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Alliance Resource Partners, L.P. 10-K 2006
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, 2005

OR

 

¨

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

FOR THE TRANSITION PERIOD FROM              TO             

COMMISSION FILE NO.: 0-26823

 


ALLIANCE RESOURCE PARTNERS, L.P.

(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

 


 

DELAWARE   73-1564280

(STATE OR OTHER JURISDICTION OF

INCORPORATION OR ORGANIZATION)

 

(IRS EMPLOYER

IDENTIFICATION NO.)

1717 SOUTH BOULDER AVENUE, SUITE 600, TULSA, OKLAHOMA 74119

(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)

(918) 295-7600

(REGISTRANT’S TELEPHONE NUMBER, INCLUDING AREA CODE)

 


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

Securities registered pursuant to Section 12(g) of the Act: common units representing limited partner interests

 


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

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

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes    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 $749,107,920 as of June 30, 2005, 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 National Market on such date.

As of March 16, 2006, 36,426,306 common units were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

 



Table of Contents

TABLE OF CONTENTS

 

          Page
   PART I   

ITEM 1.

  

BUSINESS

   2

ITEM 1A.

  

RISK FACTORS

   16

ITEM 1B.

  

UNRESOLVED STAFF COMMENTS

   27

ITEM 2.

  

PROPERTIES

   28

ITEM 3.

  

LEGAL PROCEEDINGS

   30

ITEM 4.

  

SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS

   30
   PART II   

ITEM 5.

  

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

   30

ITEM 6.

  

SELECTED FINANCIAL DATA

   31

ITEM 7.

  

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

   33

ITEM 7A.

  

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   52

ITEM 8.

  

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

   53

ITEM 9.

  

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANT ON ACCOUNTING AND FINANCIAL DISCLOSURE

   85

ITEM 9A.

  

CONTROLS AND PROCEDURES

   85

ITEM 9B.

  

OTHER INFORMATION

   87
   PART III   

ITEM 10.

  

DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL PARTNER

   88

ITEM 11.

  

EXECUTIVE COMPENSATION

   92

ITEM 12.

  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND RELATED UNITHOLDER MATTERS

   98

ITEM 13.

  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

   99

ITEM 14.

  

PRINCIPAL ACCOUNTANT FEES AND SERVICES

   102
   PART IV   

ITEM 15.

  

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

   103

 

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FORWARD-LOOKING STATEMENTS

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

 

   

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

 

   

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

 

   

risks associated with the expansion of our operations and properties;

 

   

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

 

   

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

 

   

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

 

   

customer delays or defaults in making payments;

 

   

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

 

   

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

 

   

greater than expected increases in raw material costs;

 

   

greater than expected shortage of skilled labor;

 

   

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

 

   

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

 

   

greater than expected environmental regulation, costs and liabilities;

 

   

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

 

   

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

 

   

results of litigation;

 

   

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

 

   

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

 

   

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

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

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

 

   

in this Annual Report on Form 10-K;

 

   

other reports filed by us with the SEC;

 

   

our press releases; and

 

   

written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

 

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PART I

ITEM 1. BUSINESS

General

We are a diversified producer and marketer of coal to major United States utilities and industrial users. We began mining operations in 1971 and, since then, have grown through acquisitions and internal development to become what we believe to be the fifth largest coal producer in the eastern United States. At December 31, 2005, we had approximately 549.0 million tons of reserves in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia. In 2005, we produced 22.3 million tons of coal and sold 22.8 million tons of coal. The coal we produced in 2005 was 30.0% low-sulfur coal, 14.8% medium-sulfur coal and 55.2% high-sulfur coal. In 2005, approximately 89.8% of our medium- and high-sulfur coal was sold to utility plants with installed pollution control devices, also known as “scrubbers,” to remove sulfur dioxide. We classify low-sulfur coal as coal with a sulfur content of less than 1%, medium-sulfur coal as coal with a sulfur content between 1% and 2%, and high-sulfur coal as coal with a sulfur content of greater than 2%.

At December 31, 2005, we operated seven underground complexes in Illinois, Indiana, Kentucky and Maryland. Our surface mine located in Kentucky depleted its entire reserve area in December 2005 and its production eventually will be replaced by an underground mine that is expected to emerge from mine development during the second quarter of 2006. We also are developing an underground mine in West Virginia that will replace production from our underground mine in Maryland, which is expected to deplete its reserves in November 2006. Our mining activities are conducted in three geographic regions commonly referred to in the coal industry as the Illinois Basin, Central Appalachia and Northern Appalachia 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 existing, adjacent or neighboring properties.

In 2002, we entered into long-term agreements to host and operate a coal synfuel production facility currently based at Warrior Coal, LLC (Warrior), located in the Illinois Basin region, to supply the facility with coal feedstock, to assist with the marketing of coal synfuel and to provide other services to the owner of the synfuel facility.

In 2005, Gibson County Coal, LLC (Gibson County Coal), and Mettiki Coal, LLC (Mettiki Coal), entered into similar long-term coal synfuel agreements. At Gibson, in the Illinois Basin region, we host a coal synfuel facility, supply the facility with coal feedstock, and assist with the marketing of coal synfuel. At Mettiki, in the Northern Appalachia region, we supply a coal synfuel facility located at the power plant of Mettiki’s primary customer with coal feedstock.

We and our subsidiary, Alliance Resource Operating Partners, L.P. (the intermediate partnership), are Delaware limited partnerships formed to acquire, own and operate certain coal production and marketing assets of Alliance Resource Holdings, Inc. (Alliance Resource Holdings), a Delaware corporation formerly known as Alliance Coal Corporation. We completed our initial public offering in August 1999, at which time Alliance Resource Holdings contributed certain assets in exchange for cash, common and subordinated units, general partner interests, the right to receive incentive distributions as defined in the partnership agreement and the assumption of related indebtedness.

Our managing general partner, Alliance Resource Management GP, LLC, and our special general partner, Alliance Resource GP, LLC (collectively referred to as our general partners), own an aggregate 2% general partner interest in us. Our limited partners, including the general partners as holders of common units, own an aggregate 98% limited partner interest in us.

Our internet address is www.arlp.com, and we make available on our internet website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and Forms 4 for our Section 16 filers (and amendments and exhibits, such as press releases, to such filings) as soon as reasonably practicable after we electronically file with or furnish such material to the Securities and Exchange Commission. Our “Code of Ethics” for our chief executive officer and our senior financial officers is also posted on our website.

 

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Recent Developments

Allegheny Coal Lease and Coal Sales Agreement. On December 29, 2005, we announced that our newly formed subsidiary, Penn Ridge Coal, LLC (Penn Ridge), had entered into a coal lease and sales agreement with affiliates of Allegheny Energy, Inc. (Allegheny), to pursue development of Allegheny’s Buffalo coal reserve in Washington County, Pennsylvania. Under this coal lease and sales agreement, an affiliate of Allegheny has agreed to lease to Penn Ridge the Buffalo coal reserve in exchange for lease payments consisting of fixed production royalties on coal sales proceeds. The lease term is fifteen years, and it commenced on December 28, 2005. The Buffalo coal reserve lease encompasses approximately 19,800 acres and is estimated to include approximately 55 million tons of coal in the Pittsburgh No. 8 seam and 300 acres of surface land located near Avella, Pennsylvania. We anticipate that the Penn Ridge operation will be capable of producing annually up to 5.0 million tons of coal and may employ as many as 270 persons. We are estimating total capital expenditures required to develop Penn Ridge to be approximately $165.0 million over a five-year period. We expect to immediately begin the development process for the Penn Ridge mine, which includes obtaining the necessary permits. We anticipate production from Penn Ridge commencing between 2009 and 2010. In conjunction with the Buffalo coal reserve lease, Penn Ridge also entered into a ten-year, 20 million ton coal sales agreement with affiliates of Allegheny at market based prices. Upon commencement of initial production, Penn Ridge will supply annually up to two million tons of coal produced from the Buffalo coal reserve for use in Allegheny’s power plants. The Buffalo coal reserve area is north of and contiguous to our Tunnel Ridge reserve area, which is located in Washington County, Pennsylvania and Ohio County, West Virginia. When combined with our Tunnel Ridge reserves, we control an estimated 125 million tons of coal in the Pittsburgh No. 8 seam.

LG&E Coal Sales Agreement. On December 21, 2005, we announced that our subsidiary, Alliance Coal, LLC (Alliance Coal), has entered into a new six-year, 23.5 million ton coal sales agreement, effective January 1, 2006, with Louisville Gas and Electric Company (LG&E). At the end of the primary six-year term, the parties have the option to extend the new agreement for an incremental 16.0 million tons of coal over an additional four years. Under the new agreement, beginning January 1, 2006, Alliance Coal will ship annually up to 4.0 million tons of coal directly to LG&E or as feedstock for synfuel produced for the benefit of LG&E. Since 2001, Alliance Coal, LLC and its affiliates have supplied annually approximately 2.4 million tons of Illinois Basin coal to LG&E, either directly or as synfuel feedstock, under existing coal supply agreements. The new agreement represents an increase of approximately 1.6 million tons over coal shipments historically supplied by Alliance Coal’s subsidiaries, Hopkins County Coal, LLC, Webster County Coal, LLC, and Warrior Coal, LLC.

New Mine Safety Rules. As a result of recent coal mining accidents in West Virginia and Kentucky, the U.S. Department of Labor’s Mine Safety Health Administration as well as West Virginia and several other states, including Kentucky, Pennsylvania and Illinois, have imposed, or are considering imposing, stringent new mine safety and accident reporting requirements and increased civil and criminal penalties for violations of mine safety laws. Please read “—Mine Health and Safety Laws.”

Mining Operations

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

 

     Year Ended December 31,
      2005    2004    2003    2002    2001
     (tons in millions)
Regions and Complexes   

Illinois Basin:

              

Dotiki, Warrior, Pattiki, Hopkins and Gibson Complexes

   15.7    13.6    12.3    12.1    11.9

Central Appalachia:

              

Pontiki and MC Mining Complexes

   3.3    3.6    3.6    3.0    2.8

Northern Appalachia:

              

Mettiki Complex

   3.3    3.2    3.3    2.9    2.7
                        

Total

   22.3    20.4    19.2    18.0    17.4
                        

 

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Illinois Basin Operations

Our Illinois Basin mining operations are located in western Kentucky, southern Illinois and southern Indiana. We have approximately 1,440 employees in the Illinois Basin and currently operate five mining complexes. Additionally, we host a coal synfuel facility at two of our mining complexes.

Dotiki Complex. 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. Our Dotiki complex utilizes continuous mining units employing room-and-pillar mining techniques. In 2004, the preparation plant throughput capacity was increased to 1,300 tons of raw coal an hour. Capacity was increased principally to accommodate a change in customer requirements for washed coal rather than raw coal.

On February 11, 2004, the Dotiki mine was temporarily idled following the occurrence of a mine fire. The fire was successfully extinguished and the affected area of the mine was totally isolated behind permanent barriers. Production resumed on March 8, 2004. For information on the fire at our Dotiki complex, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Production of high-sulfur coal from the Dotiki complex is shipped via the CSX and PAL railroads and by truck on U.S. and state highways. Our primary customers for coal produced at Dotiki are LG&E, Seminole Electric Cooperative, Inc. (Seminole) and Tennessee Valley Authority (TVA), all of which purchase our coal pursuant to long-term contracts for use in their scrubbed generating units.

Warrior Complex. Warrior Coal, LLC (Warrior) operates the Cardinal mine, an underground mining complex located near Madisonville, in Hopkins County, Kentucky, between and adjacent to our other western Kentucky operations. 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 producing high-sulfur coal. During 2005, Warrior increased mining capacity with the addition of one continuous miner unit. Warrior’s preparation plant has a throughput capacity of 600 tons of raw coal an hour.

Warrior sells substantially all of its production to Synfuel Solutions Operating, LLC (SSO) for feedstock in the production of coal synfuel, as discussed below. SSO’s coal synfuel production facility was moved from Hopkins County Coal, LLC (Hopkins) to Warrior in April 2003. Warrior’s production can be shipped via the CSX and PAL railroads and by truck on U.S. and state highways. Additionally, Warrior purchased supplemental production from a third-party supplier for resale to SSO and will continue to purchase tons from the third-party supplier through June 2007. SSO continues to ship coal synfuel to electric utilities that have been purchasers of our coal. We maintain “back-up” coal supply agreements with these long-term customers for our coal, which automatically provide for the sale of our coal to them in the event they do not purchase coal synfuel from SSO.

We have entered into long-term agreements with SSO to host and operate its coal synfuel facility currently located at Warrior, supply the facility with coal feedstock, assist SSO with the marketing of coal synfuel and provide other services. These agreements expire on December 31, 2007, and provide us with coal sales, rental and service fees from SSO based on the synfuel facility throughput tonnages. These amounts are dependent on the ability of SSO’s members to use certain qualifying tax credits applicable to the facility. As discussed above, we sell most of the coal produced at Warrior to SSO, while Alliance Coal Sales, a division of Alliance Coal, assists SSO with the sale of its coal synfuel to our customers pursuant to a sales agency agreement. The term of each of these agreements is subject to early cancellation provisions customary for transactions of these types, including the unavailability of synfuel tax credits, the termination of associated coal synfuel sales contracts, and the occurrence of certain force majeure events. Therefore, the continuation of the revenues associated with the coal synfuel production facility cannot be assured. However, we have maintained “back up” coal supply agreements with each coal synfuel customer that automatically provide for sale of our coal to these customers in the event they do not purchase coal synfuel from SSO. In conjunction with a decision to relocate the coal synfuel production facility to Warrior, agreements for providing certain of these services were assigned to Alliance Service, Inc. (Alliance Service), a wholly-owed subsidiary of Alliance Coal, in December 2002. Alliance Service is subject to federal and state income taxes.

For 2005, the incremental annual net income benefit from the combination of the various coal synfuel-related agreements associated with the facility located at Warrior was approximately $18.9 million, assuming that coal pricing

 

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would not have increased without the availability of synfuel. The continuation of the incremental net income benefit associated with SSO’s coal synfuel facility cannot be assured. Pursuant to our agreement with SSO, we are not obligated to make retroactive adjustments or reimbursements if SSO’s tax credits are disallowed.

In June 2003, the Internal Revenue Service (IRS) suspended the issuance of private letter rulings on the significant chemical change requirement to qualify for synfuel tax credits and announced that it was reviewing the test procedures and results used by taxpayers to establish that a significant chemical change had occurred. In October 2003, the IRS completed its review and concluded that the test procedures and results were scientifically valid if applied in a consistent and unbiased manner. The IRS has resumed issuing private letter rulings under its existing guidelines. SSO has advised us that its private letter ruling could be reviewed by the IRS as part of a tax audit, similar to the IRS reviews of other synfuel procedures.

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

Production of high-sulfur coal from the complex is shipped via the CSX railroad. Our primary customers for coal produced at Pattiki have been Northern Indiana Public Service Company and Seminole for use in their scrubbed generating units. Pattiki production is also shipped via rail to our Mt. Vernon transloading facility for sale to utilities capable of receiving barge deliveries. In 2006, Pattiki expects to ship a significant portion of its production to TVA and Tampa Electric and transfer its Seminole shipments to Dotiki and Warrior.

Hopkins Complex. During 2005, Hopkins County Coal, LLC’s (Hopkins County Coal) production was from its Newcoal surface mine that depleted its reserves in December 2005. Hopkins County Coal is developing an underground mine, referred to as the Elk Creek mine, which is described below. Hopkins County Coal is located near the city of Madisonville in Hopkins County, Kentucky. We acquired the complex in January 1998. The Newcoal surface mine was idled in June 2003 because we were unable to secure sufficient sales commitments in the Illinois Basin region. In October 2004, the surface mine was re-opened in response to incremental sale opportunities from existing customers as well as strong market demand for Illinois Basin region coal.

The surface operation utilized dragline mining and the existing preparation plant has a throughput capacity of 1,000 tons of raw coal an hour. In conjunction with the development of the Elk Creek mine, Hopkins County Coal is constructing a new preparation plant with a throughput capacity of 1,200 tons of coal an hour. The new preparation plant will provide significant operating efficiencies. Hopkins’ production has the ability to be shipped via the CSX and PAL railroads and by truck on U.S. and state highways.

On October 23, 2005, Hopkins exercised an option to lease the Elk Creek reserves. The Elk Creek coal reserves consist of approximately 36.0 million tons of high-sulfur coal. The Elk Creek mine will be an underground mining complex, using continuous mining units employing room-and-pillar mining techniques. We intend to utilize the existing coal handling and other surface facilities at Hopkins to process and ship coal produced from the Elk Creek mine. Elk Creek is expected to emerge from mine development in the second quarter of 2006. When the Elk Creek mine reaches full production capacity we expect annual production to be approximately 3.8 million tons.

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

Production from Gibson is a low-sulfur coal, that historically has been primarily shipped via truck approximately 10 miles on U.S. and state highways to Gibson’s principal customer, PSI Energy Inc. (PSI), a subsidiary of Cinergy Corporation. Gibson’s production is also trucked to our Mt. Vernon transloading facility for sale to utilities capable of receiving barge deliveries.

In January 2005, Gibson entered into long-term agreements with PC Indiana Synthetic Fuel #2, L.L.C. (PCIN) to host its coal synfuel facility, supply the facility with coal feedstock, assist PCIN with the marketing of coal synfuel and

 

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provide other services. The synfuel facility commenced operations at Gibson in May 2005. A significant portion of Gibson’s production is sold to PCIN. The agreements expire on December 31, 2007 and provide us with coal sales, rental and service fees from PCIN based on the synfuel facility throughput tonnages. These amounts are dependent on the ability of PCIN’s members to use certain qualifying tax credits applicable to the facility. The term of each of these agreements is subject to early cancellation provisions customary for transactions of these types, including the unavailability of synfuel tax credits, the termination of associated coal synfuel sales contracts, and the occurrence of certain force majeure events. Therefore, revenues associated with the coal synfuel production facility cannot be assured. However, we have entered into “back up” coal supply agreements with each coal synfuel customer that automatically provide for sale of our coal to these customers in the event they do not purchase coal synfuel from PCIN.

For 2005, the incremental annual net income benefit from the combination of the various coal synfuel related agreements associated with the facility located at Gibson was approximately $3.0 million, assuming that coal pricing would not have increased without the availability of synfuel. This estimated incremental net income cannot be assured. Pursuant to our agreement with PCIN, we are not obligated to make retroactive adjustments or reimbursements if PCIN’s tax credits are disallowed.

We have initiated the permitting process for the Gibson South reserves and are actively evaluating its development. Capital expenditures required to develop the Gibson South reserves are estimated to be approximately $100 million. Assuming sufficient sales commitments are obtained and the permitting process progresses as anticipated, initial production could commence in 2008 or 2009. When the Gibson South mine reaches full production capacity, we expect annual production to be approximately 3.1 million tons. Definitive development commitment for Gibson South is dependent upon final approval by the board of directors of our managing general partner.

Central Appalachian Operations

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

Pontiki Complex. Pontiki Coal, LLC (Pontiki Coal) owns Pontiki, an underground mining complex located near the city of Inez in Martin County, Kentucky. We constructed the mine in 1977. Pontiki owns the mining complex and leases the reserves, and Excel Mining, LLC (Excel), an affiliate of Pontiki, is responsible for conducting all mining operations. Substantially all of the coal produced at Pontiki in 2005 met or exceeded the compliance requirements of Phase II of the Clean Air Act amendments. Our Pontiki operation utilizes continuous mining units employing room-and-pillar mining techniques. The preparation plant has a throughput capacity of 800 tons of raw coal an hour. In February 2005 construction efforts began that allowed Pontiki to migrate its mining units into a new coal seam. The first mining unit in the new coal seam emerged from mine development in the fourth quarter of 2005. Beginning in 2006, production will still be low sulfur, but because of changes in geology and the migration of some of Pontiki’s mining units into the Van Lear coal seam, may no longer meet the compliance requirements of Phase II of the Clean Air Act.

Our primary customer for the low-sulfur coal produced at Pontiki is ICG, LLC (ICG), the successor-in-interest of certain assets of Horizon Natural Resources Company. In November 2005, we settled a contract dispute in which ICG alleged we failed to deliver 138,111 tons of coal. Please read “Item 13. Legal Proceedings” and “Item 8. Financial Statements and Supplementary Data – Note 18. Commitments and Contingencies.” Production from the mine is shipped primarily to electric utilities located in the southeastern United States via the Norfolk Southern railroad or by truck via U.S. and state highways to various docks on the Big Sandy River in Kentucky.

MC Mining Complex. MC Mining, LLC (MC Mining) owns an underground mining complex located near the city of Pikeville in Pike County, Kentucky. We acquired the mine in 1989. MC Mining owns the mining complex and leases the reserves, and Excel, an affiliate of MC Mining, is responsible for conducting all mining operations. On December 26, 2004, MC Mining was temporarily idled following the occurrence of a mine fire. The fire was successfully extinguished and the affected area of the mine was totally isolated behind permanent barriers. Initial production resumed on February 21, 2005. For more information on the fire at our MC Mining mine, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Substantially all of the coal produced at MC Mining in 2005 met or exceeded the compliance requirements of Phase II of the Clean Air Act amendments. The complex utilizes continuous mining units employing room-and-pillar mining techniques. The preparation plant has a throughput capacity of 800 tons of raw coal an hour.

 

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Production from the mine is shipped via the CSX railroad or by truck via U.S. and state highways to various docks on the Big Sandy River. MC Mining sells its low-sulfur production primarily in the spot market.

Northern Appalachia Operations

Our Northern Appalachia mining operation is located in the Northern Appalachia coal fields. We have approximately 230 employees and operate one mining complex in Northern Appalachia.

Mettiki Complex. Mettiki Coal operates an underground longwall mining complex, which is sometimes referred to as the D-Mine, located near the city of Oakland in Garrett County, Maryland. We constructed Mettiki in 1977 and have operated it since its inception. The operation utilizes a longwall miner for the majority of the coal extraction as well as continuous mining units used to prepare the mine for future longwall mining. The preparation plant has a throughput capacity of 1,350 tons of raw coal an hour. In response to strong market demand, Mettiki’s production capacity was increased through two small-scale third party mining operations.

Historically, our primary customer for the medium-sulfur coal produced at Mettiki has been Virginia Electric and Power Company (VEPCO), which purchased the coal pursuant to a long-term contract for use in the scrubbed generating units at its Mt. Storm, West Virginia power plant. Our coal is trucked approximately 20 miles to Mt. Storm over a private haul road, which links to a state highway. Mettiki is also served by the CSX railroad.

In June 2005 and subsequently amended in August 2005, Mettiki entered into an agreement with Mt. Storm Coal Supply, LLC, or Mt. Storm Coal Supply, to supply its coal synfuel facility, located at the Mt. Storm power plant, with coal feedstock. For 2005, the incremental annual net income benefit from the coal feedstock agreements was approximately $2.2 million, assuming that coal pricing would not increase without the availability of synfuel. The continuation of this agreement cannot be assured because the non-conventional source fuel tax credits are subject to a pro-rata phase-out or reduction based on the annual average wellhead price per barrel for all domestic crude oil (the reference price) as determined by the Secretary of the Treasury. We have entered into a “back up” coal supply agreement with VEPCO for sale of our coal in the event VEPCO does not purchase coal synfuel from Mt. Storm Coal Supply. Pursuant to our agreement with Mt. Storm Coal Supply, we are not obligated to make retroactive adjustments or reimbursements if Mt. Storm Coal Supply’s tax credits are disallowed.

Mettiki Coal (WV). Mettiki Coal (WV), LLC is developing an underground longwall mine in Tucker County, West Virginia known as the Mountain View Mine (also known as the E-Mine), which will eventually replace Mettiki Coal’s D-Mine. We anticipate the active D-Mine will deplete its coal reserves in November 2006, at which time the longwall mining system will be relocated from D-Mine to Mettiki Coal (WV)’s Mountain View Mine. Longwall production is expected to commence in January 2007.

Penn Ridge Coal. Penn Ridge Coal, LLC (Penn Ridge) has entered into a coal lease and sales agreement with affiliates of Allegheny, to pursue development of Allegheny’s Buffalo coal reserve in Washington County, Pennsylvania. The Buffalo coal reserve lease is estimated to include approximately 55 million tons of coal in the Pittsburgh No. 8 seam. Definitive development commitment for Penn Ridge is dependent upon final approval of the board of directors of our managing general partner.

Tunnel Ridge. Tunnel Ridge, LLC (Tunnel Ridge) controls, through a coal lease agreement with our special general partner, approximately 70 million tons of high-sulfur coal in the Pittsburgh No. 8 coal seam. Definitive development commitment for Tunnel Ridge is dependent upon final approval of the board of directors of our managing general partner.

Other Operations

Mt. Vernon Transfer Terminal, LLC

The Mt. Vernon Transfer Terminal, LLC (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 million tons per year with existing ground storage. During 2005, the terminal loaded approximately 2.1 million tons for Pattiki and Gibson customers and for third-party shippers.

Coal Brokerage

As markets allow, we buy coal from non-affiliated producers principally throughout the eastern United States, which we then resell, both directly and indirectly, primarily to utility customers. We purchased and sold approximately 6,000 tons of coal from non-affiliated producers in 2005. We have a policy of matching our outside coal purchases and sales to minimize market risks associated with buying and reselling coal. Purchased coal that is delivered to our operations and commingled with our production is not classified as brokerage coal.

 

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Additional Services

We develop and market additional services in order to establish ourselves as the supplier of choice for our customers. Examples of the kind of services we have offered to date include ash and scrubber sludge removal, coal yard maintenance and arranging alternate transportation services. Revenues from these services have historically represented less than one percent of our total revenues.

Reportable Segments

Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and Note 20. Segment Information under “Item 8. Financial Statements And Supplementary Data” 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 by providing greater predictability of sales volumes and sales prices. In 2005, approximately 86.0% and 81.7% of our sales tonnage and total coal sales, respectively, were sold under long-term contracts (contracts having a term of one year or greater) with maturities ranging from 2005 to 2023. Our total nominal commitment under significant long-term contracts for existing operations was approximately 117.6 million tons at December 31, 2005, and is expected to be delivered as follows: 20.2 million tons in 2006, 16.5 million tons in 2007, 14.7 million tons in 2008, 13.9 million tons in 2009, 13.9 million tons in 2010, and 38.4 million tons thereafter during the remaining terms of the relevant coal supply agreements. The total commitment of coal under contract is an approximate number because, in some instances, our contracts contain provisions that could cause the nominal total commitment to increase or decrease by as much as 20%. The contractual time commitments for customers to nominate future purchase volumes under these contracts are sufficient to allow us to balance our sales commitments with prospective production capacity. In addition, the nominal total commitment can otherwise change because of price reopener provisions contained in certain of these long-term contracts.

The terms of long-term contracts are the results of both bidding procedures and extensive negotiations with each customer. As a result, the terms of these contracts vary significantly in many respects, including, among others, price adjustment features, price and contract reopener terms, permitted sources of supply, force majeure provisions, coal qualities, and quantities. Virtually all of our long-term contracts are subject to price adjustment provisions, which permit an increase or decrease periodically in the contract price to reflect changes in specified price indices or items such as taxes, royalties or actual production costs. These provisions, however, may not assure that the contract price will reflect every change in production or other costs. Failure of the parties to agree on a price pursuant to an adjustment or a reopener provision can lead to early termination of a contract. Some of the long-term contracts also permit the contract to be reopened to renegotiate terms and conditions other than the pricing terms, and where a mutually acceptable agreement on terms and conditions cannot be concluded, either party may have the option to terminate the contract. The long-term contracts typically stipulate procedures for quality control, sampling and weighing. Most contain provisions requiring us to deliver coal within stated ranges for specific coal characteristics such as heat, sulfur, ash, moisture, grindability, volatility and other qualities. Failure to meet these specifications can result in economic penalties or termination of the contracts. While most of the contracts specify the approved seams and/or approved locations from which the coal is to be mined, some contracts allow the coal to be sourced from more than one mine or location. Although the volume to be delivered pursuant to a long-term contract is stipulated, the buyers often have the option to vary the volume within specified limits.

Reliance on Major Customers

Our three largest customers in 2005 were SSO, TVA and Mt. Storm Coal Supply. Sales to these customers in the aggregate accounted for approximately 36.4% of our 2005 total revenues, and sales to each of these customers accounted approximately 10% or more of our 2005 total revenues.

Competition

The United States coal industry is highly competitive with numerous producers in all coal producing regions. We compete with other large producers and hundreds of small producers in the United States. The largest coal company is estimated to have sold approximately 21% of the total 2005 tonnage sold in the United States market. We compete with other coal producers primarily on the basis of coal price at the mine, coal quality (including sulfur content), transportation cost from the mine to the customer, and the reliability of supply. Continued demand for our coal and the prices that we obtain are also affected by demand for electricity, environmental and government regulations, technological developments, and the availability and price of alternative fuel supplies, including nuclear, natural gas, oil, and hydroelectric power.

 

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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% to 41% of the 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.

Typically, our customers pay the transportation costs from the contractual F.O.B. point (free-on-board point), which is the standard practice in the industry and is generally from the mine to the customer’s plant. In 2005, the largest volume transporter of our coal shipments, including coal synfuel shipped by SSO, was the CSX railroad, which moved approximately 44.5% of our tonnage over its rail system. The practices of, and rates set by, the railroad serving a particular mine or customer might affect, either adversely or favorably, our marketing efforts with respect to coal produced from the relevant mine. At Gibson and Mettiki, independent contractors operate truck delivery systems that transport the coal to Gibson and Mettiki’s primary customer’s power plants.

Regulation and Laws

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

 

   

employee health and safety;

 

   

mine permits and other licensing requirements;

 

   

air quality standards;

 

   

water quality standards;

 

   

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

 

   

plant and wildlife protection;

 

   

reclamation and restoration of mining properties after mining is completed;

 

   

the discharge of materials into the environment;

 

   

storage and handling of explosives;

 

   

wetlands protection;

 

   

surface subsidence from underground mining; and

 

   

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

In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal. The possibility exists that new legislation or regulations, or new interpretations of existing laws or regulations, may be adopted that may have a significant impact on our mining operations or our customers’ ability to use coal.

We are committed to conducting mining operations in compliance with applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding our compliance efforts, we do not believe these violations can be eliminated completely. None of the violations to date have had a material impact on our operations or financial condition.

While it is not possible to quantify the costs of compliance with applicable federal and state laws, those costs have been and are expected to continue to be significant. Capital expenditures for environmental matters have not been material in recent years. We have accrued for the present value estimated cost of reclamation and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for reclamation and mine closing costs are based upon permit requirements and the costs and timing of reclamation 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. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.

 

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Mining Permits and Approvals

Numerous governmental permits or approvals are required for mining operations. We may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. All requirements imposed by any of these authorities may be costly and time consuming, and may delay or prevent commencement or continuation of mining operations in certain locations. Future legislation and administrative regulations may emphasize more heavily the protection of the environment and, as a consequence, our activities may be more closely regulated. Legislation and regulations, as well as future interpretations of existing laws and regulations, may require substantial increases in equipment and operating costs, or delays, interruptions or terminations of operations, the extent of any of which cannot be predicted.

Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws. 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 which 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.

Before commencing mining on a particular property, we must obtain mining permits and approvals by state regulatory authorities of a reclamation plan for restoring, upon the completion of mining, the mined property to its approximate prior condition, productive use or other permitted condition. Typically, we commence actions to obtain permits between 18 and 24 months before we plan to mine a new area. In our experience, permits generally are approved within 12 months after a completed application is submitted. Generally, we have not experienced material or significant difficulties in obtaining mining permits in the areas where our reserves are currently located. However, the permitting process for certain mining operations has extended over several years and we cannot assure you that we will not experience difficulty in obtaining mining permits in the future.

Our subsidiary, Mettiki Coal (WV), LLC (Mettiki Coal (WV)), is developing an underground longwall mining operation in Tucker County, West Virginia (which we refer to as the Mountain View Mine or E-Mine), which will eventually replace Mettiki’s existing longwall mining operation at the D-Mine located in Garrett County, Maryland. The Mountain View Mine is located approximately 10 miles from Mettiki. In order to proceed with development of the Mountain View Mine, Mettiki Coal (WV) submitted various permit applications to the West Virginia Department of Environmental Protection (WVDEP) including an application for approval to conduct underground mining. WVDEP issued the required permits in the Spring of 2004. Certain complainants appealed WVDEP’s decision issuing the underground mining permit to the West Virginia Surface Mine Board (SMB), which held administrative hearings on the matter in late 2004 and early 2005. On March 8, 2005, the SMB on a divided 3-3 vote issued a final order concluding consideration of the appeal without effectively rendering a decision, which, by operation of West Virginia law, resulted in the affirmation of WVDEP’s decision to issue the underground mining permit. The complainants appealed the SMB decision, but subsequently voluntarily agreed to withdraw the appeal, which was dismissed with prejudice by the Tucker County circuit court in West Virginia on April 26, 2005.

On April 19, 2005, these same complainants submitted a letter to the U.S. Department of Interior’s Office of Surface Mining, Reclamation and Enforcement (OSM), and the OSM’s regional field office in Charleston, West Virginia (CHFO), requesting federal monitoring and inspection of the Mountain View Mine and alleging that operations at the mine would create acid mine drainage with no defined end point. By written notice, dated April 21, 2005, the CHFO advised WVDEP that it would review the complainants’ allegation that the Mountain View Mine would cause material harm to the hydrological balance within and outside of the permit area. Following its initial review, on September 15, 2005, the CHFO notified WVDEP that it intended to initiate a formal investigation into the issuance of the underground mining permit for the Mountain View Mine. WVDEP requested an informal review of the CHFO decision by the OSM. By two letters, both dated October 21, 2005, OSM reversed the decision of the CHFO concluding that the CHFO and OSM lacked statutory authority to review the WVDEP’s issuance of the underground mining permit, and the Department of the Interior ordered that this was the Department’s final decision on the matter raised in the complainants’ letter dated April 19, 2005. The Mountain View Mine is not currently subject to any pending or threatened agency or third-party claims. However, on March 8, 2006, these same complainants requested that the Director of OSM evaluate West Virginia’s State Program pursuant to 30 C.F.R. §§ 733 et seq., but acknowledged a similar request had been made on April 19, 2005, which request had been previously rejected by the Department of Interior’s final decision on October 21, 2005.

 

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Mine Health and Safety Laws

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

Recent mining accidents involving fatalities in West Virginia and Kentucky have received national attention and prompted responses at the state and national level that have resulted in increased scrutiny of current industry safety practices and procedures at all mining operations. On January 26, 2006, West Virginia Governor Joe Manchin signed into law a bill imposing stringent new mine safety and accident reporting requirements and increased civil and criminal penalties for violations of mine safety laws. Other states, including Illinois, Pennsylvania and Kentucky, have proposed or passed similar bills and resolutions addressing mine safety practices. In addition, several mine safety bills have been introduced in Congress that would mandate similar improvements in mine safety practices; increase or add civil and criminal penalties for non-compliance with such laws or regulations; and expand the scope of federal oversight, inspection, and enforcement activities. On February 7, 2006, MSHA announced the promulgation of new emergency rules on mine safety. These rules address mine safety equipment, training, and emergency reporting requirements. Unlike most MSHA rules, these emergency rules will become effective immediately upon their publication in the Federal Register. Implementing and complying with these new laws and regulations could adversely affect our results of operation and financial position.

Black Lung Benefits Act

The Federal Black Lung Benefits Act (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 using actuarially determined 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, financial condition, and results of operation. Effective January 2001, new Federal Black Lung regulations took effect. These regulations relax the stringent award criteria established under the previous regulations potentially allowing more new Federal claims to be awarded and allowing previously denied claimants to re-file under the new criteria. The new 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.

Workers’ Compensation

We are required to compensate employees for work-related injuries. Several states in which we operate consider changes in workers’ compensation laws from time to time. We self-insure the potential cost using actuarially determined estimates of the cost of present and future claims. 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.

 

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Coal Industry Retiree Health Benefits Act

The Federal Coal Industry Retiree Health Benefits Act (CIRHBA), was enacted to provide for the funding of health benefits for some United Mine Workers of America retirees. The act 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. The act 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 Alliance Resource Holdings in 1996, MAPCO Inc., now a wholly-owned subsidiary of The Williams Companies, Inc., agreed to retain, and be responsible for, all liabilities under CIRHBA.

Surface Mining Control and Reclamation Act

The Federal Surface Mining Control and Reclamation Act (SMCRA), establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. The act requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, we reclaim and restore the mined areas by grading, shaping and preparing the soil for seeding. Upon completion of mining, reclamation generally is completed by seeding with grasses or planting trees for a variety of uses, as specified in the approved reclamation plan. We believe we are in compliance in all material respects with applicable regulations relating to reclamation.

SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. The act requires us to restore the surface to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. The mine operator must submit a bond or otherwise secure the performance of these reclamation obligations. 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. 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 maximum tax is $0.35 per ton on surface-mined coal and $0.15 per ton on underground-mined coal. The Abandoned Mine Lands Tax is set to expire June 30, 2006, and there are various legislative proposals that are under consideration by Congress to extend the tax. We have accrued the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. In addition, states from time-to-time have increased and may continue to increase their fees and taxes to fund reclamation or orphaned mine sites and 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 which 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 revocation of any permits that have been issued since the time of the violations or, in the case of civil penalties and reclamation fees, since the time their 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 develop in the future.

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, to pay certain black lung claims, and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for us and for our competitors generally to secure new surety bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. It is possible that surety bonds issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on us.

 

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Air Emissions

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

The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of 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.

EPA has promulgated rules, referred to as the “NOx SIP Call,” that require coal-fired power plants in 21 eastern states and Washington D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. Additionally, in March 2005, EPA issued the final Clean Air Interstate Rule, or CAIR, which will permanently cap nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. beginning in 2009 and 2010, respectively. CAIR requires these states to achieve the required emission reductions by requiring power plants to either participate in an EPA-administered “cap-and-trade” program that caps emission in two phases, or by meeting an individual state emissions budget through measures established by the state.

In March 2005, EPA finalized the Clean Air Mercury Rule (CAMR), which establishes a two-part, nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. While currently the subject of extensive controversy and litigation, if fully implemented, CAMR would permit states to implement their own mercury control regulations or participate in an interstate cap-and-trade program for mercury emission allowances.

EPA has adopted new, more stringent national air quality standards for ozone and fine particulate matter. As a result, some states will be required to amend their existing state implementation plans to attain and maintain compliance with the new air quality standards. For example, in December 2004, EPA designated specific areas in the United States as in “non-attainment” with the new national ambient air quality standard for fine particulate matter. In November 2005, EPA published proposed rules addressing how states would implement plans to bring applicable non-attainment regions into compliance with the new air quality standard. Under EPA’s proposed rulemaking, states would have until April 2008 to submit their implementation plans to EPA for approval. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, our mining operations and our customers could be affected when the new standards are implemented by the applicable states.

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

The Department of Justice, on behalf of EPA, has filed lawsuits against a number of coal-fired electric generating facilities, including some of our customers, alleging violations of the new source review provisions of the CAA. EPA has

 

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alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the new source review program. Several of these lawsuits have settled, but others remain pending. Depending on the ultimate resolution of these cases, demand for our coal could be affected.

Carbon Dioxide Emissions

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

In 2002, the United States withdrew its support for the Kyoto Protocol. With the Kyoto Protocol now effective, there will likely be increasing international pressure on the United States to adopt mandatory restrictions on carbon dioxide emissions. The United States Congress has considered bills in the past that would regulate domestic carbon dioxide emissions, but such bills have not yet received sufficient Congressional approvals. Several states have also either passed legislation or announced initiatives focused on decreasing or stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures have focused on emissions from coal-fired electric generating facilities. For example, in December 2005, seven northeastern states agreed to implement a regional cap-and-trade program to stabilize carbon dioxide emissions from regional power plants beginning in 2009.

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

Water Discharge

The Federal Clean Water Act (CWA), and similar state and local laws and regulations affect coal mining operations by imposing restrictions on effluent discharge into waters. Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions 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 wetlands permits required under CWA Section 404. However, mitigation requirements under existing and possible future wetlands permits may vary considerably. At this time we do not anticipate any increase in such requirements or in post-mining reclamation accrual requirements. For that reason, the setting of post-mine reclamation accruals for such mitigation projects is difficult to ascertain with certainty. We believe that we have obtained all permits required under the CWA as traditionally interpreted by the responsible agencies. Although more stringent permitting requirements may be imposed in the future, we are not able to accurately predict the impact, if any, of any such permitting requirements.

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

 

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On September 22, 2005, environmental groups led by the Ohio Valley Environmental Coalition filed suit in the Federal District Court for the Southern District of West Virginia challenging the Army Corps of Engineers’ (Corps of Engineers) authority to issue CWA Section 404 discharge permits for certain mountaintop mining projects. The case, styled Ohio Valley Environmental Coalition v. United States Army Corps of Engineers alleges that the Corps of Engineers generally acted arbitrarily and capriciously in issuing certain Section 404 permits to operators engaged in mountaintop mining operations. On February 1, 2006, the plaintiffs moved to amend their pleadings to seek a preliminary injunction that would void the Corps of Engineers approval of three particular CWA Section 404 permits issued to operators. Although our mining operations are not implicated in this particular litigation, it is possible that similar litigation affecting the Corps of Engineers ability to issue CWA permits could adversely affect our results of operation and financial position.

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

 

   

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

 

   

identify all current pollutant sources and loadings to that waterbody,

 

   

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

 

   

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

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

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

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

Hazardous Substances and Wastes

The Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), or 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 releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Some products used by coal companies in 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.

 

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The Federal Resource Conversation 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 EPA to require corrective action at sites where there is a release of hazardous substances. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.

In 2000, EPA declined to impose hazardous waste regulatory controls on the disposal of some coal combustion by-products, including the practice of using coal combustion by-products (CCB) as mine fill. However, under pressure from environmental groups, EPA has continued evaluating the possibility of placing additional solid waste burdens on the disposal of these types of materials. On March 1, 2006, the National Academy of Sciences released a report commissioned by Congress that studied CCB mine filling practices and recommended federal regulatory oversight of CCB mine filling under either SMCRA or the non-hazardous waste provisions of RCRA. It is unclear at this time how federal regulators will view this report and whether they will propose federal regulations under either SMCRA or RCRA. Assuming federal regulations are proposed in the future, it is not possible at this time to assess how such regulations would impact our operations. However, we believe the beneficial uses of coal combustion by-products that we employ (such as the practice of placing by-products in abandoned mine areas) do not constitute poor environmental practices because, among other things, our CWA discharge permits for treated AMD contain parameters for pollutants of concern, such as metals, and those permits require monitoring and reporting of effluent quality data.

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 where 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 property are subject to federal, state and local regulation.

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

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

Employees

To conduct our operations, our managing general partner and its affiliates employ approximately 2,300 employees, including approximately 100 corporate employees and approximately 2,200 employees involved in active mining operations. Our work-force is entirely union-free. Relations with our employees are generally good.

ITEM 1A. RISK FACTORS

Risks Inherent in an Investment in us

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

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

 

   

the supply of and demand for domestic and foreign coal;

 

   

weather conditions;

 

   

the proximity to, and capacity of, transportation facilities;

 

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worldwide economic conditions;

 

   

domestic and foreign governmental regulations and taxes;

 

   

the price and availability of alternative fuels; and

 

   

the effect of worldwide energy conservation measures.

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

A material amount of our net income and cash flow is dependent on our continued ability to realize direct or indirect benefits from federal income tax credits such as non-conventional source fuel tax credits. If the benefit to us from any of these tax credits is materially reduced, it could negatively impact our results of operations and reduce our cash available for distributions. The non-conventional source fuel tax credit is scheduled to expire on December 31, 2007.

In 2005, we derived a material amount of our net income under long-term agreements with SSO. These agreements are dependent on the ability of the synfuel facility’s owner to use certain qualifying federal income tax credits available to the facility and are subject to early cancellation in certain circumstances, including in the event that these synfuel tax credits become unavailable to the owner. In 2005, the benefit of this synfuel tax credit was approximately $24.1 million. If, because of budgetary shortfalls or any other reason, the federal government was to significantly reduce or eliminate these credits, it could negatively impact our results of operations and reduce our cash available for distributions.

Non-conventional source fuel tax credits are subject to a pro-rata phase-out or reduction if the annual average wellhead price per barrel for all domestic crude oil (the reference price) as determined by the Secretary of the Treasury exceeds certain levels. The reference price is not subject to regulation by the United States Government. The reference price for a calendar year is typically published in April of the following year. For qualified fuel sold during the 2004 calendar year, the reference price was $36.75. The pro-rata reduction of non-conventional source fuel tax credits for 2004 would have begun if the reference price was approximately $51.00 per barrel, with a complete phase-out or reduction of non-conventional synfuel tax credits if the reference price reached approximately $64.00 per barrel. We could experience a reduction of revenues associated with non-conventional source fuel facilities in the future if non-conventional source fuel tax credits become unavailable to the owners of the non-conventional source fuel facilities we service as a result of the rise in the wellhead price per barrel of crude oil above specified levels. At the present time, we have not been advised of any reductions in coal feedstock supply requirements or related services provided to any of our non-conventional source fuel facility customers. The non-conventional synfuel tax credit is scheduled to expire on December 31, 2007.

A loss of the benefit from state tax credits may adversely affect our ability to pay our quarterly distribution

Several states in which we operate or our utility customers reside have established a statutory framework for tax credits against income, franchise, or severance taxes, which have benefited, directly or indirectly, coal operators or customers purchasing coal mine production from within the applicable state. The state statutes authorizing these tax credits are scheduled to expire in accordance with their term provisions. Furthermore, these state statutes or our ability to benefit, directly or indirectly, from them may be subject to challenge by third parties. One of the states in which we operate has established a statutory framework for tax credits against income or franchise taxes, that have benefited, directly or indirectly, coal operators or customers purchasing coal produced from mines within that state. In 2005, the indirect benefit of this state tax credit to us was approximately $8.3 million. Although this credit is not set to expire by its terms in the near future, we are aware that legislation may be proposed that would eliminate this credit as a potential measure to reduce that state’s budget deficit. If these state statutes expire or any challenges are successful, we would lose the benefits of these credits. Therefore, if our operations do not produce increased cash flow sufficient to replace any lost benefits, we may not be able to pay the current quarterly distribution on its outstanding common units.

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

We compete with other large coal producers and hundreds of small coal producers in various regions of the United States for domestic sales. The industry has undergone significant consolidation over the last decade. This consolidation

 

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has led to several competitors having significantly larger financial and operating resources than we have. 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 would reduce our revenues and would adversely affect our ability to make distributions to our unitholders.

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

Some power plants are fueled by natural gas because of the cheaper construction costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. The domestic electric utility industry accounts for approximately 90% of domestic coal consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as hydroelectric power, and environmental and other governmental regulations.

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

A substantial decrease in the amount of coal sold by us pursuant to long-term contracts would reduce the certainty of the price and amounts of coal sold and subject our revenue stream to increased volatility. If that were to happen, changes in spot market coal prices below the long term contract price 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 2005, we sold approximately 86.0% of our sales tonnage under contracts having a term greater than one year. We refer to these contracts as long-term contracts. Long-term sales contracts have historically provided a relatively secure market for the amount of production committed under the terms of the contracts. From time to time industry conditions, however, may make it more difficult for us to enter into long-term contracts with our electric utility customers in the future. In the future, if supply exceeds demand in the coal industry, electric utilities may become less willing to lock in price or quantity commitments for an extended period of time. Accordingly, we may not be able to continue to obtain long-term sales contracts with reliable customers as existing contracts expire.

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

Some of our long-term contracts contain provisions which 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 can also lead to early termination of a contract.

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

 

   

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

 

   

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

 

   

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

 

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In addition, certain contracts are terminable as a result of events that are beyond our control. For example, we have entered into agreements with several coal synfuel facilities to provide coal feedstock and other services. Each of these agreements provides for early cancellation in the event federal synfuel tax credits become unavailable or upon the termination of associated coal synfuel sales contracts between the facility and our customers. In the event of early termination of any of our long-term contracts, if we are unable to enter into new contracts on similar terms, our business, financial condition and results of operations could be adversely affected.

Extensive environmental laws and regulations affect coal consumers, which 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 electric power plants, which are the ultimate consumers of our coal. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. A substantial portion of our coal has a high sulfur content, which may result in increased sulfur dioxide emissions when combusted. Accordingly, these laws and regulations may affect demand and prices for our low- and high-sulfur coal. There is also continuing pressure on state and federal regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants. As a result of these current and proposed laws, regulations and trends, electricity generators may elect to switch to other fuels that generate less of these emissions, possibly further reducing demand for our coal. Please read “Regulation and Laws—Air Emissions.”

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

During 2005, we derived approximately 36.4% of our total revenues from three customers, which individually accounted for 10% or more of our 2005 total revenues. If we were to lose any of these customers without finding replacement customers willing to purchase an equivalent amount of coal on similar terms, or if these customers were to change 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 relating to disputes with our customers may result in substantial costs, liabilities and loss of revenues.

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

Our profitability may decline due to unanticipated mine operating conditions and other factors that are not within our control.

Our mining operations are influenced by changing conditions 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 include, among others:

 

   

weather conditions;

 

   

equipment availability, replacement or repair;

 

   

prices for fuel, steel, explosives and other supplies;

 

   

Fires;

 

   

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

 

   

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

 

   

accidental mine water discharges and other geological conditions;

 

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shortage of skilled labor; or

 

   

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. For example, during the past two years, three loss incidents have occurred at our mine complexes. For details on these incidents and their negative effect on our results of operations, please read “Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations—Pattiki Vertical Belt Incident,” “—MC Mining Fire Incident” and “—Dotiki Fire Incident.” Prolonged disruption of production at any of our mines would result in a decrease in our revenues and profitability, which could be material. Decreases in our profitability as a result of the factors described above could materially adversely impact our quarterly or annual results. These risks may not be covered by our insurance policies.

Coal mining is subject to inherent risks that are beyond our control, and these risks may not be fully covered under our insurance policies.

Our mines are subject to conditions or events beyond our control that could disrupt operations and affect the cost of mining at particular mines for varying lengths of time. These risks include:

 

   

fires and explosions from methane;

 

   

natural disasters, such as heavy rains and flooding;

 

   

mining and processing equipment failures and unexpected maintenance problems;

 

   

mine flooding due to the failure of subsurface water seals or water removal equipment;

 

   

changes or variations in geologic conditions, such as the thickness of the coal deposits and the amount of rock and soil overlying the coal deposits;

 

   

inability to acquire mining rights or permits;

 

   

employee injuries or fatalities; and

 

   

labor-related interruptions.

During the past two years, three loss incidents have occurred at our mining complexes. On June 14, 2005, our Pattiki mining complex was temporarily idled for a period of 36 calendar days by the failure of the vertical conveyor belt system used in conveying raw coal out of the mine. Please read “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations—Pattiki Vertical Belt Incident.” On December 26, 2004, our Excel No. 3 mine was temporarily idled for a period of 57 calendar days following the occurrence of a mine fire. Production continues to be adversely impacted by inefficiencies attributable to or associated with this mine fire. Please read “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations—MC Mining Fire Incident.” On February 11, 2004, our Dotiki mining complex was temporarily idled for a period of 27 calendar days following the occurrence of a mine fire that originated with a diesel supply tractor. Please read “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations—Dotiki Fire Incident.” For details on how these incidents adversely affected our financial condition and results of operations, please read “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations—Analysis of Historical Results of Operations.” Loss incidents such as these are likely to increase the cost of mining and delay or halt production at particular mines for varying lengths of time. We do carry commercial (including business interruption and extra expense) property insurance policies; however, these risks may not be fully covered by these insurance policies.

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

Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least one year of experience and proficiency in multiple mining tasks. In recent years, a shortage of trained coal miners has caused

 

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us to operate certain mining units without full staff, which decreases our productivity and increases our costs. This shortage of trained coal miners is the result of a significant percentage of experienced coal miners reaching the age for retirement, combined with the difficulty of 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 are represented under collective bargaining agreements. However, all of our work force may not remain union-free in the future. If some or all of our currently union-free operations were to become unionized, it could adversely affect our productivity and increase the risk of work stoppages at our mining complexes. In addition, even if we remain union-free, our operations may still be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our operations.

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

Mining companies must obtain numerous permits 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. The public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required by us to conduct our operations may not be issued, maintained or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations. Limitations on our ability to conduct our mining operations due to the inability to obtain or renew necessary permits could reduce our production, cash flow and profitability. Please read “Regulations and Laws—Mining Permits and Approvals.”

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

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.

On the other hand, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, difficulty in coordinating the many eastern coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make coal shipments originating in the eastern United States inherently more expensive on a per-mile basis than coal shipments originating in the western United States. Historically, high coal transportation rates from the western coal producing areas into certain eastern markets limited the use of western coal in those markets. Lower or higher rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created

 

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major competitive challenges, as well as opportunities for eastern coal producers. In the event of lower transportation costs, the increased competition could have a material adverse effect on our business, financial condition and results of operations.

Some of our mines depend on a single transportation carrier or a single mode of transportation. Disruption of any of these transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks, and 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.

The states of Kentucky and West Virginia have recently increased enforcement of weight limits on coal trucks on their public roads. It is possible that other states in which our coal is transported by truck will modify their laws to limit truck weight limits. Such legislation 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.

Expansions of existing mines that we have completed since our formation, as well as mine expansions that we may undertake in the future, involve a number of risks, any of which could cause us not to realize the anticipated benefits.

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

 

   

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

 

   

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 opportunity.

Any one or more of these factors could cause us not to realize the benefits anticipated to result from an expansion. Any expansion 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 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.

We may not be able to successfully grow through future acquisitions, and we may not be able to effectively integrate the various businesses or properties we acquire.

Historically, a portion of our growth and operating results have been from acquisitions. Our future growth could be limited if we are unable to continue to make acquisitions, or if we are unable to successfully integrate the companies, businesses or properties we acquire. We may not be successful in consummating any acquisitions and the consequences of these acquisitions is 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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The unavailability of an adequate supply of coal reserves that can be mined at competitive costs could cause our profitability to decline.

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

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

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

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

 

   

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 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. As a result, you should not place undue reliance on the coal reserve data included herein.

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

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

 

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

Our coal mining operations use significant amounts of steel, petroleum products and other raw materials in various pieces of mining equipment, supplies and materials, including the roof bolts required by the room and pillar method of mining. Steel prices have risen significantly in recent years, and historically, the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel have fluctuated. Recently we have experienced cost increases for various commodities and services influenced by the recent steep increases in the price of crude oil and natural gas. Costs of diesel fuel, explosives, and coal trucking have all escalated as a direct result of supply chain problems related to the effect of recent hurricanes along the U.S. Gulf Coast. There may be other acts of nature or terrorist attacks or threats that could also increase the costs of raw materials. If the price of steel, petroleum products or other raw materials increase, our operational expenses will increase, which could have a significant negative impact on our profitability.

Cash distributions are not guaranteed and may fluctuate with our performance. In addition, our managing general partner’s discretion in establishing financial reserves may negatively impact our receipt of cash distributions.

Because distributions on our common units are dependent on the amount of cash generated through our coal sales, distributions may fluctuate based on the amount of coal we are able to produce and the price at which we are able to sell it. Therefore, the current quarterly distribution or any distribution may not be paid each quarter. The actual amount of cash that is available to be distributed each quarter will depend upon numerous factors, some of which are beyond our control and the control of our managing general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.

The partnership agreement gives our managing general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution. In addition, the partnership agreement requires the managing general partner to deduct from operating surplus each year estimated maintenance capital expenditures as opposed to actual expenditures in order to reduce wide disparities in operating surplus caused by fluctuating maintenance capital expenditure levels. If estimated maintenance capital expenditures in a year are higher than actual maintenance capital expenditures, then the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus.

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

We have long-term indebtedness, consisting of our outstanding 8.31% senior unsecured notes. At December 31, 2005, our total indebtedness outstanding was $162.0 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

 

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

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

Federal and state laws require bonds to secure our obligations related to the statutory requirement that we return mined property to its approximate original condition 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 as well as 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 right to refuse to renew the surety.

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

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

We are subject to numerous and detailed 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 of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state and local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be costly and time consuming and may delay commencement or continuation of exploration or production operations. The possibility exists that new laws or regulations (or judicial interpretations of existing laws and regulations) may be adopted in the future that could materially affect our mining operations, cash flow, and profitability, either through direct impacts such as new requirements impacting our existing mining operations, or indirect impacts such as new laws and regulations that discourage or limit our customers’ use of coal. Please read “Regulation and Laws.”

Recent mining accidents involving fatalities in West Virginia and Kentucky have received national attention and prompted responses at the state and national level that have resulted in increased scrutiny of current industry safety practices and procedures at all mining operations. On January 26, 2006, West Virginia Governor Joe Manchin signed into law a bill imposing stringent new mine safety and accident reporting requirements and increased civil and criminal penalties for violations of mine safety laws. Other states, including Illinois, have proposed or passed similar bills and resolutions addressing mine safety practices. In addition, several mine safety bills have been introduced in Congress that would mandate similar improvements in mine safety practices; increase or add civil and criminal penalties for non-compliance with such laws or regulations; and expand the scope of federal oversight, inspection, and enforcement activities. On February 7, 2006, the federal MSHA announced the promulgation of new emergency rules on mine safety.

 

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These rules address mine safety equipment, training, and emergency reporting requirements. Unlike most MSHA rules, these emergency rules will become effective immediately upon their publication in the Federal Register. Implementing and complying with these new laws and regulations could adversely affect our results of operation and financial position.

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

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

Tax Risks to Our Common Unitholders

If we were to become subject to entity-level taxation for federal or state tax purposes, then 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.

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

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us or as an entity, the cash available for distribution to you would be reduced.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contest will reduce cash available for distribution to our unitholders.

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 results from your share of our taxable income.

 

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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. Prior distributions to you in excess of the total net taxable income you were allocated for a unit, which decreased your tax basis in that unit, will, in effect, become taxable income to you if the unit is sold at a price greater than your tax basis in that unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you.

Tax-exempt entities and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.

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

We will 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 will adopt depreciation and amortization positions that may not conform with 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.

You will likely be subject to state and local taxes and income tax return filing requirements 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. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our units.

The sale or exchange of 50% or more of our capital and profits interests within a 12-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. Thus, if this occurs you will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to you with respect to that period. Although the amount of increase cannot be estimated because it depends upon numerous factors including the timing of the termination, the amount could be material. Our termination, currently would not affect our classification, as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

 

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ITEM 2. PROPERTIES

Coal Reserves

We must obtain permits from applicable state regulatory authorities before beginning to mine particular reserves. 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. We are required to post bonds to secure performance under our permits. As is typical in the coal industry, we strive to obtain mining permits within a time frame that allows us to mine reserves as planned on an uninterrupted basis. We begin preparing applications for permits for areas that we intend to mine sufficiently in advance of our planned mining activities to allow adequate time to complete the permitting process. Regulatory authorities have considerable discretion in the timing of permit issuance, and the public has rights to comment on and otherwise engage in the permitting process, including intervention in the courts. For the reserves set forth in the table below, we are not currently aware of matters which would significantly hinder our ability to obtain future mining permits on a timely basis.

Our reported coal reserves are those we believe can be economically and legally extracted and produced at the time of the filing of this Annual Report on Form 10-K and are in accordance with guidance from SEC Industry Guide No. 7. 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, 2005, we had approximately 549.0 million tons of proven and probable coal reserves in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia. 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). For information on location of our mines, please read “Mining Operations” under “Item 1. Business.”

The following table sets forth reserve information, at December 31, 2005, about each of our mining complexes:

 

Operations

   Mine Type    Heat Content
(Btus per pound)
   Proven and Probable Reserves     Reserve Assignment  
         Pounds S02 per MMbtu    
         <1.2     1.2-2.5     >2.5     Total     Assigned     Unassigned  
               (tons in millions)              

Illinois Basin Operations

                  

Dotiki

   Underground    12,300    —       —       89.5     89.5     89.5     —    

Warrior

   Underground    12,500    —       —       17.8     17.8     17.8     —    

Pattiki

   Underground    11,700    —       —       47.6     47.6     47.6     —    

Hopkins

   Underground    11,300    —       —       56.7     56.7     36.5     20.2  
   / Surface       —       —       7.6     7.6     7.6     —    

Gibson (North)

   Underground    11,600    —       27.2     7.9     35.1     35.1     —    

Gibson (South)

   Underground    11,600    —       18.6     64.1     82.7     —       82.7  
                                          

Region Total

         —       45.8     291.2     337.0     234.1     102.9  
                                          

Central Appalachia Operations

                  

Pontiki

   Underground    12,800    6.5     11.9     —       18.4     18.4     —    

MC Mining

   Underground    12,800    21.0     —       1.8     22.8     22.8     —    
                                          

Region Total

         27.5     11.9     1.8     41.2     41.2     —    
                                          

Northern Appalachia Operations

                  

Mettiki

   Underground    13,000    —       8.1     10.5     18.6     18.6     —    

Mettiki (WV)

   Underground    13,000    —       6.7     18.3     25.0     25.0     —    

Tunnel Ridge

   Underground    12,600    —       —       70.5     70.5     70.5     —    

Penn Ridge

   Underground    12,500    —       —       56.7     56.7     56.7     —    
                                          

Region Total

         —       14.8     156.0     170.8     170.8     —    
                                          

Total

         27.5     72.5     449.0     549.0     446.1     102.9  
                                          

% of Total

         5.0 %   13.2 %   81.8 %   100 %   81.3 %   18.7 %
                                          

 

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

Reserve estimates will change from time to time to reflect evolving market conditions, mining activities, additional analyses, new engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods, and other factors.

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. The 27.5 million tons of reserves listed as <1.2 pounds of SO2 per MMbtu are compliance coal which means coal that meets sulfur emission standards imposed by Phase I and II of the CAA.

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

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

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

We control certain leases for coal deposits that are near, but not contiguous to, our primary reserve bases. The tons controlled by these leases are classified as non-reserve coal deposits and are not included in our reported reserves. As of December 31, 2005, these non-reserve coal deposits are as follows: Dotiki – 20.2 million tons, Pattiki – 3.2 million tons, Hopkins County – 1.7 million tons, Gibson (North) – 0.9 million tons, Gibson (South) – 7.5 million tons, and Warrior – 8.2 million tons.

We lease almost all 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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The following table sets forth production data about each of our mining complexes:

 

Operations

   Tons Produced   

Transportation

  

Equipment

   2005    2004    2003      
     (tons in millions)          
Illinois Basin Operations               

Dotiki

   4.7    4.8    4.9    CSX, PAL; truck; barge   

CM

Warrior

   4.1    3.1    2.4    CSX, PAL; truck   

CM

Pattiki

   2.6    2.5    1.8    CSX; barge   

CM

Hopkins

   0.9    0.2    0.8    CSX, PAL; truck   

DL; CM

Gibson (North)

   3.4    3.0    2.4    Truck; barge   

CM

                    

Region Total

   15.7    13.6    12.3      
                    
Central Appalachia Operations               

Pontiki

   1.7    1.7    2.0    NS; truck   

CM

MC Mining

   1.6    1.9    1.6    CSX; truck   

CM

                    

Region Total

   3.3    3.6    3.6      
                    
Northern Appalachia Operations               

Mettiki

   3.3    3.2    3.3    Truck; CSX   

LW; CM; CS

                    

Region Total

   3.3    3.2    3.3      
                    

TOTAL

   22.3    20.4    19.2      
                    

CSX

 

-

 

CSX Railroad

PAL

 

-

 

Paducah & Louisville Railroad

NS

 

-

 

Norfolk & Southern Railroad

CM

 

-

 

Continuous Miner

CS

 

-

 

Contour Strip

DL

 

-

 

Dragline with Stripping Shovel, Front End Loaders and Dozers

LW

 

-

 

Longwall

ITEM 3. LEGAL PROCEEDINGS

We are subject to various types of litigation in the ordinary course of our business. Disputes with our customers over the provisions of long-term coal supply contracts arise occasionally and generally relate to, among other things, coal quality, quantity, pricing, and the existence of force majeure conditions. Other than the contract dispute with ICG which was settled in late 2005, as described under “Other” in “Item 8. Financial Statements and Supplementary Data – Note 17. Commitments and Contingencies,” we are not involved in any litigation involving any of our long-term coal supply contracts. However, we cannot assure you that disputes will not occur or that we will be able to resolve those disputes in a satisfactory manner. We are not engaged in any litigation that we believe is material to our operations, including under the various environmental protection statutes to which we are subject. The information under “General Litigation” and “Other” under “Item 8. Financial Statements and Supplementary Data. – Note 18. Commitments and Contingencies” is incorporated herein by this reference.

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

None.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The common units representing limited partners’ interests are listed on the Nasdaq National Market under the symbol “ARLP”. The common units began trading on August 20, 1999. On March 10, 2006, the closing market price for the common units was $36.32 per unit. As of March 10, 2006, there were 36,426,306 common units outstanding, which included 6,422,531 common units that converted from subordinated units in November 2003 and 2004. There were approximately 20,200 record holders and beneficial owners (held in street name) of common units at December 31, 2005.

 

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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 2004

   $ 20.455    $ 15.255   

$0.3125 (paid May 14, 2004)

2nd Quarter 2004

   $ 23.690    $ 16.550   

$0.3250 (paid August 13, 2004)

3rd Quarter 2004

   $ 28.285    $ 22.060   

$0.3250 (paid November 12, 2004)

4th Quarter 2004

   $ 37.385    $ 27.400   

$0.3750 (paid February 14, 2005)

1st Quarter 2005

   $ 40.495    $ 30.100   

$0.3750 (paid May 13, 2005)

2nd Quarter 2005

   $ 38.300    $ 27.750   

$0.4125 (paid August 12, 2005)

3rd Quarter 2005

   $ 48.410    $ 35.550   

$0.4125 (paid November 14, 2005)

4th Quarter 2005

   $ 46.600    $ 35.450   

$0.4600 (paid February 14, 2006)

We will 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 of any debt instrument or other agreement of ours or any of its 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” contained herein.

ITEM 6. SELECTED FINANCIAL DATA

Our historical financial data below were derived from our audited consolidated financial statements as of and for the years ended December 31, 2005, 2004, 2003, 2002 and 2001. We acquired Warrior from ARH Warrior Holdings, Inc. (ARH Warrior Holdings), a subsidiary of Alliance Resource Holdings, in February 2003. Because the Warrior acquisition was between entities under common control, it is accounted for at historical cost in a manner similar to that used in a pooling of interests. Accordingly, the financial statements as of December 31, 2002, and for each of the two years in the period ended December 31, 2002, have been restated to reflect the combined historical results of operations, financial position, and cash flows of the Partnership and Warrior. ARH Warrior Holdings acquired the assets that comprise Warrior on January 26, 2001.

 

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

 

   Year Ended December 31,  
   2005     2004     2003     2002     2001  

Statements of Income:

          

Sales and operating revenues

          

Coal sales

   $ 768.9     $ 599.4     $ 501.6     $ 479.5     $ 453.1  

Transportation revenues

     39.1       29.8       19.5       19.0       18.2  

Other sales and operating revenues

     30.7       24.1       21.6       20.4       6.2  
                                        

Total revenues

     838.7       653.3       542.7       518.9       477.5  
                                        
Expenses:           

Operating expenses

     521.5       436.4       368.8       367.5       337.2  

Transportation expenses

     39.1       29.8       19.5       19.0       18.2  

Outside purchases

     15.1       9.9       8.5       10.1       28.9  

General and administrative

     33.5       45.4       28.3       20.3       18.7  

Depreciation, depletion and amortization

     55.6       53.7       52.5       52.4       50.7  

Interest expense

     11.8       15.0       16.0       16.4       16.8  

Net gain from insurance settlement (1)

     —         (15.2 )     —         —         —    
                                        

Total expenses

     676.6       575.0       493.6       485.7       470.5  
                                        

Income from operations

     162.1       78.3       49.1       33.2       7.0  

Other income

     0.6       1.0       1.4       0.5       0.8  
                                        

Income before income taxes and cumulative effect of accounting change

     162.7       79.3       50.5       33.7       7.8  

Income tax expense (benefit)

     2.7       2.7       2.6       (1.1 )     (0.8 )
                                        

Income before cumulative effect of accounting change

     160.0       76.6       47.9       34.8       8.6  

Cumulative effect of accounting change (2)

     —         —         —         —         7.9  
                                        

Net income

   $ 160.0     $ 76.6     $ 47.9     $ 34.8     $ 16.5  
                                        

General Partners’ interest in net income

   $ 12.4     $ 3.3     $ 0.3     $ (0.8 )   $ (0.2 )
                                        

Limited Partners’ interest in net income

   $ 147.6     $ 73.3     $ 47.6     $ 35.6     $ 16.7  
                                        

Basic net income per limited partner unit

   $ 2.89     $ 1.76     $ 1.30     $ 1.14     $ 0.54  
                                        

Basic net income per limited partner unit before accounting change

   $ 2.89     $ 1.76     $ 1.30     $ 1.14     $ 0.29  
                                        

Diluted net income per limited partner unit

   $ 2.84     $ 1.71     $ 1.26     $ 1.11     $ 0.53  
                                        

Diluted net income per limited partner unit before accounting change

   $ 2.84     $ 1.71     $ 1.26     $ 1.11     $ 0.29  
                                        

Weighted average number of units outstanding-basic

     36,288,527       35,881,896       35,161,468       30,810,622       30,810,622  
                                        

Weighted average number of units outstanding-diluted

     36,977,061       36,874,336       36,325,678       31,685,416       31,369,100  
                                        
Balance Sheet Data:           

Working capital (deficit)

   $ 76.1     $ 54.2     $ 16.4     $ (15.8 )   $ 0.9  

Total assets

     532.7       412.8       336.5       316.9       310.3  

Long-term debt

     144.0       162.0       180.0       195.0       211.3  

Total liabilities

     376.9       357.6       323.9       355.7       347.8  

Partners’ capital (deficit)

     155.8       55.2       12.6       (38.8 )     (37.6 )
Other Operating Data:           

Tons sold

     22.8       20.8       19.5       18.4       18.6  

Tons produced

     22.3       20.4       19.2       18.0       17.4  

Revenues per ton sold (3)

   $ 35.07     $ 29.98     $ 26.83     $ 27.17     $ 24.69  

Cost per ton sold (4)

   $ 25.00     $ 23.64     $ 20.80     $ 21.63     $ 20.69  
Other Financial Data:           

Net cash provided by operating activities

   $ 193.6     $ 145.1     $ 110.3     $ 101.3     $ 70.5  

Net cash used in investing activities

     (110.2 )     (77.6 )     (77.8 )     (56.9 )     (31.1 )

Net cash used in financing activities

     (82.6 )     (46.4 )     (31.3 )     (46.4 )     (35.2 )

EBITDA (5)

     230.1       147.9       119.0       102.5       83.2  

Maintenance capital expenditures (6)

     56.7       31.6       30.0       29.0       24.4  

(1)

Represents the net gain from the final settlement with our insurance underwriters for claims relating to the Dotiki Mine Fire Incident. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Dotiki Fire Incident” for a description of the accounting treatment of expenses and insurance proceeds associated with the Dotiki Fire Incident.

(2)

Represents the cumulative effect of the change in the method of estimating coal workers’ pneumoconiosis (“black lung”) benefits liability effective January 1, 2001.

(3)

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

(4)

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

(5)

EBITDA is defined as net income before net interest expense, income taxes 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:

 

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

 

   

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

 

   

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

 

   

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

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

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

 

     Year Ended December 31,  
   2005     2004     2003     2002     2001  

Cash flows provided by operating activities

   $ 193,618     $ 145,055     $ 110,312     $ 101,306     $ 70,465  

Reclamation and mine closing

     (1,918 )     (1,622 )     (1,341 )     (1,365 )     (1,175 )

Coal inventory adjustment to market

     (573 )     (488 )     (687 )     (48 )     (233 )

Other

     (759 )     (255 )     353       1,014       890  

Loss on retirement of damaged vertical belt equipment

     (1,298 )     —         —         —         —    

Net effect of working capital changes

     26,577       (12,405 )     (8,240 )     (13,714 )     (2,706 )

Interest expense

     11,816       14,963       15,981       16,360       16,772  

Income taxes

     2,682       2,641       2,577       (1,094 )     (836 )
                                        

EBITDA

     230,145       147,889       118,955       102,459       83,177  

Depreciation, depletion and amortization

     (55,637 )     (53,664 )     (52,495 )     (52,408 )     (50,696 )

Interest expense

     (11,816 )     (14,963 )     (15,981 )     (16,360 )     (16,772 )

Income taxes

     (2,682 )     (2,641 )     (2,577 )     1,094       836  
                                        

Net income

   $ 160,010     $ 76,621     $ 47,902     $ 34,785     $ 16,545  
                                        

(6)

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. Maintenance capital expenditures for the years ended December 31, 2002 and 2001 have not been restated to include Warrior.

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 operation should be read in conjunction with the historical financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K. We acquired Warrior from ARH Warrior Holdings, a subsidiary of Alliance Resource Holdings, in February 2003. Because the Warrior acquisition was between entities under common control, it is accounted for at historical cost in a manner similar to that used in a pooling of interests. Accordingly, the financial statements as of December 31, 2002, and for each of the two years in the period ended December 31, 2002, have been restated to reflect the combined historical results of operations, financial position and cash flows of the Partnership and Warrior. ARH Warrior Holdings acquired Warrior on January 26, 2001. 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.”

 

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Business

We are a diversified producer and marketer of coal to major U.S. utilities and industrial users. In 2005, our total production was 22.3 million tons and our total sales were 22.8 million tons. The coal we produced in 2005 was approximately 30.0% low-sulfur coal, 14.8% medium-sulfur coal and 55.2% high-sulfur coal.

At December 31, 2005, we had approximately 549.0 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.

In 2005, approximately 83.7% of our sales tonnage was consumed by electric utilities or coal sunfuel facilities, whose ultimate customers are electric utilities with the balance consumed by cogeneration plants and industrial users. Our largest customers in 2005 were SSO, TVA and Mt. Storm Coal Supply. In 2005, approximately 86.0% of our sales tonnage, including approximately 85.6% of our medium- and high-sulfur coal sales tonnage, was sold under long-term contracts. The balance of our sales were 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 2005, approximately 89.8% of our medium- and high-sulfur coal was sold to utility plants with installed pollution control devices, also known as scrubbers, to remove sulfur dioxide.

In 2002, we entered into long-term agreements with SSO to host and operate its coal synfuel production facility currently located at Warrior, supply the facility with coal feedstock, assist SSO with the marketing of coal synfuel and provide it with other services. These agreements provide us with coal sales and rental and service fees from SSO based on the synfuel facility throughput tonnages. Certain of the operating services provided to SSO are performed by Alliance Service, a wholly-owned subsidiary of Alliance Coal. Alliance Service is subject to federal and state income taxes.

In 2005, Gibson and Mettiki entered into long-term agreements with PCIN and Mt. Storm Coal Supply, respectively, which also own coal synfuel facilities. At Gibson, we host PCIN’s coal synfuel facility, supply the facility with coal feedstock, assist PCIN with the marketing of coal synfuel and provide it with other services. At Mettiki, we supply Mt. Storm Coal Supply with coal feedstock.

All of the coal synfuel related agreements expire on December 31, 2007 and are contingent on the ability of the synfuel facilities’ members to use certain qualifying tax credits applicable to the facilities. The term of each of these agreements is subject to early cancellation provisions customary for transactions of these types, including the unavailability of coal synfuel tax credits, the termination of associated coal synfuel sales contracts, and the occurrence of certain force majeure events. We have maintained “back up” coal supply agreements with each coal synfuel customer that automatically provide for sale of our coal to these customers in the event they do not purchase coal synfuel from the synfuel facilities.

For 2005, the incremental net income benefit from the combination of the various coal synfuel-related agreements was approximately $24.1 million, assuming that coal pricing would not have increased without the availability of synfuel. The continuation of the incremental net income benefit associated with coal synfuel agreements cannot be assured. Pursuant to our coal synfuel related agreements, we are not obligated to make retroactive adjustments or reimbursements if the synfuel facilities owners’ tax credits are disallowed.

In June 2003, the IRS suspended the issuance of private letter rulings on the significant chemical change requirement to qualify for synfuel tax credits and announced that it was reviewing the test procedures and results used by taxpayers to establish that a significant chemical change had occurred. In October 2003, the IRS completed its review and concluded that the test procedures and results were scientifically valid if applied in a consistent and unbiased manner. The IRS has resumed issuing private letter rulings under its existing guidelines. SSO has advised us that its private letter ruling could be reviewed by the IRS as part of a tax audit, similar to the IRS reviews of other synfuel procedures.

One of our business strategies is to continue to make productivity improvements to remain a low-cost producer in each region in which we operate. Our principal expenses related to the production of coal are labor and benefits, equipment, materials and supplies, maintenance, royalties and excise taxes. Unlike most of our competitors in the eastern U.S., we employ a totally union-free workforce. Many of the benefits of the union-free workforce are not necessarily reflected in direct costs, but we believe are related to higher productivity. In addition, while we do not pay our customers’

 

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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.

Summary

In 2005, we reported record net income of $160.0 million, an increase of 108.8% over 2004 net income of $76.6 million. These results were achieved despite lost production, continuing fixed expenses, and other expenses incurred as a result of the MC Mining Fire and Pattiki Vertical Belt Incidents described below. Financial results for 2004 include the impact of lost production, continuing fixed expenses and other expenses incurred as a result of the Dotiki Fire Incident offset by the final settlement of an insurance claim with our insurance underwriters relating to the Dotiki Fire Incident described below. Tons produced increased 9.4% over 2004 to 22.3 million tons in 2005. Tons sold increased 9.7% over 2004 to 22.8 million tons in 2005.

During 2005, we benefited from strong coal markets as revenues rose to record levels and average coal sales prices in 2005 increased 16.9% compared to 2004.

We have commitments for substantially all of our 2006 production. For our estimated 2007 production, approximately 70% is committed under existing coal sales agreements and approximately 42% of the committed tonnage is subject to market price negotiations.

Analysis of Historical Results of Operations

2005 Compared with 2004

 

     December 31,    December 31,
   2005    2004    2005    2004
     (in thousands)    (per ton sold)

Tons sold

     22,849      20,823      N/A      N/A

Tons produced

     22,290      20,377      N/A      N/A

Coal Sales

   $ 768,958    $ 599,399    $ 33.65    $ 28.79

Operating Expenses and Outside Purchases

   $ 536,601    $ 446,384    $ 23.48    $ 21.44

Coal sales. Coal sales increased 28.3% to $769.0 million for 2005 from $599.4 million for 2004. The increase of $169.6 million reflects increased sales volumes (contributing $58.3 million of the increase) and higher coal sales prices (contributing $111.3 million of the increase). Tons sold increased 9.7% to 22.8 million tons for 2005 from 20.8 million tons in 2004, primarily reflecting an increase in tons produced. Tons produced increased 9.4% to 22.3 million tons for 2005 from 20.4 million tons in 2004.

Operating expenses. Operating expenses increased 19.5% to $521.5 million in 2005 from $436.5 million in 2004. The increase of $85.0 million primarily resulted from an increase in operating expenses associated with additional coal sales of 2.0 million tons, including the following specific factors:

 

   

Labor and benefit costs increased $27.3 million reflecting increased headcount, pay rate increases and escalating health care costs;

 

   

Material and supplies, and maintenance costs increased $32.6 million and $7.8 million, respectively, reflecting increased production and increased costs for the products and services used in the mining process;

 

   

Third party mining costs increased $7.5 million reflecting the addition of two small third party mining operations at Mettiki;

 

   

Production taxes and royalties (which are incurred as a percentage of coal sales or volumes) increased $14.1 million;

 

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Coal supply agreement buy-out expense decreased $2.1 million;

 

   

The impact of $2.9 million of expenses related to the Pattiki Vertical Belt Incident along with expenses associated with the MC Mining Fire Incident, both of which incidents are described below; and

 

   

Operating expenses were reduced by $4.9 million, reflecting the net of additional operating expenses incurred in the mine development process offset by revenues received for coal produced incidental with the mine development process.

Operating expenses in 2004 include a $3.5 million buy-out expense of several coal contracts that allowed us to take advantage of higher spot coal prices in 2005 and out-of-pocket expenses related to the Dotiki Fire that were not offset by proceeds from the final settlement with our insurance underwriters. Please read “—Dotiki Fire Incident” below.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of rental and service fees to coal synfuel production facilities and Mt. Vernon Transfer Terminal transloading fees. Other sales and operating revenues increased 27.5% to $30.7 million in 2005 from $24.1 million in 2004. The increase of $6.6 million was primarily attributable to $4.5 million of additional rent and service fees associated with a new third-party coal synfuel facility at the Gibson, which began producing synfuel in May 2005, $0.4 million of rent and service fees associated with increased volumes at the third-party coal synfuel facility at Warrior and $1.1 million of additional transloading fees attributable to increased transloading volumes at the Mt. Vernon Transfer Terminal.

Outside purchases. Outside purchases increased $5.2 million to $15.1 million in 2005 from $9.9 million in 2004. The increase was primarily attributable to the previously described coal supply arrangement with a third-party supplier, in the Illinois Basin ($8.3 million) which also contributed to additional coal sales volumes at our Illinois Basin operations offset by lower outside purchases in Central Appalachia ($3.4 million).

General and administrative. General and administrative expenses for 2005 decreased to $33.5 million compared to $45.4 million for 2004. The decrease of $11.9 million resulted from lower incentive compensation expense related to the Long-Term Incentive Plan (LTIP) of $12.1 million. The lower incentive compensation expense for the LTIP is primarily attributable to a reduction in the number of restricted units outstanding due to the vesting in November 2005 and 2004 of the LTIP, units for grant years 2003 and 2000 to 2002, respectively, combined with a lower incremental change in the market value of our common units from 2004 to 2005 than from 2003 to 2004. The reduction in incentive compensation expense was partially offset by increased salaries and related costs and a number of other general and administrative costs, none of which was individually significant.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased to $55.6 million in 2005 compared to $53.7 million in 2004. The increase of $1.9 million was primarily the result of additional depreciation expense associated with operating Hopkins County Coal for the full year 2005 compared to three months in 2004 after resumption of operations following the temporary idling of Hopkins’ surface mine and increased capital expenditures and infrastructure investments in recent years, which have increased our production capacity.

Interest expense. Interest expense decreased to $11.8 million in 2005 from $15.0 million in 2004. The decrease of $3.2 million was principally attributable to increased interest income earned on increased marketable securities which is netted against interest expense in addition to the capitalization of $0.6 million in 2005 related to the development at the Elk Creek and Mountain View mines. We had no borrowings under the credit facility during 2005 or 2004.

Transportation revenues and expenses. Transportation revenues and expenses increased 31.0% to $39.1 million in 2005 from $29.8 million for 2004. The increase of $9.3 million was primarily attributable to increased shipments to customers that reimburse us for transportation costs rather than arranging and paying for transportation directly with transportation providers. Transportation services are a pass-through to our customers. Consequently, we do not realize any margin on transportation revenues.

Income before income tax expense. Income before income tax expense increased 105.3% to $162.7 million for 2005 compared to $79.3 million for 2004. The increase was primarily attributable to increased sales volumes, higher coal prices and reduced general and administrative expenses, primarily reflecting lower incentive compensation expense, partially offset by higher operating expenses and expenses related to the Pattiki Vertical Belt Incident and MC Mining Fire Incident described below. The 2004 results included a $3.5 million buy-out expense of several coal contracts which allowed us to take advantage of higher spot coal prices in 2005 in addition to the impact of lost production, continuing fixed expenses and other expenses incurred as a result of the Dotiki Fire Incident offset by the final settlement of an insurance claim with our insurance underwriters relating to the Dotiki Fire Incident described below.

 

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Income tax expense. Income tax expense was comparable for both 2005 and 2004 at $2.7 and $2.6 million, respectively.

Our 2005 Segment Adjusted EBITDA increased $70.3 million, or 36.4% to $263.6 million from 2004 Segment Adjusted EBITDA of $193.3 million. Segment Adjusted EBITDA, tons sold, coal sales, operating revenues and Adjusted Segment EBITDA Expense by segment are as follows (in thousands):

 

     Year Ended December 31,    Increase (Decrease)  
     2005    2004   

Segment Adjusted EBITDA

          

Illinois Basin

   $ 183,075    $ 121,763    $ 61,312     50.4 %

Central Appalachia

     41,583      28,953      12,630     43.6 %

Northern Appalachia

     36,047      41,141      (5,094 )   (12.4 )%

Other and Corporate

     2,924      1,432      1,492    
                        

Total Segment Adjusted EBITDA (1)

   $ 263,629    $ 193,289    $ 70,340     36.4 %
                        

Tons sold

          

Illinois Basin

     16,264      13,760      2,504     18.2 %

Central Appalachia

     3,249      3,781      (532 )   (14.1 )%

Northern Appalachia

     3,330      3,282      48     1.5 %

Other and Corporate

     6      —        6    
                        

Total tons sold

     22,849      20,823      2,026     9.7 %
                        

Coal sales

          

Illinois Basin

   $ 504,916    $ 356,307    $ 148,609     41.7 %

Central Appalachia

     153,615      143,160      10,455     7.3 %

Northern Appalachia

     106,997      99,932      7,065     7.1 %

Other and Corporate

     3,430      —        3,430    
                        

Total coal sales

   $ 768,958    $ 599,399    $ 169,559     28.3 %
                        

Other sales and operating revenues

          

Illinois Basin

   $ 24,493    $ 19,087    $ 5,406     28.3 %

Central Appalachia

     282      187      95     50.8 %

Northern Appalachia

     2,163      2,127      36     1.7 %

Other and Corporate

     3,753      2,672      1,081    
                        

Total other sales and operating revenues

   $ 30,691    $ 24,073    $ 6,618     27.5 %
                        

Segment Adjusted EBITDA Expense

          

Illinois Basin

   $ 346,335    $ 268,848    $ 77,487     28.8 %

Central Appalachia

     112,313      114,394      (2,081 )   (1.8 )%

Northern Appalachia

     73,112      60,917      12,195     20.0 %

Other and Corporate

     4,260      1,241      3,019    
                        

Total Segment Adjusted EBITDA Expense (2)

   $ 536,020    $ 445,400    $ 90,620     20.3 %
                        

(1)

Segment Adjusted EBITDA is defined as net income before income tax expense (benefit), interest expense and interest income, depreciation, depletion and amortization, and general and administrative expense. Adjusted Segment EBITDA is reconciled to net income below.

(2)

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

Illinois Basin – Segment Adjusted EBITDA for 2005 increased 50.4%, to $183.1 million from 2004 Segment Adjusted EBITDA of $121.8 million. The increase of $61.3 million was primarily attributable to increased coal sales which rose by $148.6 million, or 41.7%, to $504.9 million during 2005 as compared to $356.3 million in 2004.

 

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Increased coal sales in 2005 reflect higher average coal sales prices per ton which increased $5.15 per ton to $31.05 per ton (contributing $83.8 million of the increase in coal sales) and increased tons sold of 2.5 million tons (contributing $64.8 million of the increase in coal sales). Other sales and operating revenues increased $5.4 million, primarily due to $4.5 million of revenues associated with the coal synfuel facility that began operating at Gibson in 2005. Total Segment Adjusted EBITDA Expense for 2005 increased 28.8% to $346.3 million from 268.8 million in 2004. On a per ton sold basis, 2005 Segment Adjusted EBITDA Expense rose to $21.30 per ton, an increase of 9.0% over the 2004 Segment Adjusted EBITDA Expense per ton of $19.54 per ton. The increase in 2005 Segment Adjusted EBITDA Expense in 2005 compared to 2004 primarily reflects the impact of cost increases described above under consolidated operating expenses and outside purchases, partially offset by the benefit of increased tons produced, which increased 2.2 million tons in 2005 to 15.7 million tons. Segment Adjusted EBITDA for the year 2004 includes $15.2 million reported as the net gain from insurance settlement associated with the Dotiki Fire Incident.

Central Appalachia — Segment Adjusted EBITDA for 2005 increased $12.6 million, or 43.6%, to $41.6 million as compared to 2004 Segment Adjusted EBITDA of $29.0 million. The increase was primarily attributable to increased coal sales of $10.5 million, reflecting a higher average coal sales price per ton of $47.27 in 2005, an increase of $9.41 per ton over the 2004 average coal sales price per ton, (which contributed $30.6 million of the increase in coal sales) partially offset by a reduction in tons sold in 2005 to 3.2 million tons, a decrease of 0.5 million tons sold from 2004 (resulting in a reduction of coal sales of $20.1 million). Segment Adjusted EBITDA Expense for 2005 decreased 1.8% to $112.3 million from $114.4 million in 2004. On a per ton basis, 2005 Segment Adjusted EBITDA Expense rose by $4.31, or 14.3%, to $34.56 per ton reflecting the impact of cost increases described under consolidated operating expenses above. This increase in per ton expense included the continuing impact of the MC Mining Fire Incident, partially offset by lower outside purchases ($3.5 million), and less favorable mining conditions, which contributed to lower production (0.4 million tons) resulting in fewer tons available for sale.

Northern Appalachia – Segment Adjusted EBITDA for 2005 decreased $5.1 million, or 12.4%, to $36.0 million as compared to 2004 Segment Adjusted EBITDA of $41.1 million. The decrease was primarily due to higher costs, reflecting less favorable mining conditions at Mettiki as the D-Mine approaches the depletion of its coal reserves. Segment Adjusted EBITDA Expense for 2005 increased 20.0% to $73.1 million as compared to $60.9 million in 2004. On a per ton basis, 2005 Segment Adjusted EBITDA Expense increased 18.3% to $21.95. The impact of higher costs was partially offset by higher coal sales in 2005, which increased $7.1 million to $107.0 million, primarily reflecting a 5.5% increase in the average coal sales price per ton which rose $1.68 per ton to $32.13 per ton (contributing $5.6 million of the increase in coal sales). The increase in the average sales price per ton primarily reflects coal sales that began in 2005 to a third-party coal synfuel producer.

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

 

     Year Ended December 31,  
     2005     2004  

Segment Adjusted EBITDA

   $ 263,629     $ 193,289  

General & administrative

     (33,484 )     (45,400 )

Depreciation, depletion and amortization

     (55,637 )     (53,664 )

Interest expense

     (11,816 )     (14,963 )

Income taxes

     (2,682 )     (2,641 )
                

Net income

   $ 160,010     $ 76,621  
                

2004 Compared with 2003

 

     December 31,    December 31,
   2004    2003    2004    2003
     (in thousands)    (per ton sold)

Tons sold

     20,823      19,467      N/A      N/A

Tons produced

     20,377      19,238      N/A      N/A

Coal Sales

   $ 599,399    $ 501,596    $ 28.79    $ 25.77

Operating Expenses and Outside Purchases

   $ 446,384    $ 377,343    $ 21.44    $ 19.38

Coal sales. Coal sales increased 19.5% to $599.4 million for 2004 from $501.6 million for 2003. The increase of $97.8 million reflects higher prices on long-term coal sales agreements and the sale of additional production at significantly higher prices on short-term coal sales agreements into the export and Central Appalachia coal markets. The increased average sales price contributed $62.9 million to the total increase in coal sales and an increase in tons sold contributed $34.9 million to the total increase in coal sales.

Higher prices on long-term contracts reflect a stronger market in the second half of 2003 when contracts were entered into for shipments in 2004. The export market opportunities for the U.S. coal industry were attributable generally

 

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to strong economic expansion in China. The increase in Central Appalachia spot market pricing was attributable primarily to a combination of the diversion of coal production from domestic markets to export markets and a decline in region-wide production. Tons sold increased 7.0% to 20.8 million for 2004 from 19.5 million in 2003, primarily reflecting an increase in tons produced. Tons produced increased 5.9% to 20.4 million for 2004 from 19.2 million in 2003.

Operating expenses. Operating expenses increased 18.3% to $436.5 million in 2004 from $368.8 million in 2003. The increase of $67.7 million was associated with additional coal sales of 1.6 million tons, including the following specific factors:

 

   

Labor and benefit costs increased $18.1 million reflecting increased headcount, pay rate increases, higher levels of overtime and escalating health care costs;

 

   

Material and supplies and maintenance costs increased $19.5 million and $9.3 million, respectively, reflecting increased production and increased costs for the products and services used in the mining process;

 

   

Third-party mining costs increased $1.9 million reflecting the addition, late in the year 2004, of two small third party mining operations at Mettiki;

 

   

Production taxes and royalties (which are incurred as a percentage of coal sales or volumes) increased $7.7 million;

 

   

Coal supply agreement buy-out expense of $3.5 million; and

 

   

Expenses of $4.1 million associated with the MC Mining Fire Incident.

Our initial estimate of the minimum non-reimbursable costs attributable to the MC Mining Fire Incident was $4.1 million. The $3.5 million buy-out expense of several coal supply agreements allowed us to take advantage of anticipated higher spot coal prices in 2005. Additionally, operating expense per ton sold was adversely impacted by adverse geologic conditions at our Pontiki mine and increased longwall moves associated with shorter longwall panels at Mettiki.

Outside purchases. Outside purchases increased 16.5% to $9.9 million in 2004 from $8.5 million in 2003. The increase was primarily attributable to an increase in outside purchases associated with our Illinois Basin ($4.6 million) and Central Appalachia ($2.7 million) operations partially offset by a decrease in the domestic brokerage market of $6.1 million.

Other sales and operating revenues. Other sales and operating revenues are primarily comprised of services to the coal synfuel production facility and increased 11.5% to $24.1 million in 2004 from $21.6 million in 2003. The increase of $2.5 million was primarily attributable to $1.5 million of additional rental and service fees associated with increased volumes at SSO’s coal synfuel facility that originally operated at Hopkins County Coal and was relocated to Warrior in April 2003 and $1.1 million of additional transloading fees attributable to increased volumes at the Mt. Vernon Transfer Terminal.

General and administrative. General and administrative expenses for 2004 increased to $45.4 million compared to $28.3 million for 2003. The $17.1 million increase was primarily attributable to higher incentive compensation expense, which increased approximately $16.0 million. The last reported sales price of our common units on the NASDAQ was $37.00 on December 31, 2004 compared to a closing price of $17.19 on December 31, 2003 (both closing prices are adjusted for the two-for-one unit split in September 2005).

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased to $53.7 million in 2004 compared to $52.5 million in 2003. The increase of $1.2 million was primarily the result of additional depreciation expense associated with increased capital expenditures and infrastructure investments over the last few years, which have increased our production capacity. The increase was partially offset by a $2.6 million decrease in depreciation attributable to operating Hopkins County Coal six months in 2003 compared to three months in 2004.

 

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Interest expense. Interest expense declined 6.4% to $15.0 million in 2004 from $16.0 million in 2003. The decrease of $1.0 million was attributable to reduced interest expense associated with the revolving credit facility. We had no borrowings under the credit facility during 2004.

Transportation revenues and expenses. Transportation revenues and expenses increased 52.5% to $29.8 million in 2004 from $19.6 million for 2003. The increase of $10.2 million was primarily attributable to increased shipments to customers that reimburse us for transportation costs rather than arranging and paying for transportation directly with transportation providers. Transportation services are a pass-through to our customers. Consequently, we do not realize any margin on transportation revenues.

Income before income tax expense. Income before income tax expense increased 57.0% to $79.3 million for 2004 compared to $50.5 million for 2003. The increase was primarily attributable to higher sales prices, reflecting the continued strengthening of domestic and international coal markets, partially offset by higher operating expenses and increased general and administrative expense, primarily attributable to higher incentive compensation expense.

Income tax expense. Income tax expense was comparable for both 2004 and 2003 at $2.6 million for each year.

Our Segment Adjusted EBITDA of $193.3 million for 2004 was $46.0 million, or 31.3% higher than 2003 Segment Adjusted EBITDA of $147.2 million. Segment Adjusted EBITDA, tons sold, coal sales, operating revenues and Adjusted Segment EBITDA Expense by segment are as follows (in thousands):

 

     Year Ended December 31,    Increase (Decrease)  
     2004    2003   

Segment Adjusted EBITDA

          

Illinois Basin

   $ 121,763    $ 95,351    $ 26,412     27.7 %

Central Appalachia

     28,953      23,962      4,991     20.8 %

Northern Appalachia

     41,141      27,288      13,853     50.8 %

Other and Corporate

     1,432      624      808     129.5 %
                        

Total Segment Adjusted EBITDA (1)

   $ 193,289    $ 147,225    $ 46,064     31.3 %
                        

Tons sold

          

Illinois Basin

     13,760      12,223      1,537     12.6 %

Central Appalachia

     3,781      3,608      173     4.8 %

Northern Appalachia

     3,282      3,445      (163 )   (4.7 )%

Other and Corporate

     —        191      (191 )  
                        

Total tons sold

     20,823      19,467      1,356     7.0 %
                        

Coal sales

          

Illinois Basin

   $ 356,307    $ 301,976    $ 54,331     18.0 %

Central Appalachia

     143,160      114,366      28,794     25.2 %

Northern Appalachia

     99,932      79,076      20,856     26.4 %

Other and Corporate

     —        6,178      (6,178 )  
                        

Total coal sales

   $ 599,399    $ 501,596    $ 97,803     19.5 %
                        

Other sales and operating revenues

          

Illinois Basin

   $ 19,087    $ 17,233    $ 1,854     10.8 %

Central Appalachia

     187      779      (592 )   (76.0 )%

Northern Appalachia

     2,127      1,980      147     7.4 %

Other and Corporate

     2,672      1,606      1,066    
                        

Total operating revenues

   $ 24,073    $ 21,598    $ 2,475     11.5 %
                        

Segment Adjusted EBITDA Expense

          

Illinois Basin

   $ 268,848    $ 223,858    $ 44,990     20.1 %

Central Appalachia

     114,394      91,183      23,211     25.5 %

Northern Appalachia

     60,917      53,768      7,149     13.3 %

Other and Corporate

     1,241      7,160      (5,919 )  
                        

Total Segment Adjusted EBITDA Expense (2)

   $ 445,400    $ 375,969    $ 69,431     18.5 %
                        

(1)

Segment Adjusted EBITDA is defined as net income before income tax expense (benefit), interest expense and interest income, depreciation, depletion and amortization, and general and administrative expense. Adjusted Segment EBITDA is reconciled to income before income taxes below.

(2)

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

 

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IIllinois Basin – Segment Adjusted EBITDA for 2004 increased $26.4 million, or 27.7%, to $121.8 million as compared to 2003 Segment Adjusted EBITDA of $95.4 million. The increase was primarily attributable to increased coal sales which rose $54.3 million in 2004 to $356.3 million, reflecting a 1.5 million ton, or 12.6%, increase in tons sold to 13.8 million tons (which contributed $37.9 million of the increase in coal sales) and a 4.8% increase in the average coal sales price per ton to $25.90 per ton (which contributed $16.4 million of the increase in coal sales). Other sales and operating revenues increased $1.9 million in 2004 to $19.1 million, reflecting additional revenues associated with SSO’s coal synfuel facility. Segment Adjusted EBITDA Expense for 2004 increased 20.1% to $268.8 million while Segment Adjusted EBITDA Expense per ton increased 6.7% to $19.54. This increase reflects the impact of increased costs as discussed under consolidated operating expenses and outside purchases above, including the $3.3 million associated with the buy-out of several coal supply agreements that allowed us to take advantage of higher spot coal prices in 2005. The impact of increased costs was partially offset by higher production in 2004, which increased 1.1 million tons, or 8.9%, to 13.5 million tons. Segment Adjusted EBITDA for the year 2004 includes $15.2 million reported as the net gain from insurance settlement associated with the Dotiki Fire Incident.

Central Appalachia – Segment Adjusted EBITDA for 2004 increased $5.0 million, or 20.8%, to $29.0 million as compared to 2003 Segment Adjusted EBITDA of $24.0 million. The increase was primarily attributable to increased coal sales, which rose $28.8 million in 2004 to $143.2 million, reflecting a 19.4% increase in the average coal sales price per ton to $37.86 per ton (which contributed $23.3 million of the increase in coal sales) and increased tons sold of 0.2 million tons (which contributed $5.5 million of the increase in coal sales). Segment Adjusted EBITDA Expense for 2004 increased 25.5% to $114.4 million while Segment Adjusted EBITDA Expense per ton increased 19.7% to $30.25, reflecting less favorable mining conditions and the impact of cost increases as discussed under consolidated operating expenses and outside purchases above. Segment Adjusted EBITDA Expense for the year 2004 included $4.1 million reflecting our initial estimate of the minimum non-reimbursable costs attributable to the MC Mining Fire Incident.

Northern Appalachia – Segment Adjusted EBITDA for 2004 increased $13.9 million, or 50.8%, to $41.1 million as compared to 2003 Segment Adjusted EBITDA of $27.3 million. The increase was primarily attributable to increased coal sales which rose $20.9 million in 2004 to $99.9 million, reflecting a 32.6% increase in the average coal sales price per ton to $30.45 (which increased coal sales by $24.6 million). The higher average coal sales price per ton was attributable to spot market opportunities for sales into the export market to satisfy demand created by economic expansion in China and India. The increase was partially offset by a 0.2 million ton decrease in tons sold during 2004 to 3.3 million tons (which reduced coal sales by $3.7 million). Segment Adjusted EBITDA Expense for 2004 increased 13.3% to $60.9 million, while Segment Adjusted EBITDA Expense per ton increased 18.9% to $18.56, primarily as a result of less favorable mining conditions and the impact of cost increases and described under consolidated operating expenses above.

Other and Corporate – Lower coal sales and Segment Adjusted EBITDA Expense reflects a reduction in coal brokerage volumes. A strengthening coal market resulted in reduced opportunities for coal brokerage transactions.

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

 

     Year Ended December 31,  
     2004     2003  

Segment Adjusted EBITDA

   $ 193,289     $ 147,225  

General & administrative

     (45,400 )     (28,270 )

Depreciation, depletion and amortization

     (53,664 )     (52,495 )

Interest expense

     (14,963 )     (15,981 )

Income taxes

     (2,641 )     (2,577 )
                

Net income

   $ 76,621     $ 47,902  
                

Long-Term Incentive Plan

On October 25, 2005, the compensation committee of our managing general partner determined that the vesting requirements for the 2003 LTIP grants of 278,710 restricted units (net of 3,700 restricted unit forfeitures) had been satisfied as of September 30, 2005. As a result of this vesting, on November 1, 2005, we issued 165,426 common units to LTIP participants. The remaining units were settled in cash primarily to satisfy individual tax obligations of the LTIP participants.

 

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Unit Split

On September 15, 2005, we completed a two-for-one split of our common units, whereby holders of record at the close of business on September 2, 2005 received one additional common unit for each common unit owned on that date. This unit split resulted in the issuance of 18,130,440 common units.

Pattiki Vertical Belt Incident

On June 14, 2005, our Pattiki mine was temporarily idled following the failure of the vertical conveyor belt system (the Vertical Belt Incident) used in conveying raw coal out of the mine. White County Coal surface personnel detected a failure of the vertical conveyor belt on June 14, 2005 and immediately shut down operation of all underground conveyor belt systems. On July 20, 2005, White County Coal’s efforts to repair the vertical belt system had progressed sufficiently to allow it to perform a full test of the vertical belt system. After evaluating the test results, the Pattiki mine resumed initial production operations on July 21, 2005. Production of raw coal has returned to levels that existed prior to the occurrence of the Vertical Belt Incident. The majority of repairs to the vertical belt conveyor system and ancillary equipment have been completed. Operating expenses were increased by $2.9 million in 2005 to reflect the estimated direct expenses and costs attributable to the Vertical Belt Incident, which estimate included a $1.3 million retirement of the damaged vertical belt equipment. We have not identified currently any significant additional costs compared to the original cost estimates. We conducted an analysis of a number of possible alternatives to mitigate the losses arising from the Vertical Belt Incident. This analysis included a review of the Vertical Belt System Design, Supply, and Oversight of Installation Contract (Installation Contract), dated December 7, 2000, between White County Coal and Lake Shore Mining, Inc. As a result of this analysis, we filed suit on January 19, 2006, against Frontier-Kemper Constructors, Inc. to whom Lake Shore Mining, Inc. had assigned all of its rights and obligations under the Installation Contract, for the damages we suffered on account of the Vertical Belt Incident. Until this litigation is resolved, however, we can make no assurances of the amount or timing of recoveries, if any. Concurrent with the renewal of our commercial property (including business interruption) insurance policies concluded on October 31, 2005, White County Coal confirmed with the current underwriters of the commercial property insurance coverage that it would not file a formal insurance claim for losses arising from or in connection with the Vertical Belt Incident.

MC Mining Fire

On December 26, 2004 the MC Mining Excel No. 3 mine was temporarily idled following the occurrence of a mine fire (MC Mining Fire Incident). The fire was discovered by mine personnel near the bottom of the Excel No. 3 mine slope late the evening of December 25, 2004. Under a firefighting plan developed by MC Mining, in cooperation with mine emergency response teams from MSHA and the Kentucky Office of Mine Safety and Licensing, the four portals at the Excel No. 3 mine were capped to deprive the fire of oxygen. A series of boreholes were then drilled into the fire area to further suppress the fire. As a result of these efforts, the mine atmosphere was rendered substantially inert, or without oxygen, and the Excel No. 3 mine fire was effectively suppressed. MC Mining then began construction of temporary and permanent barriers designed to completely isolate the mine fire area. Once construction of the permanent barriers was completed, MC Mining began efforts to repair and rehabilitate the Excel No. 3 mine infrastructure. On February 21, 2005, the repair and rehabilitation efforts had progressed sufficiently to allow initial resumption of production. Coal production has returned to near normal levels, but continues to be adversely impacted by inefficiencies attributable to or associated with the MC Mining Fire Incident.

We maintain commercial property (including business interruption) insurance policies with various underwriters, which are renewed annually in October and provide for self-retention and various applicable deductibles, including certain monetary and/or time element forms of deductibles, (collectively, the 2005 Deductibles) and 10% co-insurance (2005 Co-Insurance), but we cannot give any assurances as to the eventual timing or amount of any recovery of proceeds under these policies. We believe such insurance coverage will cover a substantial portion of the total cost of the disruption to MC Mining’s operations. However, concurrent with the renewal of our commercial property (including business interruption) insurance policies concluded on October 31, 2005, MC Mining confirmed with the current underwriters of the commercial property insurance coverage that any negotiated settlement of the losses arising from or in connection with the MC Mining Fire Incident would not exceed $40.0 million (inclusive of the 2005 Co-insurance and 2005 Deductible amounts). Until the claim is resolved ultimately, either through the claim adjustment process, settlement, or litigation, with the applicable underwriters, we can make no assurance of the amount or timing of recovery of insurance proceeds.

 

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We made an initial estimate of certain costs primarily associated with activities relating to the suppression of the fire and the initial resumption of operations. Operating expenses for 2004 were increased by $4.1 million to reflect an initial estimate of certain minimum costs attributable to the MC Mining Fire Incident that are not reimbursable under our insurance policies due to the application of the 2005 Deductibles and 2005 Co-Insurance.

Following the initial two submittals to a representative of the underwriters of our estimate of the expenses and losses (including business interruption losses) incurred by MC Mining and other affiliates arising from and in connection with the MC Mining Fire Incident (MC Mining Insurance Claim), on September 15, 2005, we filed a third partial proof of loss, with an update through July 31, 2005. Partial payments of $12.2 million were received in 2005, which are net of the 2005 Deductibles and 2005 Co-Insurance. The accounting for these partial payments and future payments, if any, made to us by the underwriters will be subject to the accounting methodology described below. We continue to evaluate our potential insurance recoveries under the applicable insurance policies in the following areas:

 

  1.

Fire Brigade/Extinguishing/Mine Recovery Expense; Expenses to Reduce Loss; Debris Removal Expenses; Demolition and Increased Cost of Construction; Expediting Expenses; and Extra Expenses incurred as a result of the fire—These expenses and other costs (e.g. professional fees) associated with extinguishing the fire, reducing the overall loss, demolition of certain property and removal of debris, expediting the recovery from the loss, and extra expenses that would not have been incurred by us, but for the MC Mining Fire Incident, are being expensed as incurred with related actual and/or estimated insurance recoveries recorded as they are considered to be probable, up to the amount of the actual cost incurred.

 

  2.

Damage to MC Mining mine property—The net book value of property destroyed of $154,000, was written off in the first quarter of 2005 with a corresponding amount recorded as an estimated insurance recovery, since such recovery is considered probable. Any insurance proceeds from the claims relating to the MC Mining mine property (other than amounts relating to the matters discussed in 1. above) that exceed the net book value of such damaged property would result in a gain. Any gain will be recorded when the MC Mining Insurance Claim is resolved and/or proceeds are received.

 

  3.

MC Mining mine business interruption losses—We have submitted to a representative of the underwriters a business interruption loss analysis for the period of December 24, 2004 through July 31, 2005. Expenses associated with business interruption losses are expensed as incurred, and estimated insurance recoveries of such losses are recognized to the extent such recoveries are considered to be probable, up to the actual amount incurred. Recoveries in excess of actual costs incurred will be recorded as gains when the MC Mining Insurance Claim is resolved and/or proceeds are received.

In 2005, pursuant to the accounting methodology described above, of the $12.2 million of partial payments received, we recorded, as an offset to operating expenses, $10.7 million, which amount represents the current estimated insurance recovery of actual costs incurred, net of the 2005 Deductibles and 2005 Co-Insurance. We continue to discuss the MC Mining Insurance Claim and the determination of the total claim amount with representatives of the underwriters. The MC Mining Insurance Claim will continue to be developed as additional information becomes available and we have completed our assessment of the losses (including the methodologies associated therewith) arising from or in connection with the MC Mining Fire Incident. At this time, based on the magnitude and complexity of the MC Mining Insurance Claim, we are unable to reasonably estimate the total amount of the MC Mining Insurance Claim as well as its exposure, if any, for amounts not covered by the our insurance program.

Dotiki Mine Fire

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

 

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On September 10, 2004, we filed a third and final proof of loss with the applicable insurance underwriters reflecting a settlement of all expenses, losses and claims incurred by Webster County Coal and other affiliates arising from or in connection with the Dotiki Fire Incident in the aggregate amount of $27.0 million, inclusive of a $1.0 million self-retention of initial loss, a $2.5 million deductible and 10% co-insurance.

During 2004, we recorded as an offset to operating expenses $5.9 million and a combined net gain of approximately $15.2 million for damage to the property destroyed, interruption of business operations (including profit recovery), and extra expenses incurred to minimize the period and total cost of disruption to operations associated with the Dotiki Fire Incident.

Ongoing Acquisition Activities

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

Liquidity and Capital Resources

Liquidity

We generally satisfy our working capital requirements and fund our capital expenditures and debt service obligations from cash generated from operations and borrowings under our revolving credit facility. We believe that the cash generated from operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled debt payments and distribution payments. To further develop available financing alternatives, in October 2002, we entered into a master lease agreement. Under the master lease agreement, lease terms and rental payments are negotiated individually when specific pieces of equipment are leased. During 2005, 2004 and 2003, we had rental expense of $0.8 million, $1.3 million and $1.0 million, respectively, under the master lease agreement. Our credit facility limits the amount of total operating lease obligations to $15.0 million payable in any period of 12 consecutive months. Our ability to satisfy our obligations and planned expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry, some of which are beyond our control.

We earn income by supplying three coal synfuel facilities with coal feedstock and assist the owners of two of these facilities with the marketing of coal synfuel as well as the provision of certain other services. Assuming that coal pricing would not have increased without the availability of coal synfuel, the incremental net income benefit associated with these facilities (i.e., which equals cash generation except for working capital timing differences) was $24.1 million for the year ended December 31, 2005.

The continuation of the incremental net income benefit associated with the coal synfuel related agreements, however, cannot be assured. The terms of the coal synfuel related agreements expire on December 31, 2007, and the agreements are not expected to be extended. Additionally, the term of the synfuel related agreements is subject to early cancellation provisions customary for transactions of these types, including the unavailability of synfuel tax credits, the termination of associated coal synfuel sales contracts, and the occurrence of certain force majeure events. However, we have maintained “back up” coal supply agreements with each coal synfuel customer that automatically provides for sale of our coal to these customers in the event they do not purchase coal synfuel.

One of the states in which we operate has established a statutory framework for tax credits against income or franchise taxes, which tax credit has benefited, directly or indirectly, coal operators or customers purchasing coal produced from mines within that state. Our indirect benefit of this state tax credit was $8.3 million for the year ended December 31, 2005. Although this tax credit is not set to expire by its terms in the near future, legislation may be proposed in the future that would eliminate the credit as a potential measure to reduce that state’s budget deficit.

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

 

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Cash Flows

Cash provided by operating activities was $193.6 million in 2005, compared to $145.1 million in 2004. The increase in cash provided by operating activities was attributable principally to an increase in net income partially offset by an increase in total working capital. Increased working capital reflects a revenue driven increase in trade receivables, increased inventories, prepaid expenses and advance royalties, partially offset by increased accounts payable due to increased production and a lesser increase in 2005 compared to 2004 in the total accrued liability for the LTIP included in the current and long-term liability due to affiliates resulting from the vesting in 2005 of the 2003 LTIP grants and in 2004 of the 2000 to 2002 LTIP grants.

Net cash used in investing activities was $110.2 million in 2005, compared to $77.6 million in 2004. The increase is primarily attributable to an increase in capital expenditures associated with the addition of continuous mining units at our Pattiki and Warrior mining complexes and costs associated with the initial development of the Elk Creek and Mountain View mines along with construction to transition the Pontiki mine into the Van Lear coal seam. The increase in investing activities was partially offset by purchases, net of proceeds, of marketable securities during 2004 of $25.7 million.

Net cash used in financing activities was $82.6 million for 2005 compared to $46.4 million for 2004. The increase is primarily attributable to a scheduled $18.0 million debt payment in August 2005 in addition to increased distributions to partners in 2005.

We have various commitments primarily related to long-term debt, operating lease commitments related to buildings and equipment, obligations for estimated reclamation and mining closing costs, capital project commitments, and pension funding. We expect to fund these commitments with cash generated from operations, proceeds from the sale of marketable securities, and borrowings under our revolving credit facility. The following table provides details regarding our contractual cash obligations as of December 31, 2005 (in thousands):

 

Contractual Obligations

   Total   

Less

than 1

year

  

2-3

years

  

4-5

years

  

After 5

years

Long-term debt

   $ 162,000    $ 18,000    $ 36,000    $ 36,000    $ 72,000

Future interest obligations on long-term debt

     62,406      12,917      21,347      15,364      12,778

Operating leases

     15,874      3,812      6,643      5,203      216

Other long-term obligations (excluding discount effect of $29.4 million for reclamation liability)

     70,652      2,597      7,675      3,223      57,157

Purchase obligations for capital projects

     10,830      10,830      —        —        —  

ICG coal purchases

     46,526      46,526      —        —        —  
                                  
   $ 368,288    $ 94,682    $ 71,665    $ 59,790    $ 142,151
                                  

We expect to contribute $7.9 million to the defined benefit pension plan (Pension Plan) during 2006. We estimate our income tax cash requirements to be approximately $2.7 million in 2006.

Capital Expenditures

Capital expenditures increased to $119.9 million in 2005 compared to $54.7 million in 2004. See discussion of “Cash Flows” above concerning the increase in capital expenditures. Capital expenditures includes items received but not yet paid, which is disclosed as non-cash activity, purchase of property, plant and equipment in “Supplemental Cash Flow Information” in “Item 8, Financial Statements—Consolidated Statements of Cash Flows.”

We currently project that our average annual maintenance capital expenditures will be approximately $59.4 million. We also currently expect to fund our anticipated total capital expenditures for 2006 of $160.0 million, with cash generated from operations and borrowings under our revolving credit facility described below.

 

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Notes Offering and Credit Facility

Alliance Resource Operating Partners, L.P., our intermediate partnership, has $162.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in nine remaining equal annual installments of $18.0 million beginning in August 2005 with interest payable semi-annually (Senior Notes). On August 22, 2003, our intermediate partnership completed an $85 million revolving credit facility (Credit Facility), which expires September 30, 2006. The Credit Facility replaced a $100 million credit facility that would have expired August 2004. We paid in full all amounts outstanding under the $100 million original credit facility with borrowings of $20 million under the Credit Facility. The interest rate on the Credit Facility is based on either the (i) London Interbank Offered Rate (LIBOR) or (ii) the Base Rate, which is equal to the greater of the JPMorgan Chase Prime Rate or the Federal Funds Rate plus 1/2 of 1%, plus, in either case, an applicable margin. We incurred certain costs aggregating $1.2 million associated with the Credit Facility. These costs have been deferred and are being amortized as a component of interest expense over the term of the Credit Facility. We had no borrowings outstanding under the Credit Facility at December 31, 2005. Letters of credit can be issued under the Credit Facility not to exceed $30.0 million. Outstanding letters of credit reduce amounts available under the Credit Facility. At December 31, 2005, we had letters of credit of $9.0 million outstanding under the Credit Facility.

The Senior Notes and Credit Facility are guaranteed by all of the subsidiaries of our intermediate partnership. The Senior Notes and Credit Facility contain various restrictive and affirmative covenants, including restrictions on the amount of distributions by our intermediate partnership and the incurrence of other debt. We were in compliance with the covenants of both the Credit Facility and Senior Notes at December 31, 2005.

We have previously entered into and have maintained agreements with two banks to provide additional letters of credit in an aggregate amount of $25.0 million to maintain surety bonds to secure our obligations for reclamation liabilities and workers’ compensation benefits as statutorily required. At December 31, 2005, we had $24.8 million in letters of credit outstanding under these agreements. Our special general partner guarantees the letters of credit.

Critical Accounting Policies

From our Summary of Significant Accounting Policies, we have identified the following accounting policies that require the exercise of our most difficult, complex and subjective levels of judgment. Our judgments in the following areas are principally based on estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements. Please see “Item 8. Financial Statements and Supplementary Data.” Actual results that are influenced by future events could materially differ from the current estimates.

Revenue Recognition

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

Long-Lived Assets

We review the carrying value of long-lived assets 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, which is based on cash flows from that asset, discounted at a rate commensurate with the risk involved. Events or changes in circumstance that could cause us to perform such a review include, but are not limited to, the loss of a major coal supply agreement, a significant decline in demand for our coal or an adverse change in geologic conditions.

 

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Mine Development Costs

Mine development costs are capitalized until production, other than production incidental to the mine development process, commences and amortized over the estimated life of the mine. Mine development costs represent costs that establish access to mineral reserves and include costs associated with sinking or driving shafts and underground drifts, permanent excavations, roads and tunnels.

Reclamation and Mine Closing Costs

The Federal SMCRA and similar state statutes require that mine property be restored in accordance with specified standards and an approved reclamation plan. We record the liability for the estimated cost of future mine reclamation and closing procedures on a present value basis when incurred, and the associated cost is capitalized by increasing the carrying amount of the related long-lived asset. Those costs relate to sealing portals at underground mines and to reclaiming the final pit and support acreage at surface mines. Other costs common to both types of mining are related to removing or covering refuse piles and settling ponds, and dismantling preparation plants, other facilities and roadway infrastructure. We had accrued liabilities of $41.3 million and $34.0 million for these costs at December 31, 2005 and 2004, respectively. The liability for mine reclamation and closing procedures is sensitive to changes in cost estimates and estimated mine lives.

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 provide for these claims through self-insurance programs. The liability for traumatic injury claims is the estimated present value of current workers’ compensation benefits, based on an annual independent actuarial study. The 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 $37.0 million and $32.6 million for these costs at December 31, 2005 and 2004, respectively. A one-percentage-point reduction in the discount rate would have increased the liability at December 31, 2005 approximately $2.1 million, which would have a corresponding increase in operating expenses.

Coal mining companies are subject to the Federal Coal Mine Health and Safety Act of 1969, 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 estimated black lung liability is based on an annual actuarial study performed by an independent actuary. The actuarial calculations are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents and interest rates. We had accrued liabilities of $23.8 million and $20.3 million for these benefits at December 31, 2005 and 2004, respectively. A one-percentage-point reduction in the discount rate would have increased the expense recognized for the year ended December 31, 2005 by approximately $1.2 million. Under the service cost method used to estimate our black lung benefits liability, actuarial gains or losses attributable to changes in actuarial assumptions such as the discount rate are amortized over the remaining service period of active miners.

Universal Shelf

In April 2002, we filed with the Securities and Exchange Commission a universal shelf registration statement allowing us to issue from time-to-time up to an aggregate of $200 million of debt or equity securities. At March 5, 2006, we had approximately $143 million available under this registration statement.

Related Party Transactions

Administrative Services

Our partnership agreement provides that our managing general partner and its affiliates be reimbursed for all direct and indirect expenses they incur or payments they make on our behalf, including, but not limited to, management’s salaries and related benefits (including incentive compensation), and accounting, budget, 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 $14,069,000, $28,536,000, and $12,471,000 for the years ended December 31, 2005, 2004, and 2003, respectively. The decrease from 2005 to 2004 was primarily attributable to lower compensation accruals for the

 

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LTIP, Short-Term Incentive Plan (STIP) and Supplemental-Executive Retirement Plan (SERP). The increase from 2003 to 2004 was primarily attributable to higher accruals for the LTIP, STIP and SERP. The expenses associated with LTIP and SERP were impacted by the market value of the our common units, which had a closing market price of $37.20, $37.00, and $17.19 at December 31, 2005, 2004 and 2003, respectively. The amounts billed by the managing general partner include $10,559,000, $24,242,000, and $9,319,000 for the years ended December 31, 2005, 2004 and 2003, respectively, for the LTIP, STIP and SERP.

Tunnel Ridge Acquisition

In January 2005, we acquired 100% of the limited liability company member interests of Tunnel Ridge, LLC (Tunnel Ridge) for approximately $500,000 and the assumption of reclamation liabilities from Alliance Resource Holdings, Inc., a company owned by our management. Tunnel Ridge controls through a coal lease agreement with our special general partner, approximately 9,400 acres of land located in Ohio County, West Virginia and Washington County, Pennsylvania containing an estimated 70 million tons of high-sulfur coal in the Pittsburgh No. 8 coal seam. Under the terms of the coal lease, beginning on January 1, 2005, Tunnel Ridge has paid and will continue to pay our special general partner an advance minimum royalty of $3.0 million per year. The advance royalty payments are fully recoupable against earned royalties.

Tunnel Ridge also has rights to surface land and other tangible assets under a separate lease agreement with our special general partner. Under the terms of the lease agreement, Tunnel Ridge has paid and will continue to pay our special general partner an annual lease payment of $240,000. The lease agreement has an initial term of four years, which may be extended to be consistent with the term of the coal lease. Lease expense was $240,000 for the year ended December 31, 2005.

The Tunnel Ridge transaction described above was a related-party transaction and, as such, was reviewed by the board of directors of our managing general partner and its conflicts committee. Based upon these reviews, it was determined that this transaction reflects market-clearing terms and conditions customary in the coal industry. As a result, the board of directors of our managing general partner and its conflicts committee approved the Tunnel Ridge transaction as fair and reasonable to us and our limited partners.

Warrior Acquisition

On February 14, 2003, we acquired Warrior Coal from an affiliate, ARH Warrior Holdings, a subsidiary of Alliance Resource Holdings, a subsidiary of ARH, pursuant to a Put/Call Agreement. Warrior Coal purchased the capital stock of Roberts Bros. Coal Co., Inc., Warrior Coal Mining Company, Warrior Coal Corporation and certain assets of Christian Coal Corp. and Richland Mining Co., Inc. in January 2001. Our managing general partner had previously declined the opportunity to purchase these assets as we had previously committed to major capital expenditures at two existing operations. As a condition to not exercising its right of first refusal, we requested that ARH Warrior Holdings enter into a put and call arrangement for Warrior Coal. We and ARH Warrior Holdings, with the approval of the conflicts committee of our managing general partner, entered into the Put/Call Agreement in January 2001. Concurrently, ARH Warrior Holdings acquired Warrior Coal in January 2001 for $10.0 million.

The Put/Call Agreement preserved the opportunity for us to acquire Warrior Coal during a specified time period. Under the terms of the Put/Call Agreement, ARH Warrior Holdings exercised its put option requiring us to purchase Warrior at a put option price of approximately $12.7 million.

The option provisions of the Put/Call Agreement were subject to certain conditions (unless otherwise waived), including, among others, (a) the non-occurrence of a material adverse change in the business and financial condition of Warrior Coal, (b) the prohibition of any dividends or other distributions to Warrior Coal’s shareholders, (c) the maintenance of Warrior Coal’s assets in good working condition, (d) the prohibition on the sale of any equity interest in Warrior Coal except for the options contained in the Put/Call Agreement, and (e) the prohibition on the sale or transfer of Warrior Coal’s assets except those made in the ordinary course of its business.

The Put/Call Agreement option prices reflected negotiated sale and purchase amounts that both parties determined would allow each party to satisfy acceptable minimum investment returns in the event either the put or call options were exercised. In January 2001 and in December 2002, we developed financial projections for Warrior Coal based on due diligence procedures we customarily perform when considering the acquisition of a coal mine. The assumptions underlying the financial projections made by us for Warrior Coal included, among others, (a) annual production levels

 

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ranging from 1.5 million to 1.8 million tons, (b) coal prices at or below the then current coal prices and (c) a discount rate of 12 percent. Based on these financial projections, as of the date of the acquisition and at December 31, 2002 and 2001, we believe that the fair value of Warrior Coal was equal to or greater than the put option exercise price.

The put option price of $12.7 million was paid to ARH Warrior Holdings in accordance with the terms of the Put/Call Agreement. In addition, we repaid Warrior Coal’s borrowings of $17.0 million under the revolving credit agreement between our special general partner and Warrior Coal. The primary borrowings under the revolving credit agreement financed new infrastructure capital projects at Warrior Coal that have contributed to improved productivity and significantly increased capacity. We funded the Warrior Coal acquisition through a portion of the proceeds received from the issuance of 4,500,000 common units. Because the Warrior Coal acquisition was between entities under common control, it has been accounted for at historical cost in a manner similar to that used in a pooling of interests.

Under the terms of the Put/Call Agreement, we assumed certain other obligations, including a mineral lease and sublease with SGP Land, a subsidiary of our special general partner, covering coal reserves that have been and will continue to be mined by Warrior Coal . The terms and conditions of the mineral lease and sub-lease remain unchanged.

SGP Land

Webster County Coal has a mineral lease and sublease with SGP Land requiring annual minimum royalty payments of $2.7 million, payable in advance through 2013 or until $37.8 million of cumulative annual minimum and/or earned royalty payments have been paid. Webster County Coal paid royalties of $3,449,000, $4,611,000, and $3,460,000 for the years ended December 31, 2005, 2004 and 2003, respectively. As of December 31, 2005, Webster County Coal has recouped, as earned royalties, all advance minimum royalty payments made under these lease terms except for $1,018,000.

Warrior Coal has a mineral lease and sublease with SGP Land. Under the terms of the lease, Warrior Coal has paid and will continue to pay in arrears an annual minimum royalty obligation of $2,270,000 until $15,890,000 of cumulative annual minimum and/or earned royalty payments have been paid. The annual minimum royalty periods are from October 1st through the end of the following September, expiring September 30, 2007. Warrior Coal paid royalties of $3,627,000, $2,561,000, and $2,453,000 for the years ended December 31, 2005, 2004, and 2003, respectively. As of December 31, 2005, Warrior Coal has recouped, as earned royalties, all advance minimum royalty payments made in accordance with these lease terms.

Under the terms of the mineral lease and sublease agreements described above, Webster County Coal and Warrior Coal also reimbursed SGP Land for SGP Land’s base lease obligations. We reimbursed SGP Land $6,379,000, $5,428,000, and $4,395,000 for the years ended December 31, 2005, 2004 and 2003 respectively, for the base lease obligations. As of December 31, 2005, Webster County Coal and Warrior Coal have recouped, as earned royalties, all advance minimum royalty payments made in accordance with these terms except for $236,000.

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 obligation of $300,000 until $6.0 million of cumulative annual minimum and/or earned royalty payments have been paid. MC Mining paid royalties of $600,000 and $479,000 during the years ended December 31, 2005 and 2003, respectively. The 2004 annual minimum royalty obligation of $300,000 was paid in January, 2005. As of December 31, 2005, MC Mining has recouped, as earned royalties, all advance minimum royalty payments made in accordance with these lease terms except for $600,000.

On October 23, 2005, we exercised our option to lease and/or sublease certain reserves from SGP Land that are associated with Hopkins County Coal’s Elk Creek mine. Upon exercise of the option agreement, Hopkins County Coal entered into a Coal Lease and Sublease Agreement as well as a Royalty Agreement (collectively the Coal Lease Agreements). The terms of the Coal Lease Agreements are through December 2015, with the right to extend the term for successive one-year periods for as long as we are mining within the coal field, as such term is defined in the Coal Lease Agreements.

The Coal Lease Agreements provide for five annual minimum royalty payments of $684,000. The combined annual minimum royalty payments, consistent with the option agreement, and cumulative option fees of $3.4 million previously paid by Hopkins County Coal are fully recoupable against future tonnage royalty payments. Under the terms of the Coal Lease Agreements, Hopkins County Coal will also reimburse SGP Land for SGP Land’s base lease obligations. Under

 

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the terms of the option to lease and/or lease and sublease agreements, Hopkins County Coal paid advance minimum royalties and/or option fees of $684,000 and $1,368,000 during the years ended December 31, 2005 and 2004, respectively. The 2003 option fee of $684,000 was paid in January 2004 and is included in the due to affiliates balance sheet as of December 31, 2003. As of December 31, 2005, Hopkins County Coal has available $4,059,000 of advance minimum royalty payments made under the Coal Lease Agreements that management expects will be recouped against future production.

Special General Partner

Effective January 2001, Gibson entered into a noncancelable operating lease arrangement with our special general partner for its coal preparation plant and ancillary facilities. Based on the terms of the lease, Gibson has paid and will continue to make monthly payments of approximately $216,000 through January 2011. Lease expense incurred for each of the three years in the period ended December 31, 2005 was $2,595,000.

We have previously entered into and have maintained agreements with two banks to provide letters of credit in an aggregate amount of $25.0 million. At December 31, 2005, we had $24.8 million in outstanding letters of credit. Our special general partner guarantees these letters of credit. Historically, we have compensated our special general partner a guarantee fee equal to 0.30% per annum of the face amount of the letters of credit outstanding. Our special general partner agreed to waive the guarantee fee in exchange for a parent guarantee from our intermediate partnership and Alliance Coal, LLC on the mineral lease and sublease with Webster County Coal and Warrior Coal. Since the guarantee is made on behalf of entities within the consolidated partnership, the guarantee has no fair value under Financial Accounting Standards Board (FASB) Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantees of Indebtedness of Others, and does not impact the consolidated financial statements. We paid approximately $31,300 in guarantee fees to our special general partner for the year ended December 31, 2003.

Accruals of Other Liabilities

We had accruals for other liabilities, including current obligations, totaling $115.5 million and $101.1 million at December 31, 2005 and 2004. These accruals were chiefly comprised of workers’ compensation benefits, black lung benefits, and costs associated with reclamation and mine closings. These obligations are self-insured. The accruals of these items were based on estimates of future expenditures based on current legislation, related regulations and other developments. Thus, from time to time, our results of operations may be significantly affected by changes to these liabilities. Please see “Item 8. Financial Statements and Supplementary Data.—Note 15. Reclamation and Mine Closing Costs and Note 16. Pneumoconiosis (“Black Lung”) Benefits.”

Pension Plan

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

Our pension expense was approximately $3,006,000 and $2,751,000 for the years ended December 31, 2005 and 2004, respectively. The pension expense is based upon a number of actuarial assumptions, including an expected long-term rate of returns on our Pension Plan assets of 8.0% and 8.0% and discount rates of 5.75% and 6.25% for the years ended December 31, 2005 and 2004, respectively. Our actual return on plan assets was 7.2% and 11.9% for the years ended December 31, 2005 and 2004, respectively. Additionally, we base our determination of pension expense on an unsmoothed market-related valuation of assets equal to the fair value of assets, which immediately recognizes all investment gains or losses.

In developing our expected long-term rate of return assumption, we evaluated input from our investment manager, including their review of asset class return expectations by economists, and our actuary. At January 1, 2006, our expected long-term return assumption is at least 8%. Our advisors base the projected returns on broad equity and bond indices. Our expected long-term rate of return on Pension Plan assets is based on an asset allocation assumption of 80.0% with equity managers, with an expected long-term rate of return of 10.4%, and 20.0% with fixed income managers, with an expected long-term rate of return of 5.3%. The pension plan trustee regularly reviews our actual asset allocation in accordance with our investment guidelines and periodically rebalances our investments to our targeted allocation when considered appropriate. The investment committee annually reviews our asset allocation with the compensation committee of our managing general partner.

 

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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 Aa-rated utility bond index as the primary benchmark for establishing the discount rate. The duration of the bonds that comprise this index is comparable to the duration of the benefit obligation in the Pension Plan. The discount rate determined on this basis decreased from 5.75% at December 31, 2004 to 5.6% at December 31, 2005.

We estimate that our Pension Plan expense and cash contributions will be approximately $3,350,000 and $7,900,000, respectively, in 2006. 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 8.0% to 7.0%) at December 31, 2004 would have increased our pension expense for the year ended December 31, 2005 by approximately $240,000. Lowering the discount rate assumption by 0.5% (from 5.75% to 5.25%) at December 31, 2004 would have increased our pension expense for the year ended December 31, 2005 by approximately $482,000.

Inflation

In 2005 an increase in the cost of steel, power and fuel has increased, directly and indirectly, our materials, supplies and maintenance costs. Other elements of inflation in the U.S. have been relatively low in recent years and did not have a material impact on our results of operations for the three years in the period ended December 31, 2005.

New Accounting Standards

In November 2004, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 151, Inventory Costs. SFAS No. 151 is an amendment of Accounting Research Bulletin (ARB) No. 43, chapter 4, paragraph 5 that deals with inventory pricing. SFAS No. 151 clarifies the accounting for abnormal amounts of idle facility expenses, freight, handling costs, and spoilage. Under previous guidance, paragraph 5 of ARB No. 43, chapter 4, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs might be considered to be so abnormal, under certain circumstances, as to require treatment as current period charges. This Statement eliminates the criterion of “so abnormal” and requires that those items be recognized as current period charges. Also, SFAS No. 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 is effective on January 1, 2006. We believe that its adoption will not have any significant impact on our financial position, results of operations or cash flows.

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS No. 123R is a revision of SFAS No. 123, Accounting for Stock Based Compensation, and supersedes Accounting Principles Board Opinion (“APB 25”). Among other items, SFAS No. 123R eliminates the use of APB 25 and the intrinsic value method of accounting, and requires companies to recognize in their financial statements the cost of employee services received in exchange for awards of equity instruments, based on the fair value of those awards on grant date.

In April 2005, the Securities and Exchange Commission issued a rule that amended the implementation date for our adoption of SFAS No. 123R from the third quarter of 2005 to the first quarter of 2006. SFAS No. 123R permits companies to adopt its requirements using either a “modified prospective” method, or a “modified retrospective” method. Under the “modified prospective” method, compensation cost is recognized in the financial statements beginning with the effective date, based on the requirements of SFAS No. 123R, of all share-based payments granted after that date, and based on the requirements of SFAS No. 123 for all unvested awards granted prior to the effective date of SFAS No. 123R. Under the “modified retrospective” method, the requirements are the same as under the “modified prospective” method, but also permits entities to restate financial statements of previous periods based on pro forma disclosures made in accordance with SFAS No. 123. We adopted SFAS No. 123R on January 1, 2006. We used the modified prospective method of adoption provided under SFAS No. 123R, and therefore, will not restate prior period results. Because we have previously expensed share-based payments using the current market value of our common units at the end of each period, the adoption of SFAS No. 123R will not have a material impact on our consolidated results of operations. The intrinsic value previously recognized at December 31, 2005 essentially equals the fair value at January 1, 2006 and therefore, no incremental compensation cost will be recognized upon adoption of SFAS 123R. As required by SFAS No. 123R, the fair value will be reduced for expected forfeitures, to the extent compensation cost has been previously recognized and this amount will be recognized as a cumulative effect of accounting change. Because the

 

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share-based compensation will be settled by delivery of common units, except for the minimum statutory withholding requirements, the previously recognized liability reflected in the due to affiliates current and long-term accounts in the consolidated balance sheet will be reclassed to Partners’ Capital upon adoption of SFAS 123R.

As permitted by SFAS No. 123, prior to January 1, 2006, we accounted for share-based payments to employees using the APB No. 25 intrinsic method and related FASB Interpretation No. 28 based upon the current market value of our common units at the end of each period. We have recorded compensation expense of $8,193,000, $20,320,000 and $7,687,000 for each of the three years ended December 31, 2005, respectively.

In March 2005, the FASB issued Emerging Issues Task Force (EITF) No. 04-6, Accounting for Stripping Costs in the Mining Industry and concluded that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. EITF No. 04-6 does not address the accounting for stripping costs incurred during the pre-production phase of a mine. EITF No. 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005 with early adoption permitted. The effect of initially applying this consensus would be accounted for in a manner similar to a cumulative-effect adjustment. Since we have historically adhered to the accounting principles similar to EITF No. 04-6 in accounting for stripping costs incurred at our surface operation, the adoption of EITF No. 04-6, on January 1, 2006, did not have a material impact on our consolidated financial statements.

In April 2005, the FASB adopted Financial Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). FIN 47 clarifies that the term “conditional asset obligation” from SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity on which the timing or method of settlement is conditional on a future event and requires the recognition of such conditional obligations even though uncertainty exists. Our adoption of FIN 47 at December 31, 2005 did not affect on our consolidated financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We have significant long-term coal supply agreements. Virtually all of the long-term coal supply agreements are subject to price adjustment provisions, which permit an increase or decrease periodically in the contract price to principally reflect changes in specified price indices or items such as taxes, royalties or actual production costs. For additional discussion of coal supply agreements, please see “Item 1. Business. – Coal Marketing and Sales” and “Item 8. Financial Statements and Supplementary Data. – Note 19. Concentration of Credit Risk and Major Customers.”

Almost all of our transactions are, denominated in U.S. dollars, and as a result, we do not have material exposure to currency exchange-rate risks. At the current time, we do not have any interest rate, foreign currency exchange rate or commodity price-hedging transactions outstanding.

Borrowings under our Credit Facility are at variable rates and, as a result, we have interest rate exposure. Our earnings are not materially affected by changes in interest rates. We had no borrowings outstanding under the Credit Facility during 2005 or at December 31, 2005.

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, 2005, and 2004. The carrying amounts and fair values of financial instruments are as follows (in thousands):

 

Expected Maturity Dates

as of December 31, 2005

   2006     2007     2008     2009     2010     Thereafter     Total   

Fair Value

December 31,

2005

Senior Notes fixed rate

   $ 18,000     $ 18,000     $ 18,000     $ 18,000     $ 18,000     $ 72,000     $ 162,000    $ 176,254

Weighted Average interest rate

     8.31 %     8.31 %     8.31 %     8.31 %     8.31 %     8.31 %     

Expected Maturity Dates

as of December 31, 2004

   2005     2006     2007     2008     2009     Thereafter     Total   

Fair Value

December 31,

2004

Senior Notes fixed rate

   $ 18,000     $ 18,000     $ 18,000     $ 18,000     $ 18,000     $ 90,000     $ 180,000    $ 197,278

Weighted Average interest rate

     8.31 %     8.31 %     8.31 %     8.31 %     8.31 %     8.31 %     

 

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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, 2005 and 2004, and the related consolidated statements of income, cash flows and Partners’ capital (deficit) and comprehensive income for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these 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 the Partnership as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, 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, presents 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 effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2005, 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 March 16, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Partnership’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Tulsa, Oklahoma

March 16, 2006

 

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2005 AND 2004

(In thousands, except unit data)

 

     December 31,  
     2005     2004  
ASSETS     

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 32,054     $ 31,177  

Trade receivables, net

     94,495       56,967  

Other receivables

     2,330       1,637  

Marketable securities

     49,242       49,397  

Inventories

     17,270       13,839  

Advance royalties

     2,952       3,117  

Prepaid expenses and other assets

     8,934       4,345  
                

Total current assets

     207,277       160,479  

PROPERTY, PLANT AND EQUIPMENT:

    

Property, plant and equipment, at cost

     635,086       526,468  

Less accumulated depreciation, depletion and amortization

     (330,672 )     (292,900 )
                

Total property, plant and equipment

     304,414       233,568  

OTHER ASSETS:

    

Advance royalties

     16,328       11,737  

Coal supply agreements, net

     —         2,723  

Other long-term assets

     4,668       4,277  
                

Total other assets

     20,996       18,737  
                

TOTAL ASSETS

   $ 532,687     $ 412,784  
                
LIABILITIES AND PARTNERS’ CAPITAL     

CURRENT LIABILITIES:

    

Accounts payable

   $ 53,473     $ 30,961  

Due to affiliates

     8,795       10,338  

Accrued taxes other than income taxes

     13,177       10,742  

Accrued payroll and related expenses

     12,466       11,730  

Accrued pension benefit

     7,588       5,798  

Accrued interest

     4,855       5,402  

Workers’ compensation and pneumoconiosis benefits

     7,740       7,081  

Other current liabilities

     5,120       6,253  

Current maturities, long-term debt

     18,000       18,000  
                

Total current liabilities

     131,214       106,305  

LONG-TERM LIABILITIES:

    

Long-term debt, excluding current maturities

     144,000       162,000  

Pheumoconiosis benefits

     23,293       19,833  

Workers’ compensation

     30,050       25,994  

Reclamation and mine closing

     38,716       32,838  

Due to affiliates

     6,940       7,457  

Other liabilities

     2,697       3,170  
                

Total long-term liabilities

     245,696       251,292  
                

Total liabilities

     376,910       357,597  
                
COMMITMENTS AND CONTINGENCIES     

PARTNERS’ CAPITAL:

    

Limited Partners - Common Unitholders 36,426,306 and 36,260,880 units outstanding, respectively

     461,068       363,658  

General Partners’ deficit

     (298,270 )     (303,295 )

Unrealized loss on marketable securities

     (68 )     (54 )

Minimum pension liability

     (6,953 )     (5,122 )
                

Total Partners’ capital

     155,777       55,187  
                

TOTAL LIABILITIES AND PARTNERS’ CAPITAL

   $ 532,687     $ 412,784  
                

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, 2005, 2004 AND 2003

(In thousands, except unit and per unit data)

 

     Year Ended December 31,  
     2005    2004     2003  

SALES AND OPERATING REVENUES:

       

Coal sales

   $ 768,958    $ 599,399     $ 501,596  

Transportation revenues

     39,069      29,817       19,553  

Other sales and operating revenues

     30,691      24,073       21,598  
                       

Total revenues

     838,718      653,289       542,747  
                       

EXPENSES:

       

Operating expenses

     521,488      436,471       368,835  

Transportation expenses

     39,069      29,817       19,553  

Outside purchases

     15,113      9,913       8,508  

General and administrative

     33,484      45,400       28,270  

Depreciation, depletion and amortization

     55,637      53,664       52,495  

Interest expense (net of interest income and interest

capitalized of $3,367, $852 and $545, respectively)

     11,816      14,963       15,981  

Net gain from insurance settlement

     —        (15,217 )     —    
                       

Total operating expenses

     676,607      575,011       493,642  
                       

INCOME FROM OPERATIONS

     162,111      78,278       49,105  

OTHER INCOME

     581      984       1,374  
                       

INCOME BEFORE INCOME TAXES

     162,692      79,262       50,479  

INCOME TAX EXPENSE

     2,682      2,641       2,577  
                       

NET INCOME

   $ 160,010    $ 76,621     $ 47,902  
                       

ALLOCATION OF NET INCOME:

       

PORTION APPLICABLE TO WARRIOR COAL LOSS PRIOR TO ITS ACQUISITION ON FEBRUARY 14, 2003

   $ —      $ —       $ (666 )

PORTION APPLICABLE TO PARTNERS’ INTEREST

     160,010      76,621       48,568  
                       

NET INCOME

   $ 160,010    $ 76,621     $ 47,902  
                       

GENERAL PARTNERS’ INTEREST IN NET INCOME

   $ 12,409    $ 3,324     $ 306  
                       

LIMITED PARTNERS’ INTEREST IN NET INCOME

   $ 147,601    $ 73,297     $ 47,596  
                       

BASIC NET INCOME PER LIMITED PARTNER UNIT

   $ 2.89    $ 1.76     $ 1.30  
                       

DILUTED NET INCOME PER LIMITED PARTNER UNIT

   $ 2.84    $ 1.71     $ 1.26  
                       

DISTRIBUTIONS PAID PER COMMON AND SUBORDINATED UNIT

   $ 1.58    $ 1.24     $ 1.05  
                       

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC

     36,288,527      35,881,896       35,161,468  
                       

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING – DILUTED

     36,977,061      36,874,336       36,325,678  
                       

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, 2005, 2004 AND 2003

(In thousands)

 

     Year Ended December 31,  
     2005     2004     2003  

CASH FLOWS FROM OPERATING ACTIVITIES:

      

Net income

   $ 160,010     $ 76,621     $ 47,902  

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

      

Depreciation, depletion and amortization

     55,637       53,664       52,495  

Reclamation and mine closings

     1,918       1,622       1,341  

Coal inventory adjustment to market

     573       488       687  

Loss on retirement of damaged vertical belt equipment

     1,298       —         —    

Other

     759       255       (353 )

Changes in operating assets and liabilities:

      

Trade receivables

     (37,528 )     (20,593 )     (3,459 )

Other receivables

     (693 )     294       (1,828 )

Inventories

     (4,004 )     200       (2,049 )

Prepaid expenses and other assets

     (4,584 )     (913 )     (648 )

Advance royalties

     (4,396 )     (1,307 )     2,227  

Accounts payable

     13,115       8,678       (679 )

Due to affiliates

     4,928       14,194       9,978  

Accrued taxes other than income taxes

     2,435       367       2,270  

Accrued payroll and related benefits

     736       635       1,091  

Pneumoconiosis benefits

     3,460       2,702       1,064  

Workers’ compensation

     4,715       3,849       4,002  

Other

     (4,761 )     4,299       (3,729 )
                        

Total net adjustments

     33,608       68,434       62,410  
                        

Net cash provided by operating activities

     193,618       145,055       110,312  
                        

CASH FLOWS FROM INVESTING ACTIVITIES:

      

Purchase of property, plant and equipment

     (110,517 )     (54,713 )     (43,004 )

Purchase of Warrior Coal

     —         —         (12,661 )

Proceeds from sale of property, plant and equipment

     198       687       913  

Purchase of marketable securities

     (63,448 )     (49,271 )     (23,091 )

Proceeds from marketable securities

     63,589       23,537       —    

Proceeds from assumption of liability

     —         2,112       —    
                        

Net cash used in investing activities

     (110,178 )     (77,648 )     (77,843 )
                        

CASH FLOWS FROM FINANCING ACTIVITIES:

      

Proceeds from common unit offering to public

     —         —         53,927  

Cash contribution by General Partners

     143       3       9  

Payments on Warrior Coal revolving credit balance

     —         —         (17,000 )

Borrowings under revolving credit and working capital facilities

     —         —         31,600  

Payments under revolving credit and working capital facilities

     —         —         (31,600 )

Payments on long-term debt

     (18,000 )     —         (31,250 )

Distributions to Partners

     (64,706 )     (46,389 )     (37,027 )
                        

Net cash used in financing activities

     (82,563 )     (46,386 )     (31,341 )
                        

NET CHANGE IN CASH AND CASH EQUIVALENTS

     877       21,021       1,128  

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

     31,177       10,156       9,028  
                        

CASH AND CASH EQUIVALENTS AT END OF PERIOD

   $ 32,054     $ 31,177     $ 10,156  
                        

SUPPLEMENTAL CASH FLOW INFORMATION:

      

CASH PAID FOR:

      

Cash paid for interest

   $ 15,160     $ 15,229     $ 15,960  
                        

Cash paid for taxing authorities

   $ 3,025     $ 2,150     $ 2,681  
                        

NON-CASH ACTIVITY:

      

Purchase of property, plant and equipment

   $ 9,364     $ —       $ —    
                        

Market value of common units issued to Long-Term Incentive Plan participants upon vesting

   $ 6,988     $ 13,680     $ —