The performance target historically has been EBITDA-derived, with items added or removed from the EBITDA calculation to ensure that the performance target reflects the pure operating results of the core mining business. (EBITDA is defined as net income of ARLP before net interest expense, income taxes, depreciation, depletion and amortization and net income attributable to noncontrolling interest.) The aggregate cash available for awards under the STIP each year is dependent on our actual financial results for the year compared to the annual performance target, and it increases in relationship to our EBITDA, as adjusted, exceeding the minimum threshold. The Compensation Committee may determine satisfactory results and adjust the size of the pay-out pool in its sole discretion. In 2010, the Compensation Committee approved a minimum financial performance target of $360.6 million in EBITDA from current operations, normalized by excluding any charges for unit-based compensation and affiliate contributions, if any, and we exceeded the minimum target.

Awards to our Named Executive Officers each year are determined by and in the discretion of the Compensation Committee. As it does when reviewing base salaries, in determining individual awards under the STIP the Compensation

 

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Committee considers its assessment of the individual’s performance, comparative compensation data of companies in our peer group and the recommendation of the President and Chief Executive Officer. The compensation expense associated with STIP awards is recognized in the year earned, with the cash awards payable in the first quarter of the following calendar year. Termination of employment of an executive officer for any reason prior to payment of a cash award will result in forfeiture of any right to the award, unless and to the extent waived by the Compensation Committee in its discretion.

The performance measure for the STIP in 2011 will be EBITDA for current operations, excluding charges for unit-based compensation and affiliate contributions, if any. As discussed above, the Compensation Committee may, in its discretion, make equitable adjustments to the performance criteria under the STIP and adjust the amount of the aggregate pay-out. The Compensation Committee believes that the STIP performance criteria for 2011 will be reasonably difficult to achieve and therefore support our key compensation objectives discussed above.

Equity Awards under the LTIP

Equity compensation pursuant to the LTIP is a key component of our executive compensation program. Our LTIP is sponsored by Alliance Coal. Under the LTIP, grants may be made of either (a) restricted units or (b) options to purchase common units, although to date, no grants of options have been made. The Compensation Committee has authority to determine the participants to whom restricted units are granted, the number of restricted units to be granted to each such participant, and the conditions under which the restricted units may become vested, including the duration of any vesting period. Annual grant levels for designated participants (including our Named Executive Officers) are recommended by our managing general partner’s President and Chief Executive Officer, subject to review and approval by the Compensation Committee. Grant levels are intended to support the objectives of the comprehensive compensation package described above. The LTIP grants provide our Named Executive Officers with the opportunity to achieve a meaningful ownership stake in the Partnership, thereby assuring that their interests are aligned with our success. However, as noted above, because Mr. Craft’s interests are directly aligned with the interests of our unitholders as a result of his ownership positions, Mr. Craft has not been granted any awards under the LTIP since 2005. There is no formula for determining the size of awards to any individual recipient and, as it does when reviewing base salaries and individual STIP payments, the Compensation Committee considers its assessment of the individual’s performance, compensation levels at peer companies in the coal industry and the recommendation of the President and Chief Executive Officer. Amounts realized from prior grants, including amounts realized due to changes in the value of our common units, are not considered in setting grant levels or other compensation for our Named Executive Officers.

Restricted Units. Restricted units granted under the LTIP are “phantom” or notional units that upon vesting entitle the participant to receive an ARLP common unit. Restricted units granted under the LTIP vest at the end of a stated period from the grant date (which is currently approximately three years for all outstanding restricted units), provided we achieve an aggregate performance target for that period. However, if a grantee’s employment is terminated for any reason prior to the vesting of any restricted units, those restricted units will be automatically forfeited, unless the Compensation Committee, in its sole discretion, determines otherwise. The number of units actually distributed upon satisfaction of the applicable vesting requirements is reduced to cover the minimum statutory income tax withholding requirement for each individual participant based upon the fair market value of the common units as of the date of distribution. Pursuant to the distribution equivalent rights provision of the LTIP, all grants of restricted units include the contingent right to receive quarterly cash distributions in an amount equal to the cash distributions we make to unitholders during the vesting period.

The performance target applicable to restricted unit awards under the LTIP is based on a normalized EBITDA measure, with that measure typically being the same as the STIP measure for the year of the grant. The target, however, requires achieving an aggregate performance level for the three-year period. Historically, we have issued grants under the LTIP at the beginning of each year, with the exceptions of new employees who begin employment with us at some other time and job promotions that may occur at some other time. In 2008, we also issued grants in October in lieu of issuing grants at the beginning of 2009. The compensation expense associated with LTIP grants is recognized over the vesting period in accordance with FASB ASC 718, Compensation – Stock Compensation.

Our managing general partner’s policy is to grant restricted units pursuant to the LTIP to serve as a means of incentive compensation for performance. Therefore, no consideration will be payable by the LTIP participants upon receipt of the common units. Common units to be delivered upon the vesting of restricted units may be common units acquired by us in the open market, common units acquired by us from any other person, common units already owned or newly issued by us, or any combination of the foregoing. If we issue new common units upon payment of the restricted units instead of purchasing them, the total number of common units outstanding will increase.

 

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The most recent grants under the LTIP, made January 25, 2011, will cliff vest on January 1, 2014 provided we achieve a target level of aggregate EBITDA for current operations, excluding charges for unit-based compensation, if any, for the period January 1, 2011 through December 31, 2013. The LTIP provides the Compensation Committee with discretion to determine the conditions for vesting (as well as all other terms and conditions) associated with any award under the plan, and to amend any of those conditions so long as an amendment does not materially reduce the benefit to the participant. The Compensation Committee believes the performance-related vesting conditions of all outstanding awards under the LTIP will be reasonably difficult to satisfy and therefore support our key compensation objectives discussed above.

Unit Options. We have not made any grants of unit options. The Compensation Committee, in the future, may decide to make unit option grants to employees and directors on terms determined by the Compensation Committee.

Grant Timing. The Compensation Committee does not time, nor has the Compensation Committee in the past timed, the grant of LTIP awards in coordination with the release of material non-public information. Instead, LTIP awards are granted only at the time or times dictated by our normal compensation process as developed by the Compensation Committee.

Effect of a Change in Control. Upon a “change in control” as defined in the LTIP, all awards outstanding under the LTIP will automatically vest and become payable or exercisable, as the case may be, in full. Please see “Item 11. Executive Compensation—Potential Payments Upon a Termination or Change of Control.”

Amendments and Termination. Our Board of Directors or the Compensation Committee may, in its discretion, terminate the LTIP at any time with respect to any common units for which a grant has not previously been made. Except as required by the rules of the exchange on which the common units may be listed at that time, our Board of Directors or the Compensation Committee may alter or amend the LTIP in any manner from time to time; provided, however, that no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the affected participant. In addition, our Board of Directors or the Compensation Committee may, in its discretion, establish such additional compensation and incentive arrangements as it deems appropriate to motivate and reward our employees.

Supplemental Executive Retirement Plan

We maintain the SERP to help attract and motivate key employees, including our Named Executive Officers. The SERP is sponsored by Alliance Coal. Participation in the SERP aligns the interest of each Named Executive Officer with the interests of our unitholders because all allocations made to participants under the SERP are made in the form of notional common units of ARLP, defined in the SERP as “phantom units.” The Compensation Committee approves the SERP participants and their percentage allocations, and can amend or terminate the SERP at any time. All of our Named Executive Officers currently participate in the SERP.

Under the terms of the SERP, a participant is entitled to receive on December 31 of each year an allocation of phantom units having a fair market value equal to his or her percentage allocation multiplied by the sum of the participant’s base salary and cash bonus received that year, then reduced by any supplemental contribution that was made to our defined contribution PSSP for the participant that year. A participant’s cumulative notional phantom unit account balance earns the equivalent of common unit distributions, which are added to the notional account balance in the form of additional phantom units. All amounts granted under the SERP vest immediately and, with respect to terminations from employment occurring after January 1, 2011, are paid out upon the participant’s termination from employment in ARLP common units equal to the number of phantom units then credited to the participant’s account, less the number of units required to satisfy our tax withholding obligations; provided that a participant in the SERP shall not be entitled to an allocation for the year in which the participant’s termination from employment occurs, except as described in the following paragraph.

A participant in the SERP, including any of our Named Executive Officers, is entitled to receive an allocation under the SERP for the year in which his employment is terminated only if such termination results from one of the following events:

 

  (1) the participant’s employment is terminated other than for “cause”

 

  (2) the participant terminates employment for “good reason”

 

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  (3) a change of control of us or our managing general partner occurs and, as a result, the participant’s employment is terminated (whether voluntary or involuntary);

 

  (4) death of the participant;

 

  (5) the participant attains (or has attained) retirement age of 65 years; or

 

  (6) the participant incurs a total and permanent disability, which shall be deemed to occur if the participant is eligible to receive benefits under the terms of the long-term disability program maintained by us.

This allocation for the year in which a participant’s termination occurs shall equal the participant’s eligible compensation for such year (including any severance amount, if applicable) multiplied by his percentage allocation under the SERP, reduced by any supplemental contribution that was made to our defined contribution PSSP for the participant that year.

Other Compensation-Related Matters

Trading in Derivatives

It is our managing general partner’s policy that directors and all officers, including the Named Executive Officers, may not purchase or sell options on ARLP’s common units.

Tax Deductibility of Compensation

With respect to the deduction limitations imposed under Section 162(m) of the Internal Revenue Code, we are a limited partnership and do not meet the definition of a “corporation” under Section 162(m). Accordingly, such limitations do not apply to compensation paid to our Named Executive Officers.

Compensation Committee Report

The Compensation Committee has submitted the following report for inclusion in this Annual Report on Form 10-K:

Our Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis contained in this Annual Report on Form 10-K with management. Based on our Compensation Committee’s review of and the discussions with management with respect to the Compensation Discussion and Analysis, our Compensation Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

The foregoing report is provided by the following directors, who constitute all the members of the Compensation Committee:

 

Members of the Compensation Committee:

John H. Robinson, Chairman

Michael J. Hall

John P. Neafsey

Wilson M. Torrence

Notwithstanding anything to the contrary set forth in any of our previous filings under the Securities Act or the Exchange Act, that incorporate future filings, including this Annual Report on Form 10-K, in whole or in part, the foregoing Compensation Committee Report shall not be deemed to be filed with the SEC or incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference.

 

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Summary Compensation Table for 2010

 

Name and Principal Position   Year     Salary (2)     Bonus (3)     Unit
Awards (4)
    Option
Awards (1)
    Non-Equity
Incentive Plan
Compensation (5)
    Change in
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings (1)
    All Other
Compensation (6)
    Total  

Joseph W. Craft III,

    2010      $ 334,828      $ —        $ —        $ —        $ —        $ —        $ 288,579      $ 623,407   

President, Chief Executive Officer and Director

    2009        341,267        —          —          —          —          —          197,634        538,901   
    2008        334,828        —          —          —          —          —          163,909        498,737   

Brian L. Cantrell,

    2010        237,269        —          227,268        —          370,000        —          43,599        878,136   

Senior Vice President - Chief Financial Officer

    2009        233,873        —          —          —          175,000        —          40,724        449,597   
    2008        218,619        —          409,482        —          170,000        —          33,848        831,949   

R. Eberley Davis

    2010        260,473        —          227,268        —          370,000        —          54,920        912,661   

Senior Vice President, General Counsel and Secretary

    2009        254,442        70,000        —          —          185,000        —          56,906        566,348   
    2008        236,369        70,000        409,482        —          180,000        —          46,510        942,361   

Robert G. Sachse,

    2010        283,577        —          350,837        —          390,000        —          84,419        1,108,833   

Executive Vice President-Marketing

    2009        280,148        —          —          —          220,000        —          75,349        575,497   
    2008        261,971        —          409,482        —          190,000        —          52,412        913,865   

Thomas M. Wynne,

    2010        305,384        —          332,828          390,000        —          50,173        1,078,385   

Senior Vice President and Chief Operating Officer

    2009        264,807        —          175,988          200,000        —          54,387        695,182   
    2008        197,992        —          —          —          155,000        —          30,417        383,409   

 

(1) Column is not applicable.
(2) Certain of our Named Executive Officers devote a portion of their time to the business of one or more related parties and, to the extent they do so, the base salary of those executive officers is reimbursed to Alliance Coal by those related parties pursuant to an administrative services agreement. Please see “Item 1. Business—Employees—Administrative Services Agreement.” In 2010, the percentage of base salary reimbursed to Alliance Coal was 5% for Mr. Craft, 4% for Mr. Cantrell and 8% for Mr. Davis. In 2009, the percentage of base salary reimbursed to Alliance Coal was 5% for Mr. Craft, 6% for Mr. Cantrell, 8.5% for Mr. Davis, and 1% for Mr. Sachse. In 2008, the percentage of base salary reimbursed to Alliance Coal was 5% for Mr. Craft, 12% for Mr. Cantrell, 14% for Mr. Davis and 1% for Mr. Sachse.
(3) Amounts represent a retention bonus paid to Mr. Davis in 2009 and 2008.
(4) The Unit Awards represent the aggregate grant date fair value of equity awards granted (computed in accordance with FASB ASC 718) to each Named Executive Officer under the LTIP in the respective year. Please see “Item 11. Compensation Discussion and Analysis—Compensation Program Components—Equity Awards under the LTIP.” Messrs. Cantrell, Davis and Sachse received awards in January 2008 and October 2008. The Compensation Committee approved the awards in October 2008 in lieu of making awards in January 2009. The October 2008 awards increased the 2008 Unit Awards total for each of Messrs. Cantrell, Davis and Sachse by $199,928, based on the grant date fair value.
(5) Amounts represent the STIP bonus earned for the respective year. STIP payments are made in the first quarter of the year following the year in which they are earned. Other than this bonus, there were no other applicable bonuses earned or deferred associated with year 2010. Please see “Item 11. Compensation Discussion and Analysis—Compensation Program Components—Annual Incentive Bonus Awards.”

 

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(6) For all Named Executive Officers, the amounts represent the sum of the (a) SERP phantom unit contributions valued at the market closing price of our common units on the date the phantom unit was granted, (b) profit sharing savings plan employer contribution and (c) perquisites in excess of $10,000. A reconciliation of the amounts shown is as follows:

 

     Year      SERP      Profit
Sharing
Plan
Employer
Contribution
     Perquisites (a)      Total  

Joseph W. Craft

     2010       $ 205,058       $ 19,600       $ 63,921       $ 288,579   
     2009         178,034         19,600         —           197,634   
     2008         145,627         18,282         —           163,909   

Brian L. Cantrell

     2010         24,617         18,982         —           43,599   
     2009         22,014         18,710         —           40,724   
     2008         18,064         15,784         —           33,848   

R. Eberley Davis

     2010         35,320         19,600         —           54,920   
     2009         37,306         19,600         —           56,906   
     2008         29,208         17,302         —           46,510   

Robert G. Sachse

     2010         49,260         19,600         15,559         84,419   
     2009         41,854         19,600         13,895         75,349   
     2008         34,012         18,400         —           52,412   

Thomas M. Wynne

     2010         30,573         19,600         —           50,173   
     2009         22,582         19,600         12,205         54,387   
     2008         16,810         13,607         —           30,417   

 

a) For Mr. Craft, the 2010 amount includes perquisites and other personal benefits totaling $63,921, comprising club dues of $8,621 and tax preparation fees of $55,300. For Mr. Sachse, the 2010 amount includes perquisites and other personal benefits totaling $15,559, comprising club dues of $6,479 and tax preparation fees of $9,080 and the 2009 amount includes perquisites and other personal benefits totaling $13,895, comprising club dues of $8,150 and tax preparation fees of $5,745. For Mr. Wynne, the 2009 amount includes perquisites and other personal benefits totaling $12,205, all of which were tax preparation fees.

 

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Grants of Plan-Based Awards Table for 2010

 

     Grant   Approved   Estimated Future Payouts
Under Non-Equity Incentive
Plan Awards
  Estimated Future Payouts Under
Equity Incentive Plan Awards
    All
Other
Unit
Awards:
Number
of
    All Other
Option
Awards:
Number of
Securities
Underlying
    Exercise
or Base
Price of
Options
    Grant
Date Fair
Value of
Unit
 
Name    Date   Date   Threshold (1)   Target (1)   Maximum (1)   Threshold (4)   Target (2)     Maximum (4)     Units (3)     Options (1)     Awards (1)     Awards (5)  

Joseph W. Craft, III

   February 12, 2010   (6)             —            1,092          $ 43,789   
  

May 14, 2010

  (6)             —            974            43,742   
  

August 13, 2010

  (6)             —            914            45,929   
  

November 12, 2010

  (6)             —            820            49,635   
  

December 31, 2010

  January 25, 2011             —            334            21,964   
                                          
                 —            4,134            205,059   
                                          

Brian L. Cantrell

   January 26, 2010   January 26, 2010             5,742          —              227,268   
  

February 12, 2010

  (6)             —            48            1,925   
  

May 14, 2010

  (6)             —            43            1,931   
  

August 13, 2010

  (6)             —            40            2,010   
  

November 12, 2010

  (6)             —            36            2,179   
  

December 31, 2010

  January 25, 2011             —            252            16,572   
                                          
                 5,742          419            251,885   
                                          

R. Eberley Davis

   January 26, 2010   January 26, 2010             5,742          —              227,268   
  

February 12, 2010

  (6)             —            41            1,644   
  

May 14, 2010

  (6)             —            36            1,617   
  

August 13, 2010

  (6)             —            34            1,709   
  

November 12, 2010

  (6)             —            31            1,876   
  

December 31, 2010

  January 25, 2011             —            433            28,474   
                                          
                 5,742          575            262,588   
                                          

Robert G. Sachse

   January 26, 2010   January 26, 2010             8,864          —              350,837   
  

February 12, 2010

  (6)             —            60            2,406   
  

May 14, 2010

  (6)             —            54            2,425   
  

August 13, 2010

  (6)             —            50            2,513   
  

November 12, 2010

  (6)             —            45            2,724   
  

December 31, 2010

  January 25, 2011             —            596            39,193   
                                          
                 8,864          805            400,098   
                                          

Thomas M. Wynne

   January 26, 2010   January 26, 2010             8,409          —              332,828   
  

February 12, 2010

  (6)             —            69            2,767   
  

May 14, 2010

  (6)             —            61            2,740   
  

August 13, 2010

  (6)             —            58            2,915   
  

November 12, 2010

  (6)             —            52            3,148   
  

December 31, 2010

  January 25, 2011             —            289            19,005   
                                          
                 8,409          529            363,403   
                                          

 

(1) Column not applicable.
(2) These awards are grants of restricted units pursuant to our LTIP. Please see “Item 11. Compensation Discussion and Analysis—Compensation Components—Equity Awards under the LTIP.”
(3) These awards are phantom units added to each Named Executive Officer’s SERP notional account balance. Please see “Item 11. Compensation Discussion and Analysis—Compensation Components—Supplemental Executive Retirement Plan.”
(4) Grants of restricted units under our LTIP are not subject to minimum thresholds, targets or maximum payout conditions. However, the vesting of these grants is subject to the satisfaction of certain performance criteria. Please see “Item 11. Compensation Discussion and Analysis—Compensation Components—Equity Awards under the LTIP.”

 

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(5) We calculated the fair value of LTIP awards using a value of $39.59 per unit, the unit price applicable for 2010 grants. We calculated the fair value of SERP phantom unit awards using the market closing price on the date the phantom unit award was granted. Phantom units granted under the SERP vest on the date granted.
(6) In accordance with the provisions of the SERP, a participant’s cumulative notional phantom unit account balance earns the equivalent of common unit distributions when we pay a distribution to our common unitholders, which is added to the account balance in the form of phantom units. These contributions are made in accordance with the SERP plan document, which has been approved by the Compensation Committee. Therefore, these contributions are not separately approved by the Compensation Committee.

Narrative Disclosure Relating to the Summary Compensation Table and Grants of Plan-Based Awards Table

Annual Cash Incentive Bonus Awards

Under the STIP, our Named Executive Officers are eligible for cash awards for our achieving an annual financial performance target. The annual performance target is recommended by the President and Chief Executive Officer of our managing general partner and approved by the Compensation Committee, typically in January of each year. The performance target historically has been EBITDA-derived, with items added or removed from the EBITDA calculation to ensure that the performance target reflects the pure operating results of the core mining business. (EBITDA is calculated as net income of ARLP before net interest expense, income taxes, depreciation, depletion and amortization and net income attributable to noncontrolling interest.) The aggregate cash available for awards under the STIP each year is dependent on our actual financial results for the year compared to the annual performance target. The cash available generally increases in relationship to our EBITDA, as adjusted, exceeding the minimum financial performance target and is subject to adjustment by the Compensation Committee in its discretion. Please see “Item 11. Compensation Discussion and Analysis—Compensation Components—Annual Incentive Bonus Awards.”

Long-Term Incentive Plan

Under the LTIP, grants may be made of either (a) restricted units or (b) options to purchase common units, although to date, no grants of options have been made. Annual grant levels for designated participants (including our Named Executive Officers) are recommended by our managing general partner’s President and Chief Executive Officer, subject to the review and approval of the Compensation Committee. Restricted units granted under the LTIP are “phantom” or notional units that upon vesting entitle the participant to receive an ARLP unit. Restricted units granted under the LTIP vest at the end of a stated period from the grant date (which is currently approximately three years for all outstanding restricted units), provided we achieve an aggregate performance target for that period. The performance target is based on a normalized EBITDA measure, with that measure typically being the same as the STIP measure for the year of the grant. The target, however, requires achieving an aggregate performance level for the three-year period compared to aggregate budgeted performance for the period. Please see “Item 11. Compensation Discussion and Analysis—Compensation Components—Equity Awards under the LTIP.”

Supplemental Executive Retirement Plan

Under the terms of the SERP, participants are entitled to receive on December 31 of each year an allocation of phantom units having a fair market value equal to his or her percentage allocation multiplied by the sum of base salary and cash bonus received that year, then reduced by any supplemental contribution that was made to our defined contribution PSSP for the participant that year. A participant’s cumulative notional phantom unit account balance earns the equivalent of common unit distributions. The calculated distributions are added to the notional account balance in the form of additional phantom units. All amounts granted under the SERP vest immediately and are paid out upon the participant’s termination or death in ARLP common units equal to the number of phantom units then credited to the participant’s account, subject to reduction of the number of units distributed to cover withholding obligations. Please see “Item 11. Compensation Discussion and Analysis—Compensation Components—Supplemental Executive Retirement Plan.”

 

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Salary and Bonus in Proportion to Total Compensation

The following table shows the total of salary and bonus in proportion to total compensation from the Summary Compensation Table:

 

Name    Year      Salary and
Bonus ($)
     Total
Compensation ($)
     Salary and
Bonus as a %
of Total
Compensation
 

Joseph W. Craft III

     2010       $ 334,828       $ 623,407         53.7
     2009         341,267         538,901         63.3
     2008         334,828         498,737         67.1

Brian L. Cantrell

     2010         237,269         878,136         27.0
     2009         233,873         449,597         52.0
     2008         218,619         831,949         26.3

R. Eberley Davis

     2010         260,473         912,661         28.5
     2009         324,442         566,348         57.3
     2008         306,369         942,361         32.5

Robert G. Sachse

     2010         283,577         1,108,833         25.6
     2009         280,148         575,497         48.7
     2008         261,971         913,865         28.7

Thomas M. Wynne

     2010         305,384         1,078,385         28.3
     2009         264,807         695,182         38.1
     2008         197,992         383,409         51.6

Outstanding Equity Awards at Fiscal Year-End 2010 Table

 

Name    Number of
Securities
Underlying
Unexercised
Options
Exercisable (1)
     Number of
Securities
Underlying
Unexercised
Options
Unexerciseable (1)
     Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexercised
Unearned
Options (1)
     Option
Exercise
Price (1)
     Option
Expiration
Date (1)
     Market
Value of
Units
That
Have Not
Vested (1)
     Equity
Incentive
Plan
Awards:
Number of
Unearned
Units or
Other
Rights
That Have
Not
Vested (2)
     Equity
Incentive
Plan
Awards:
Market or
Payout
Value of
Unearned
Units or
Other Rights
That Have
Not
Vested (3)
 

Joseph W. Craft III

                       —         $ —     

Brian L. Cantrell

                       18,667         1,227,542   

R. Eberley Davis

                       18,667         1,227,542   

Robert G. Sachse

                       21,789         1,432,845   

Thomas M. Wynne

                       15,534         1,021,516   

 

(1) Column is not applicable.
(2) Amounts represent restricted units awarded under the LTIP that were not vested as of December 31, 2010. Subject to our achieving financial performance targets, the units vested, or will vest, as follows: For Messrs. Cantrell and Davis, 5,800 units on January 1, 2011, 7,125 units on January 1, 2012 and 5,742 units on January 1, 2013; for Mr. Sachse, 5,800 units on January 1, 2011, 7,125 on January 1, 2012 and 8,864 units on January 1, 2013; and for Mr. Wynne, 7,125 units on January 1, 2012 and 8,409 units on January 1, 2013. Please see “Item 11. Compensation Discussion and Analysis—Compensation Components—Equity Awards under the LTIP.”

 

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(3) Stated values are based on $65.76 per unit, the closing price of our common units on December 31, 2010, the final market trading day of 2010.

Option Exercises and Unit Vested Table for 2010

 

     Option Awards      Unit Awards  
Name    Number of
Units
Acquired on
Exercise (1)
     Value
Realized on
Exercise (1)
     Number of
Units
Acquired on
Vesting (2)
     Value
Realized on
Vesting (2)
 

Joseph W. Craft III

           —         $ —     

Brian L. Cantrell

           5,800         260,884   

R. Eberley Davis

           5,800         260,884   

Robert G. Sachse

           5,800         260,884   

Thomas M. Wynne

           3,700         166,426   

 

(1) Column is not applicable.
(2) Amounts represent the number and value of restricted units granted under the LTIP that vested in 2010. All of these units vested on January 1, 2010 and are valued at $44.98 per unit, the closing price on January 4, 2010, the first market trading date of 2010. Please see “Item 11. Compensation Discussion and Analysis—Compensation Components—Equity Awards under the LTIP.”

Pension Benefits Table for 2010

 

Name    Plan
Name
     Year      Number
of Years
Credited
Service (1)
     Present
Value of
Accumulated
Benefit (2)
     Payments
During
Last
Fiscal
Year
 

Joseph W. Craft III

     SERP         2010          $ 3,966,117       $ —     

Brian L. Cantrell

     SERP         2010            187,416         —     

R. Eberley Davis

     SERP         2010            173,738         —     

Robert G. Sachse

     SERP         2010            254,360         —     

Thomas M. Wynne

     SERP         2010            265,473         —     

 

(1) Column not applicable because no provision of the SERP is affected by years of service.
(2) Amounts represent the Named Executive Officer’s cumulative notional account balance of phantom units valued at $65.76, the closing price of our common units on December 31, 2010, the final market trading day of 2010. Please see “Item 11. Compensation Discussion and Analysis—Compensation Components—Supplemental Executive Retirement Plan.”

 

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Narrative Discussion Relating to the Pension Benefits Table for 2010

Supplemental Executive Retirement Plan

Under the terms of the SERP, participants are entitled to receive on December 31 of each year an allocation of phantom units having a fair market value equal to their percentage allocation multiplied by the sum of base salary and cash bonus received that year, then reduced by any supplemental contribution that was made to our defined contribution PSSP for the participant that year. A participant’s cumulative notional phantom unit account balance earns the equivalent of common unit distributions. The calculated distributions are added to the notional account balance in the form of additional phantom units. All amounts granted under the SERP vest immediately and are paid out upon the participant’s termination or death in ARLP common units equal to the number of phantom units then credited to the participant’s account, subject to reduction of the number of units distributed to cover withholding obligations. Please see “Item 11. Compensation Discussion and Analysis—Compensation Components—Supplemental Executive Retirement Plan.”

Potential Payments Upon a Termination or Change of Control

Each of our Named Executive Officers is eligible to receive accelerated vesting and payment under the LTIP and the SERP upon certain terminations of employment or upon our change in control. Upon a “change of control,” as defined in the LTIP, all awards outstanding under the LTIP will automatically vest and become payable or exercisable, as the case may be, in full. In this regard, all restricted periods shall terminate and all performance criteria, if any, shall be deemed to have been achieved at the maximum level. The LTIP defines a “change in control” as one of the following events: (1) any sale, lease, exchange or other transfer of all or substantially all of our assets or our managing general partner’s assets to any person other than a person who is our affiliate; (2) the consolidation or merger of our managing general partner with or into another person pursuant to a transaction in which the outstanding voting interests of our managing general partner is changed into or exchanged for cash, securities or other property, other than any such transaction where (a) the outstanding voting interests of our managing general partner are changed into or exchanged for voting stock or interests of the surviving corporation or its parent and (b) the holders of the voting interests of our managing general partner immediately prior to such transaction own, directly or indirectly, not less than a majority of the voting stock or interests of the surviving corporation or its parent immediately after such transaction; or (3) a person or group being or becoming the beneficial owner of more than 50% of all voting interests of our managing general partner then outstanding.

The amounts each of our Named Executive Officers could receive under the SERP have been previously disclosed in “Item 11. Pension Benefits Table for 2010” and the amounts each of the Named Executive Officers could receive under the LTIP have been previously disclosed in “Item 11. Outstanding Equity Awards at Fiscal Year-End 2010 Table”, in each case assuming the triggering event occurred on December 31, 2010. The exact amount that any Named Executive Officer would receive could only be determined with certainty upon an actual termination or change in control.

Director Compensation

The compensation of the directors of our managing general partner, MGP, is set by the Board of Directors upon recommendation of the Compensation Committee. Mr. Craft and Mr. Wesley, our only employee directors, receive no director compensation. The directors of MGP devote 100% of their time as directors of MGP to the business of the ARLP Partnership.

Director Compensation Table for 2010

 

Name   Fees
earned or
Paid in
Cash ($)
    Unit
Awards ($) (2)(4)
    Option
Awards ($)(1)
    Non-Equity
Incentive Plan
Compensation ($)(1)
    Change in
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings ($)(1)
    All Other
Compensation ($)(3)
    Total ($)  

Michael J. Hall

  $ 75,000      $ 19,009      $ —        $ —        $ —        $ 5,000      $ 99,009   

John P. Neafsey

    115,000        84,905        —          —          —          5,000        204,905   

John H. Robinson

    100,000        47,236        —          —          —          1,800        149,036   

Wilson M. Torrence

    115,000        50,777        —          —          —          —          165,777   

 

(1) Column is not applicable.
(2) Amounts represent the grant date fair value of equity awards in 2010 related to deferrals of annual retainer and automatically deferred compensation. Please see Narrative to Director Compensation Table, below.

 

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(3) Messrs. Hall, Neafsey and Robinson’s Other Compensation includes matching charitable contributions made by us. We match individual contributions of $25 or more to educational institutions and not-for-profit organizations on a one-to-one basis up to $5,000 per individual, per calendar year.
(4) At December 31, 2010, each director had the following number of “phantom” ARLP common units credited to his notional account under the deferred compensation plan:

 

Name   

Directors

Deferred
Compensation

Plan
(in Units)

 

Michael J. Hall

     1,374   

John P. Neafsey

     18,164   

John H. Robinson

     1,003   

Wilson M. Torrence

     10,172   

Narrative to Directors Compensation Table

Our directors’ compensation includes an annual cash retainer paid quarterly in advance on a pro rata basis (the “Annual Retainer”). The Annual Retainer for calendar year 2010 was $115,000. Directors have the option to defer all or part of the Annual Retainer pursuant to the MGP’s Amended and Restated Deferred Compensation Plan for Directors (the “Deferred Compensation Plan”) by completing an election form prior to the beginning of each calendar year. Mr. Robinson elected to defer part of his annual retainer in 2010. In addition to the Annual Retainer, in 2010 Directors received equity-based compensation that was automatically deferred under the Deferred Compensation Plan. The equity-based compensation in 2010 was $20,000 for each director other than Mr. Hall, with an additional $10,000 for the Chairman of the Board and each Committee chairman, other than Mr. Hall (without duplication), and was credited quarterly in advance on a pro rata basis. At Mr. Hall’s request, his compensation in 2010 remained the same as 2009, comprising Annual Retainer of $75,000 and equity-based compensation of $15,000. Mr. Hall, who is chairman of our Audit Committee, is also a director and chairman of the audit committee of AGP, the general partner of AHGP, and received like compensation for his service in those roles.

Pursuant to the Deferred Compensation Plan, for both deferred amounts of Annual Retainer and automatic deferrals of equity-based compensation, a notional account is established and credited with notional common units of ARLP, described in the plan as “phantom” units. The number of phantom units credited is determined by dividing the amount deferred by the average closing unit price for the ten trading days immediately preceding the deferral date. When quarterly cash distributions are made with respect to ARLP common units, an amount equal to such quarterly distribution is credited to the notional account as additional phantom units. For notional accounts under the Deferred Compensation Plan payable after January 1, 2011, payment will be made in ARLP common units equal to the number of phantom units then credited to the director’s account.

Directors may elect to receive payment of the account resulting from deferrals during a plan year either (a) on the January 1 on or next following his or her separation from service as a director or (b) on the earlier of a specified January 1 or the January 1 on or next following his or her separation from service. The payment election must be made prior to each plan year; if no election is made, the account will be paid on the January 1 on or next following the director’s separation from service. The Deferred Compensation Plan is administered by the Compensation Committee, and the Board of Directors may change or terminate the plan at any time; provided, however, that accrued benefits under the plan cannot be impaired.

Upon any recapitalization, reorganization, reclassification, split of common units, distribution or dividend of securities on ARLP common units, our consolidation or merger, or sale of all or substantially all of our assets or other similar transaction which is effected in such a way that holders of common units are entitled to receive (either directly or upon subsequent liquidation) cash, securities or assets with respect to or in exchange for ARLP common units, the Compensation Committee shall, in its sole discretion (and upon the advice of financial advisors as may be retained by the Compensation Committee), immediately adjust the notional balance of phantom units in each director’s account under

 

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the Deferred Compensation Plan to equitably credit the fair value of the change in the ARLP common units and/or the distributions (of cash, securities or other assets) received or economic enhancement realized by the holders of the ARLP common units.

Our Board of Directors has established a policy that each non-employee director will attain, by January 1, 2014 or five years following such person’s election to the Board of Directors, and thereafter maintain during service on the Board of Directors, ownership of equity of ARLP (including phantom equity ownership under the Deferred Compensation Plan) with value equal to or greater than three times the Annual Retainer amount.

Compensation Committee Interlocks and Insider Participation

Mr. Craft is a director and the President and Chief Executive Officer of our managing general partner and is Chairman of the Board of Directors, President and Chief Executive Officer of AGP, the general partner of AHGP. Otherwise, none of our executive officers serves as a member of the Board of Directors or Compensation Committee of any entity that has one or more of its executive officers serving as a member of the Board of Directors or Compensation Committee of our managing general partner.

 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth certain information as of February 23, 2011, regarding the beneficial ownership of common units held by (a) each director of our managing general partner, (b) each executive officer of our managing general partner identified in the Summary Compensation Table included in “Item 11. Executive Compensation” above, (c) all such directors and executive officers as a group, and (d) each person known by our managing general partner to be the beneficial owner of 5% or more of our common units. Our managing general partner is owned by AHGP (which is reflected as a 5% common unitholder in the table below), and approximately 80% of the equity of AHGP is owned by members of management and certain former members of management. Our special general partner is a wholly-owned subsidiary of ARH, which is indirectly wholly-owned by Mr. Craft. The address of each of AHGP, ARH, our managing general partner, our special general partner, and unless otherwise indicated in the footnotes to the table below, each of the directors and executive officers reflected in the table below is 1717 South Boulder Avenue, Suite 400, Tulsa, Oklahoma 74119. Unless otherwise indicated in the footnotes to the table below, the common units reflected as being beneficially owned by our managing general partner’s directors and named executive officers are held directly by such directors and officers. The percentage of common units beneficially owned is based on 36,775,741 common units outstanding as of February 23, 2011.

 

Name of Beneficial Owner   

Common
Units

Beneficially
Owned

    

Percentage
of
Common
Units

Beneficially
Owned

 

Directors and Executive Officers

     

Joseph W. Craft III (1)

     15,902,620         43.24

Michael J. Hall

     29,951         *   

John P. Neafsey

     46,620         *   

John H. Robinson

     9,000         *   

Wilson M. Torrence

     2,696         *   

Charles R. Wesley III

     111,836         *   

Brian L. Cantrell

     24,758         *   

R. Eberley Davis

     7,428         *   

Robert G. Sachse

     24,217         *   

Thomas M. Wynne

     21,455         *   

All directors and executive officers as a group (10 persons)

     16,180,581         44.0

5% Common Unit Holders

     

Alliance Holdings GP, L.P. (2)

     15,544,169         42.27

 

* Less than one percent.
(1) Mr. Craft’s common units consist of (i) 357,451 common units held directly by him, (ii) 1,000 common units held by his son, and (iii) 15,544,169 common units held by AHGP. Mr. Craft is a director, and through his ownership of C-Holdings, LLC, the sole owner of AGP, the general partner of AHGP, and he holds, directly or indirectly, or may be deemed to be the beneficial owner of, a majority of the outstanding common units of AHGP. AHGP owns approximately 42.3% of our common units as of February 23, 2011. Mr. Craft disclaims beneficial ownership of the common units held by AHGP except to the extent of his pecuniary interest therein.

 

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(2) See footnote (1) above and the paragraph preceding the above table for explanation of the relationship between AHGP, Mr. Craft and us.

Equity Compensation Plan Information

 

Plan Category   

Number of
units to be
issued upon

exercise/
vesting of
outstanding

options,
warrants and
rights

as of
December 31,
2010

     Weighted-
average
exercise
price of
outstanding
options,
warrants
and rights
     Number of
units
remaining
available for
future
issuance
under equity
compensation
plans as of
December 31,
2010
 

Equity compensation plans approved by unitholders:

        

Long-Term Incentive Plan

     372,723         N/A         2,302,591   

 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Certain Relationships and Related Transactions

As of December 31, 2010, AHGP owned 15,544,169 common units representing 42.3% of our common units and our IDR. In addition, our general partners own, on a combined basis, an aggregate 2% general partner interest in us, the Intermediate Partnership and the subsidiaries. Our managing general partner’s ability, as managing general partner, to control us together with AHGP’s ownership of 42.3% of our common units, effectively gives our managing general partner the ability to veto our actions and to control our management.

Certain of our officers and directors are also officers and/or directors of AHGP, including Mr. Craft, the President and Chief Executive Officer of our managing general partner, Mr. Hall, a Director, member of the Compensation Committee and Chairman of the Audit Committee of our managing general partner, Mr. Cantrell, the Senior Vice President and Chief Financial Officer of our managing general partner, and Mr. Davis, the Senior Vice President, General Counsel and Secretary of our managing general partner.

Transactions Between Us, SGP, SGP Land, ARH, ARH II and AHGP

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

Administrative Services

On April 1, 2010, effective January 1, 2010, ARLP entered into an Administrative Services Agreement with our managing general partner, our Intermediate Partnership, AHGP and its general partner AGP, and ARH II. The Administrative Services Agreement superseded the administrative services agreement signed in connection with the AHGP IPO in 2006. 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, 2010 of $0.3 million from AHGP and $0.2 million from ARH II.

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 to us by our managing general partner and its affiliates were approximately

 

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$1.3 million for the year ended December 31, 2010. The executive officers of our managing general partner are employees of and paid by Alliance Coal, and the reimbursement we pay to our managing general partner pursuant to the partnership agreement does not include any compensation expenses associated with them.

MAC

In September 2007, MAC entered into a $1.5 million Revolver with ARLP. 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 expired on December 31, 2010. At December 31, 2010, MAC owed ARLP $1.6 million under the Revolver, which is classified as Due from Affiliates on our consolidated balance sheets. MAC repaid the amount due under the Revolver in January 2011.

SGP Land, LLC

SGP Land is owned by our special general partner, which is owned indirectly by Mr. Craft.

On May 2, 2007, Alliance Coal, our operating subsidiary, entered into a time sharing agreement with SGP Land concerning the use of aircraft owned by SGP Land. In accordance with the provisions of the time sharing agreement as amended, we reimbursed SGP Land $0.8 million for the year ended December 31, 2010 for use of aircraft.

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 the year ended December 31, 2010. As of December 31, 2010, $2.1 million of advance minimum royalties paid under the lease is available for recoupment.

SGP

In 2005, Tunnel Ridge entered into a coal lease agreement with the SGP, our special general partner, requiring advance minimum royalty payments of $3.0 million per year. As of December 31, 2010, Tunnel Ridge had paid $17.9 million of advance minimum royalty payments pursuant to the lease. The advance royalty payments are fully recoupable against earned royalties. Tunnel Ridge also controls surface land and other tangible assets under a separate lease agreement with the SGP. Under the terms of the lease agreement, Tunnel Ridge has paid and will continue to pay the SGP an annual lease payment of $0.2 million. The lease agreement has an initial term of four years, which may be extended to be coextensive with the term of the coal lease. Lease expense was $0.2 million for the year ended December 31, 2010. In August 2010, the coal lease was amended to include approximately 34.4 million additional clean tons of recoverable coal reserves in the proven and probable categories.

We have a noncancelable operating lease arrangement with the SGP for the coal preparation plant and ancillary facilities at the Gibson mining complex. Pursuant to the lease, we made monthly payments of approximately $0.2 million through January 2011. Lease expense incurred for the year ended December 31, 2010 was $2.6 million. Effective February 1, 2011, the lease was amended to extend the term through January 2017 and modify other terms, including reducing the monthly payments to approximately $50,000.

We have agreements with two banks to provide letters of credit in an aggregate amount of $31.1 million. At December 31, 2010, we had $30.7 million in outstanding letters of credit under these agreements. The SGP guarantees $5.0 million of these outstanding letters of credit. The SGP does not charge us for this guarantee.

Omnibus Agreement

Concurrent with the closing of our initial public offering, we entered into an omnibus agreement with ARH and our general partners, which govern potential competition among us and the other parties to this agreement. The omnibus agreement was amended in May 2002. Pursuant to the terms of the amended omnibus agreement, ARH agreed, and caused its controlled affiliates to agree, for so long as management controls our managing general partner, not to engage in the business of mining, marketing or transporting coal in the U.S., unless it first offers us the opportunity to engage in a potential activity or acquire a potential business, and the Board of Directors, with the concurrence of its Conflicts Committee, elects to cause us not to pursue such opportunity or acquisition. In addition, ARH has the ability to purchase businesses, the majority value of which is not mining, marketing or transporting coal, provided ARH offers us the

 

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opportunity to purchase the coal assets following their acquisition. The restriction does not apply to the assets retained and business conducted by ARH at the closing of our initial public offering. Except as provided above, ARH and its controlled affiliates are prohibited from engaging in activities wherein they compete directly with us. In addition to its non-competition provisions, the agreement also provides for indemnification of us against liabilities associated with certain assets and businesses of ARH which were disposed of or liquidated prior to consummating our initial public offering. In May 2006, in connection with the closing of the AHGP IPO, the omnibus agreement was amended to include AHGP and AGP as parties to the agreement.

Director Independence

As a publicly-traded limited partnership listed on the NASDAQ Global Select Market, we are required to maintain a sufficient number of independent directors on the board of our managing general partner to satisfy the audit committee requirement set forth in NASDAQ Rule 4350(d)(2). Rule 4350(d)(2) requires us to maintain an audit committee of at least three members, each of whom must, among other requirements, be independent as defined under NASDAQ Rule 4200(a)(15) and meet the criteria for independence set forth in Rule 10A-3(b)(1) under the Exchange Act (subject to the exemptions provided in Rule 10A-3(c)).

In 2010, the Board of Directors affirmatively determined that the members of the Audit Committee—Messrs. Hall, Robinson and Torrence—are independent directors as defined under applicable NASDAQ and Exchange Act rules. Please see “Item 10. Directors, Executive Officers and Corporate Governance of the Managing General Partner—Audit Committee.”

 

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The firm of Deloitte & Touche LLP is our independent registered public accounting firm. Fees paid to Deloitte & Touche LLP during the last two fiscal years were as follows:

Audit Fees. Fees for audit services provided during each of the years ended December 31, 2010 and 2009 were $0.6 and $0.8 million, respectively. Audit services consist primarily of the audit and quarterly reviews of the consolidated financial statements, but can also be related to statutory audits of subsidiaries required by governmental or regulatory bodies, attestation services required by statute or regulation, comfort letters, consents, assistance with and review of documents filed with the SEC, work performed by tax professionals in connection with the audit and quarterly reviews, and accounting and financial reporting consultations and research work necessary to comply with GAAP.

Audit-Related Fees. There were no audit-related fees for the years ended December 31, 2010 and 2009.

Tax Fees. There were no fees for tax services for the years ended December 31, 2010 and 2009.

All Other Fees. There were no other fees for the years ended December 31, 2010 and 2009.

The charter of the Audit Committee provides that the committee is responsible for the pre-approval of all auditing services and permitted non-audit services to be performed for us by our independent registered public accounting firm, subject to the requirements of applicable law. In accordance with such charter, the Audit Committee may delegate the authority to grant such pre-approvals to the Audit Committee chairman or a sub-committee of the Audit Committee, which pre-approvals are then reviewed by the full Audit Committee at its next regular meeting. Typically, however, the Audit Committee itself reviews the matters to be approved. The Audit Committee periodically monitors the services rendered by and actual fees paid to the independent registered public accounting firm to ensure that such services are within the parameters approved by the Audit Committee.

 

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PART IV

 

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 

(a) (1)   Financial Statements.
  The response to this portion of Item 15 is submitted as a separate section herein under Part II, Item 8. Financial Statements and Supplementary Data.
(a)(2)   Financial Statement Schedules.
  Schedule II—Valuation and Qualifying Accounts—Years ended December 31, 2010, 2009 and 2008, is set forth under Part II, Item 8. Financial Statements and Supplementary Data. All other schedules are omitted because they are not applicable or the information is shown in the financial statements or notes thereto.
(a)(3) and (c)   The exhibits listed below are filed as part of this annual report.

 

          Incorporated by Reference  

Exhibit
Number

  

Exhibit Description

   Form      SEC
File No. and
Film No.
     Exhibit      Filing Date      Filed
Herewith*
 

    3.1

   Second Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P.      8-K        

 

000-26823

051159681

  

  

     3.1         10/27/2005      

    3.2

   Amended and Restated Agreement of Limited Partnership of Alliance Resource Operating Partners, L.P.      10-K        

 

000-26823

583595

  

  

     3.2         03/29/2000      

    3.3

   Certificate of Limited Partnership of Alliance Resource Partners, L.P      S-1        

 

333-78845

99630855

  

  

     3.6         05/20/1999      

    3.4

   Certificate of Limited Partnership of Alliance Resource Operating Partners, L.P.      S-1/A        

 

333-78845

99669102

  

  

     3.8         07/23/1999      

    3.5

   Certificate of Formation of Alliance Resource Management GP, LLC      S-1/A        

 

333-78845

99669102

  

  

     3.7         07/23/1999      

    3.6

   Amended and Restated Operating Agreement of Alliance Resource Management GP, LLC      S-3        

 

333-85282

02596627

  

  

     3.4         04/01/2002      

    3.7

   Amendment No. 1 to Amended and Restated Operating Agreement of Alliance Resource Management GP, LLC      S-3        

 

333-85282

02596627

  

  

     3.5         04/01/2002      

    3.8

   Amendment No. 2 to Amended and Restated Operating Agreement of Alliance Resource Management GP, LLC      S-3        

 

333-85282

02596627

  

  

     3.6         04/01/2002      

    3.9

   Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P.      8-K        

 

000-26823

06993800

  

  

     3.1         08/01/2006      

    3.10

   Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L. P. dated October 25, 2007      10-K        

 

000-26823

08654096

  

  

     3.10         02/29/2008      

    3.11

   Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P., dated April 14, 2008      8-K        

 

000-26823

08763867

  

  

     3.1         04/18/2008      

 

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          Incorporated by Reference  

Exhibit
Number

  

Exhibit Description

   Form      SEC
File No. and
Film No.
     Exhibit      Filing Date      Filed
Herewith*
 

    4.1

   Form of Common Unit Certificate (Included as Exhibit A to the Second Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P., included in this Exhibit Index as Exhibit 3.1).      8-K        

 

000-26823

08763867

  

  

     3.1         04/18/2008      

    5.1

   Opinion of Vinson & Elkins L.L.P. as to the Legality of Securities      S-8         333-165168         5.1         03/03/2010      

  10.1

   Note Purchase Agreement, dated as of August 16, 1999, among Alliance Resource GP, LLC and the purchasers named therein      10-K        

 

000-26823

583595

  

  

     10.2         03/29/2000      

  10.2

   Letter of Credit Facility Agreement dated as of October 2, 2001, between Alliance Resource Partners, L.P. and Bank of the Lakes, National Association      10-Q        

 

000-26823

1782487

  

  

     10.25         11/13/2001      

  10.3

   First Amendment to the Letter of Credit Facility Agreement between Alliance Resource Partners, L.P. and Bank of the Lakes, National Association      10-Q        

 

000-26823

02827517

  

  

     10.32         11/14/2002      

  10.4

   Promissory Note Agreement dated as of October 2, 2001, between Alliance Resource Partners, L.P. and Bank of the Lakes, N.A.      10-Q        

 

000-26823

1782487

  

  

     10.26         11/13/2001      

  10.5

   Guarantee Agreement, dated as of October 2, 2001, between Alliance Resource GP, LLC and Bank of the Lakes, N.A.      10-Q        

 

000-26823

1782487

  

  

     10.27         11/13/2001      

  10.6

   Contribution and Assumption Agreement, dated August 16, 1999, among Alliance Resource Holdings, Inc., Alliance Resource Management GP, LLC, Alliance Resource GP, LLC, Alliance Resource Partners, L.P., Alliance Resource Operating Partners, L.P. and the other parties named therein      10-K        

 

000-26823

583595

  

  

     10.3         03/29/2000      

  10.7

   Omnibus Agreement, dated August 16, 1999, among Alliance Resource Holdings, Inc., Alliance Resource Management GP, LLC, Alliance Resource GP, LLC and Alliance Resource Partners, L.P.      10-K        

 

000-26823

583595

  

  

     10.4         03/29/2000      

  10.81)

   Amended and Restated Alliance Coal, LLC 2000 Long-Term Incentive Plan      10-K        

 

000-26823

04667577

  

  

     10.17         03/15/2004      

  10. 9(1)

   First Amendment to the Alliance Coal, LLC 2000 Long-Term Incentive      10-K        

 

000-26823

04667577

  

  

     10.18         03/15/2004      

  10.10(1)

   Alliance Coal, LLC Short-Term Incentive Plan      10-K        

 

000-26823

583595

  

  

     10.12         03/29/2000      

  10.11(1)

   Alliance Coal, LLC Supplemental Executive Retirement Plan      S-8        

 

333-85258

02595143

  

  

     99.2         04/01/2002      

  10.12(1)

   Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors      S-8        

 

333-85258

02595143

  

  

     99.3         04/01/2002      

  10.13

   Restated and Amended Coal Supply Agreement, dated February 1, 1986, among Seminole Electric Cooperative, Inc., Webster County Coal Corporation and White County Coal Corporation      S-1/A        

 

333-78845

99667220

  

  

     10.9         07/20/1999      

 

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          Incorporated by Reference  

Exhibit
Number

  

Exhibit Description

   Form      SEC
File No. and
Film No.
     Exhibit      Filing Date      Filed
Herewith*
 

  10.14

   Amendment No. 1 to the Restated and Amended Coal Supply Agreement effective April 1, 1996, between MAPCO Coal Inc., Webster County Coal Corporation, White County Coal Corporation, and Seminole Electric Cooperative, Inc.      10-Q        

 

000-26823

693139

  

  

     10.14         08/11/2000      

  10.15

   Guaranty by Alliance Coal, LLC dated October 25, 2005      10-K        

 

000-26823

06691048

  

  

     10.28         03/16/2006      

  10.16(2)

   Financial Covenants Agreement dated October 25, 2005 by and between Seminole Electric Corporation, Inc. and Alliance Coal, LLC      10-K        

 

000-26823

06691048

  

  

     10.29         03/16/2006      

  10.17

   Agreement for the Supply of Coal to the Mt. Storm Power Station dated June 22, 2005, between Virginia Electric and Power Company and Alliance Coal, LLC      8-K        

 

000-26823

05917813

  

  

     10.1         06/27/2005      

  10.18(2)

   Amendment No. 1 to the Agreement for the Supply of Coal to Mt. Storm Power Station, made effective January 1, 2007, between Virginia Electric and Power Company and Alliance Coal, LLC      8-K        

 

000-26823

07634133

  

  

     10.1         02/20/2007      

  10.19(2)

   Ancillary Services Agreement dated June 22, 2005, between Virginia Electric and Power Company and Alliance Coal, LLC      8-K        

 

000-26823

05917813

  

  

     10.2         06/27/2005      

  10.20(2)

   Amended and Restated Lease Agreement dated June 22, 2005, between Virginia Electric and Power Company and Mettiki Coal, LLC      8-K        

 

000-26823

05917813

  

  

     10.3         06/27/2005      

  10.21(2)

   Amended and Restated Equipment Lease Agreement (Existing Truck Unloading Facility), dated June 22, 2005, between Virginia Electric and Power Company and Mettiki Coal, LLC      8-K        

 

000-26823

05917813

  

  

     10.4         06/27/2005      

  10.22(2)

   Memorandum of Understanding, made effective January 1, 2007, between Virginia Electric and Power Company, and Alliance Coal, LLC, Mettiki Coal (WV), LLC and Mettiki Coal, LLC      10-K        

 

000-26823

07660999

  

  

     10.33         03/01/2007      

  10.23

   Amended and Restated Charter for the Audit Committee of the Board of Directors dated February 23, 2009      10-K        

 

000-26823

09647063

  

  

     10.35         03/02/2009      

  10.24

   Second Amendment to the Omnibus Agreement dated May 15, 2006 by and among Alliance Resource Partners, L.P., Alliance Resource GP, LLC, Alliance Resource Management GP, LLC, Alliance Resource Holdings, Inc., Alliance Resource Holdings II, Inc., AMH-II, LLC, Alliance Holdings GP, L.P., Alliance GP, LLC and Alliance Management Holdings, LLC      10-Q        

 

000-26823

061017824

  

  

     10.1         08/09/2006      

  10.25

   Administrative Services Agreement dated May 15, 2006 among Alliance Resource Partners, L.P., Alliance Resource Management GP, LLC, Alliance Resource Holdings II, Inc., Alliance Holdings GP, L.P. and Alliance GP, LLC      10-Q        

 

000-26823

061017824

  

  

     10.2         08/09/2006      

 

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          Incorporated by Reference  

Exhibit
Number

  

Exhibit Description

   Form      SEC
File No. and
Film No.
     Exhibit      Filing Date      Filed
Herewith*
 

  10.26

   Amended and Restated Charter for the Compensation Committee of the Board of Directors dated January 27, 2009      10-K        

 

000-26823

09647063

  

  

     10.40         03/02/2009      

  10.27(1)

   First Amendment to the Amended and Restated Alliance Coal, LLC Supplemental Executive Retirement Plan      10-K        

 

000-26823

07660999

  

  

     10.50         03/01/2007      

  10.28(1)

   Second Amendment to the Amended and Restated Alliance Coal, LLC Supplemental Executive Retirement Plan      10-K        

 

000-26823

08654096

  

  

     10.50         02/29/2008      

  10.29(1)

   Second Amendment to the Amended and Restated Alliance Coal, LLC Long-Term Incentive Plan      10-K        

 

000-26823

07660999

  

  

     10.51         03/01/2007      

  10.30(1)

   First Amendment to the Alliance Coal, LLC Short-Term Incentive Plan      10-K        

 

000-26823

07660999

  

  

     10.52         03/01/2007      

  10.31(1)

   Second Amendment to the Alliance Coal, LLC Short-Term Incentive Plan      10-K        

 

000-26823

08654096

  

  

     10.53         02/29/2008      

  10.32

   First Amendment to the Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors      10-K        

 

000-26823

07660999

  

  

     10.53         03/01/2007      

  10.33

   Second Amendment to the Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors      10-K        

 

000-26823

08654096

  

  

     10.55         02/29/2008      

  10.34

   Second Amended and Restated Credit Agreement, dated as of September 25, 2007, among Alliance Resource Operating Partners, L.P. as Borrower and the Initial Lenders, Initial Issuing Banks and Swing Line Bank and J.P. Morgan Chase Bank, N.A. as Paying Agent and Citicorp USA, inc. and JP Morgan Chase Bank, N.A. as Co-Administrative Agents and Citigroup Global markets Inc. and J.P. Morgan Securities Inc. as Joint Lead Arrangers and Joint Bookrunners      8-K        

 

000-26823

071138090

  

  

     99.1         09/27/2007      

  10.35

   Note Purchase Agreement, 6.28% Senior Notes Due June 26, 2015, and 6.72% Senior Notes due June 26, 2018, dated as of June 26, 2008, by and among Alliance Resource Operating Partners, L.P. and various investors      8-K        

 

000-26823

08928968

  

  

     10.1         07/01/2008      

  10.36

   First Amendment, dated as of June 26, 2008, to the Note Purchase Agreement, dated August 16, 1999, 8.31% Senior Notes due August 20, 2014, by and among Alliance Resource Operating Partners, L.P. (as successor to Alliance Resource GP, LLC) and various investors      8-K        

 

000-26823

08928968

  

  

     10.2         07/01/2008      

 

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Table of Contents
          Incorporated by Reference  

Exhibit
Number

  

Exhibit Description

   Form      SEC
File No. and
Film No.
     Exhibit      Filing Date      Filed
Herewith*
 

  10.37

   Letter Amendment No. 1, dated as of June 26, 2008, to the Second Amended and Restated Credit Agreement, dated as of September 25, 2007, among Alliance Resource Operating Partners, L.P. as Borrower, the Initial Lenders, Initial Issuing Banks and Swing Line Bank, in each case as named therein, JPMorgan Chase Bank, N.A. as Paying Agent, Citicorp USA, Inc. and JPMorgan Chase Bank, N.A. as Co-Administrative Agents, and Citigroup Global Markets Inc. and J.P. Morgan Securities, Inc. as Joint Lead Arrangers and Joint Bookrunners      8-K        

 

000-26823

08928968

  

  

     99.1         07/01/2008      

  10.38

   Term Loan Agreement      8-K        

 

000-26823

11502824

  

  

     99.1         01/04/2011      

  10.39(1)

   Third Amendment to the Amended and Restated Alliance Coal, LLC Supplemental Executive Retirement Plan      10-K        

 

000-26823

09647063

  

  

     10.52         03/02/2009      

  10.40(1)

   Amended and Restated Alliance Coal, LLC Supplemental Executive Retirement Plan dated as of January 1, 2011                  þ   

  10.41(1)

   Second Amendment to the Amended and Restated Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors      10-K        

 

000-26823

09647063

  

  

     10.53         03/02/2009      

  10.42(1)

   Amended and Restated Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors dated as of January 1, 2011                  þ   

  10.43

   Amendment No. 2 to Letter of Credit Facility Agreement between Alliance Resource Partners, L.P. and Bank of the Lakes, National Association, dated April 13, 2009      10-Q        

 

000-26823

09811514

  

  

     10.1         05/08/2009      

  10.44

   Amendment No. 2, dated as of September 30, 2009, to the Second Amended and Restated Credit Agreement, dated as of September 25, 2007, among Alliance Resource Operating Partners, L.P. as Borrower, the Initial Lenders, Initial Issuing Banks and Swing Line Bank, in each case as named therein, JPMorgan Chase Bank, N.A. as Paying Agent, Citicorp USA, Inc. and JPMorgan Chase Bank, N.A. as Co-Administrative Agents, and Citigroup Global Markets Inc. and J.P. Morgan Securities, Inc. as Joint Lend Arrangers and Joint Bookrunners      8-K        

 

000-26823

091107762

  

  

     10.1         10/06/2009      

  10.45(2)

   Agreement for the Supply of Coal, dated August 20, 2009 between Tennessee Valley Authority and Alliance Coal, LLC      10-Q        

 

000-26823

091164883

  

  

     10.2         11/06/2009      

  10.46

   Amended and Restated Charter for the Compensation Committee of the Board of Directors dated February 23, 2010.      10-K        

 

000-26823

10638795

  

  

     10.49         02/26/2010      

 

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Table of Contents
          Incorporated by Reference  

Exhibit
Number

  

Exhibit Description

   Form      SEC
File No. and
Film No.
     Exhibit      Filing Date      Filed
Herewith*
 

  10.47(2)

   Amendment No. 5 effective January 1, 2010, between Seminole Electric Cooperative, Inc. and Webster County Coal, LLC (successor-in-interest to Webster County Coal Corporation), White County Coal, LLC (successor-in-interest to White County Coal Corporation), and Alliance Coal, LLC, as successor-in-interest to Mapco Coal, Inc. and agent for Webster County Coal, LLC and White County Coal, LLC, to the Coal Supply Agreement.      10-Q        

 

000-26823

10811686

  

  

     10.1         05/07/2010      

  10.48

   Amended and Restated Administrative Services Agreement effective January 1, 2010, among Alliance Resource Partners, L.P., Alliance Resource Management GP, LLC, Alliance Resource Holdings II, Inc., Alliance Resource Operating Partners, L.P., Alliance Holdings GP, L.P. and Alliance GP, LLC.      10-Q        

 

000-26823

101000555

  

  

     10.1         08/09/2010      

  10.49

   Uncommitted Line of Credit and Reimbursement Agreement dated April 9, 2010 between Alliance Resource Partners, L.P. and Fifth Third Bank.      10-Q        

 

000-26823

101000555

  

  

     10.2         08/09/2010      

  18.1

   Preferability Letter on Accounting Change      10-Q/A        

 

000-26823

02593767

  

  

     18.1         03/29/2002      

  21.1

   List of Subsidiaries.                  þ   

  23.1

   Consent of Deloitte & Touche LLP regarding Form S-3 and Form S-8, Registration Statements No. 333-158526 and 333-85258, respectively.                  þ   

  31.1

   Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated February 28, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                  þ   

  31.2

   Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated February 28, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                 
 
þ
 
  
  

  32.1

   Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated February 28, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                  þ   

 

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Table of Contents
          Incorporated by Reference  

Exhibit
Number

  

Exhibit Description

   Form      SEC
File No.  and
Film No.
     Exhibit      Filing
Date
     Filed
Herewith*
 

  32.2

   Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated February 28, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                  þ   

101

   Interactive Data File (Form 10-K for the year ended December 31, 2010 furnished in XBRL). The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed” and, in accordance with Rule 406T of Regulation S-T, is not deemed “filed” or part of a registration statement or prospectus for purposes of Sections 11 and 12 of the Securities Act of 1933, as amended, and Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under these sections.               

 

* Filed herewith (or furnished, in the case of Exhibits 32.1 and 32.2).
(1) Denotes management contract or compensatory plan or arrangement.
(2) Portions of this exhibit have been omitted pursuant to a request for confidential treatment under Rule 24b-2 of the Securities Exchange Act of 1934, as amended, and the omitted material has been separately filed with the Securities and Exchange Commission.

 

141


Table of Contents

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in Tulsa, Oklahoma, on February 28, 2011.

 

    ALLIANCE RESOURCE PARTNERS, L.P.
By:  

Alliance Resource Management GP, LLC

its managing general partner

 

/s/ Joseph W. Craft III

  Joseph W. Craft III
  President, Chief Executive
  Officer and Director
 

/s/ Brian L. Cantrell

  Brian L. Cantrell
  Senior Vice President and
  Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature

  

Title

 

Date

/s/ Joseph W. Craft III

Joseph W. Craft III

  

President, Chief Executive Officer,

and Director (Principal Executive Officer)

  February 28, 2011

/s/ Brian L. Cantrell

Brian L. Cantrell

  

Senior Vice President and

Chief Financial Officer (Principal Financial and Accounting Officer)

  February 28, 2011

/s/ Michael J. Hall

Michael J. Hall

   Director   February 28, 2011

/s/ John P. Neafsey

John P. Neafsey

   Director   February 28, 2011

/s/ John H. Robinson

John H. Robinson

   Director   February 28, 2011

/s/ Wilson M. Torrence

Wilson M. Torrence

   Director   February 28, 2011

/s/ Charles R. Wesley

Charles R. Wesley

   Executive Vice President and Director   February 28, 2011

 

142