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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
     
(Mark One)    
þ
  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
 
o
  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. 1-32423
ALPHA NATURAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
     
Delaware   02-0733940
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification Number)
One Alpha Place, P.O. Box 2345, Abingdon, Virginia   24212
(Address of principal executive offices)   (Zip Code)
Registrant’s telephone number, including area code:
(276) 619-4410
Securities registered pursuant to Section 12(b) of the Act:
     
Title of Each Class   Name of Each Exchange on Which Registered
     
Common stock, $0.01 par value
  New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
      Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes þ          No o
      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 o          No þ
      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, and (2) has been subject to such filing requirements for the past 90 days.     Yes þ          No o
      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.     Yes o          No þ
      Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Exchange Act Rule 12b-2).
o Large accelerated filer          o Accelerated filer          þ  Non-accelerated filer
      Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).     Yes o          No þ
      The aggregate market value of the Common Stock held by non-affiliates of the registrant on June 30, 2005, was approximately $785,629,529 based on the last sales price reported that date on the New York Stock Exchange of $23.88 per share. In determining this figure, the registrant has assumed that all of its directors and executive officers are affiliates. Such assumptions should not be deemed to be conclusive for any other purpose.
      Common Stock, $0.01 par value, outstanding as of February 1, 2006 — 64,422,510 shares.
DOCUMENTS INCORPORATED BY REFERENCE
      Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2006 annual meeting of stockholders, which proxy statement will be filed no later than 120 days after the close of the registrant’s fiscal year ended December 31, 2005.
 
 


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CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS
      This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements, which involve risks and uncertainties, relate to analyses and other information that are based on forecasts of future results and estimates of amounts not yet determinable and may also relate to our future prospects, developments and business strategies. We have used the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project” and similar terms and phrases, including references to assumptions, in this report to identify forward-looking statements. These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those matters expressed in or implied by these forward-looking statements.
      The following factors are among those that may cause actual results to differ materially from our forward-looking statements:
  •  market demand for coal, electricity and steel;
 
  •  future economic or capital market conditions;
 
  •  weather conditions or catastrophic weather-related damage;
 
  •  our production capabilities;
 
  •  the consummation of financing, acquisition or disposition transactions and the effect thereof on our business;
 
  •  our ability to successfully integrate the operations we acquired in the Nicewonder Acquisition with our existing operations, and to successfully operate NCI’s highway construction business;
 
  •  our plans and objectives for future operations and expansion or consolidation;
 
  •  our relationships with, and other conditions affecting, our customers;
 
  •  timing of changes in customer coal inventories;
 
  •  long-term coal supply arrangements;
 
  •  inherent risks of coal mining beyond our control;
 
  •  environmental laws, including those directly affecting our coal mining and production, and those affecting our customers’ coal usage;
 
  •  competition in coal markets;
 
  •  railroad, barge, truck and other transportation performance and costs;
 
  •  availability of mining and processing equipment and parts;
 
  •  our assumptions concerning economically recoverable coal reserve estimates;
 
  •  employee workforce factors;
 
  •  regulatory and court decisions;
 
  •  future legislation and changes in regulations, governmental policies or taxes;
 
  •  changes in postretirement benefit obligations;
 
  •  our liquidity, results of operations and financial condition; and
 
  •  other factors, including the other factors discussed in Item 1A, “Risk Factors” of this report.
      When considering these forward-looking statements, you should keep in mind the cautionary statements in this report and the documents incorporated by reference. We do not undertake any responsibility to release publicly any revisions to these forward-looking statements to take into account events or circumstances that occur after the date of this report. Additionally, we do not undertake any responsibility to update you on the occurrence of any unanticipated events which may cause actual results to differ from those expressed or implied by the forward-looking statements contained in this report.


 

2005 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
             
        Page
         
 PART I
   Business     2  
   Risk Factors     19  
   Properties     37  
   Legal Proceedings     41  
   Submission of Matters to a Vote of Security Holders     41  
 PART II
   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     41  
   Selected Financial Data     42  
   Management’s Discussion and Analysis of Financial Condition and Results of Operation     47  
   Quantitative and Qualitative Disclosures about Market Risk     64  
   Financial Statements and Supplementary Data     65  
   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     112  
   Controls and Procedures     112  
   Other Information     112  
 PART III
   Directors and Executive Officers of the Registrant     115  
   Executive Compensation     115  
   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     115  
   Certain Relationships and Related Transactions     115  
   Principal Accounting Fees and Services     115  
 PART IV
   Exhibits, Financial Statement Schedules     116  
 EX-10.3: THIRD AMENDED AND RESTATED EMPLOYMENT AGREEMENT
 EX-10.5: EMPLOYMENT AGREEMENT
 EX-10.17: TWO PARTIAL SURRENDER AGREEMENTS
 EX-10.18: PARTIAL SURRENDER AGREEMENT
 EX-10.24: PLAN DOCUMENT
 EX-23: CONSENT OF KPMG LLP
 EX-31.A: CERTIFICATION
 EX-31.B: CERTIFICATION
 EX-32.A: CERTIFICATION
 EX-32.B: CERTIFICATION

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PART I
Item 1. Business
Overview
      We are a leading Appalachian coal producer. Our reserves primarily consist of high Btu, low sulfur steam coal that is currently in high demand in U.S. coal markets and metallurgical coal that is currently in high demand in both U.S. and international coal markets. We produce, process and sell steam and metallurgical coal from eight regional business units, which, as of February 1, 2006, are supported by 44 active underground mines, 25 active surface mines and 11 preparation plants located throughout Virginia, West Virginia, Kentucky, and Pennsylvania, as well as a highway construction business in West Virginia that produces coal. We are also actively involved in the purchase and resale of coal mined by others, the majority of which we blend with coal produced from our mines, allowing us to realize a higher overall margin for the blended product than we would be able to achieve selling these coals separately.
      Steam coal, which is primarily purchased by large utilities and industrial customers as fuel for electricity generation, accounted for approximately 63% of our 2005 coal sales volume. The majority of our steam coal sales volume in 2005 consisted of high Btu (above 12,500 Btu content per pound), low sulfur (sulfur content of 1.5% or less) coal, which typically sells at a premium to lower-Btu, higher-sulfur steam coal. Metallurgical coal, which is used primarily to make coke, a key component in the steel making process, accounted for approximately 37% of our 2005 coal sales volume. Metallurgical coal generally sells at a premium over steam coal because of its higher quality and its value in the steelmaking process as the raw material for coke. Under current market conditions, we are able to market a significant portion of our higher quality steam coal as metallurgical coal.
      During 2005, we sold a total of 26.7 million tons of steam and metallurgical coal and generated revenues of $1,627.3 million, EBITDA, as adjusted, of $145.2 million and net income of $21.2 million. We define and reconcile EBITDA, as adjusted, and explain its importance, in note (3) under “Selected Financial Data.” Our coal sales during 2005 consisted of 20.6 million tons of produced and processed coal, including 1.5 million tons purchased from third parties and processed at our processing plants or loading facilities prior to resale, and 6.1 million tons of purchased coal that we resold without processing. Approximately 67% of the purchased coal in 2005 was blended with coal produced from our mines prior to resale. Approximately 45% of our sales revenue in 2005 was derived from sales made outside the United States, primarily in Canada, Japan, Brazil, Korea and several countries in Europe.
      As of December 31, 2005, we owned or leased 489.5 million tons of proven and probable coal reserves. Of our total proven and probable reserves, approximately 89% are low sulfur reserves, with approximately 63% having sulfur content below 1.0%. Approximately 92% of our total proven and probable reserves have a high Btu content. We believe that our total proven and probable reserves will support current production levels for more than 20 years.
      As discussed in Note 23 to our financial statements, we have one reportable segment — Coal Operations — which consists of our coal extracting, processing and marketing operations, as well as our purchased coal sales function and certain other coal-related activities, including our recovery of coal incidental to our highway construction operations. Our equipment and part sales and equipment repairs operations, terminal services, coal analysis services, leasing of mineral rights, and the non-coal recovery portion of our highway construction operations described below under “— Other Operations” are not included in our Coal Operations segment.
History
      In 2002, ANR Holdings, LLC (“ANR Holdings”) was formed by First Reserve Fund IX, L.P. and ANR Fund IX Holdings, L.P. (referred to as the “First Reserve Stockholders” or collectively with their affiliates, “First Reserve”) and our management to serve as the top-tier holding company of the Alpha Natural Resources organization. On February 11, 2005, Alpha Natural Resources, Inc. succeeded to the

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business of ANR Holdings in a series of internal restructuring transactions which we refer to collectively as the “Internal Restructuring,” and on February 18, 2005 Alpha Natural Resources, Inc. completed an initial public offering of its common stock. When we use the terms “Alpha,” “we,” “our,” “the Company” and similar terms in this report, we mean (1) prior to our Internal Restructuring, ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. (a subsidiary of First Reserve Fund IX, L.P. prior to our Internal Restructuring) and subsidiaries on a combined basis and (2) after our Internal Restructuring, Alpha Natural Resources, Inc. and its consolidated subsidiaries. Alpha Natural Resources, Inc. was formed under the laws of the State of Delaware on November 29, 2004.
      On December 13, 2002, the First Reserve Stockholders, who then owned 100% of the membership interests of ANR Holdings, acquired the majority of the Virginia coal operations of Pittston Coal Company (our “Predecessor”), a subsidiary of the Brink’s Company (formerly known as The Pittston Company), through wholly owned subsidiaries of ANR Holdings for $62.9 million.
      On January 31, 2003, wholly owned subsidiaries of ANR Holdings acquired Coastal Coal Company, LLC for $67.8 million, and on March 11, 2003, ANR Holdings and its subsidiaries acquired the U.S. coal production and marketing operations of American Metals and Coal International, Inc. (“AMCI”) for $121.3 million. Of the consideration for the U.S. AMCI acquisition, $69.0 million was provided in the form of an approximate 44% membership interest in ANR Holdings issued to the owners of AMCI, which together with the issuances of an approximate 1% membership interest to Madison Capital Funding, LLC and Alpha Coal Management reduced the First Reserve Stockholders membership interest in ANR Holdings to approximately 55%.
      On November 17, 2003, we acquired the assets of Mears Enterprises, Inc. (“Mears”) for $38.0 million.
      On April 1, 2004, we acquired substantially all of the assets of Moravian Run Reclamation Co., Inc. for five thousand dollars in cash and the assumption by us of certain liabilities, including four active surface mines and two additional surface mines under development, operating in close proximity to and serving many of the same customers as our AMFIRE business unit located in Pennsylvania.
      On May 10, 2004, we acquired a coal preparation plant and railroad loading facility located in Portage, Pennsylvania and related equipment and coal inventory from Cooney Bros. Coal Company for $2.5 million in cash and an adjacent coal refuse disposal site from a Cooney family trust for $0.3 million in cash.
      On October 13, 2004, our AMFIRE business unit entered into a coal mining lease with Pristine Resources, Inc., a subsidiary of International Steel Group Inc., for the right to deep mine a substantial area of the Upper Freeport Seam in Pennsylvania.
      On February 11, 2005, we succeeded to the business and became the indirect parent entity of ANR Holdings in connection with the Internal Restructuring and, on February 18, 2005, we completed an initial public offering of our common stock (the “IPO”).
      On April 14, 2005, we sold the assets of our Colorado mining subsidiary, National King Coal LLC, and related trucking subsidiary, Gallup Transportation and Transloading Company, LLC (collectively, “NKC”) to an unrelated third party for cash in the amount of $4.4 million, plus an amount in cash equal to the fair market value of NKC’s coal inventory, and the assumption by the buyer of certain liabilities of NKC.
      On October 26, 2005, we acquired the Nicewonder Coal Group’s coal reserves and operations in southern West Virginia and southwestern Virginia. The Nicewonder Acquisition consisted of the purchase of the outstanding capital stock of White Flame Energy, Inc., Twin Star Mining, Inc. and Nicewonder Contracting, Inc., the equity interests of Powers Shop, LLC and Buchanan Energy, LLC and substantially all of the assets of Mate Creek Energy of W. Va., Inc. and Virginia Energy Company, and the business of Premium Energy, Inc. by merger. We paid an aggregate purchase price of $328.2 million in the Nicewonder Acquisition, consisting of cash at closing in the amount of $35.2 million, a cash payment of $1.9 million to be made to the sellers in April 2006, transaction costs of $4.7 million, $221.0 million principal amount of promissory installment notes of one of our indirect, wholly owned subsidiaries (of which $181.1 million was paid on November 2, 2005 and $39.9 million was paid on January 13, 2006), a final payment for working capital in the

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amount of $12.3 million paid on February 6, 2006, and 2,180,233 shares of our common stock valued at approximately $53.2 million for accounting purposes. For this purpose, the value of the common stock issued was based on the average closing prices of our common stock for the five trading days surrounding October 20, 2005, the date the number of shares to be issued under the terms of the acquisition agreement became fixed without subsequent revision. In connection with the Nicewonder Acquisition, we also agreed to make royalty payments to the former owners of the acquired companies in the amount of $0.10 per ton of coal mined and sold from White Flame Energy’s Surface Mine No. 10. The operations we acquired from the Nicewonder Coal Group constitute our new eighth business unit, Callaway Natural Resources.
Mining Methods
      We produce coal using two mining methods: underground room and pillar mining using continuous mining equipment, and surface mining, which are explained as follows:
      Underground Mining. Underground mines in the United States are typically operated using one of two different methods: room and pillar mining or longwall mining. In 2005, approximately 76% of our coal production volume from mines operated by our subsidiaries’ employees came from underground mining operations using the room and pillar method with continuous mining equipment. In room and pillar mining, rooms are cut into the coal bed leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of air. Continuous mining equipment is used to cut the coal from the mining face. Generally, openings are driven 20 feet wide and the pillars are generally rectangular in shape measuring 35-50 feet wide by 35-80 feet long. As mining advances, a grid-like pattern of entries and pillars is formed. Shuttle cars are used to transport coal to the conveyor belt for transport to the surface. When mining advances to the end of a panel, retreat mining may begin. In retreat mining, as much coal as is feasible is mined from the pillars that were created in advancing the panel, allowing the roof to cave. When retreat mining is completed to the mouth of the panel, the mined panel is abandoned. The room and pillar method is often used to mine smaller coal blocks or thin or non-contiguous seams, and seam recovery ranges from 35% to 70%, with higher seam recovery rates applicable where retreat mining is combined with room and pillar mining. Productivity for continuous room and pillar mining in the United States averages 3.5 tons per employee per hour, according to the U.S. Energy Information Administration (“EIA”).
      The other underground mining method commonly used in the United States is the longwall mining method, which we do not currently use at any of our mines. In longwall mining, a rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the roof of the mine while it advances through the coal. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface. Our Central Appalachian reserves often include non-contiguous seams of coal that can be extracted at a lower cost using continuous mining as opposed to the more capital intensive longwall method.
      Surface Mining. Surface mining is used when coal is found close to the surface. In 2005, approximately 24% of our coal production volume from mines operated by our subsidiaries’ employees came from surface mines. This method involves the removal of overburden (earth and rock covering the coal) with heavy earthmoving equipment and explosives, loading out the coal, replacing the overburden and topsoil after the coal has been excavated and reestablishing vegetation and plant life and making other improvements that have local community and environmental benefit. Overburden is typically removed at our mines using large, rubber-tired diesel loaders. Seam recovery for surface mining is typically 90% or more. Productivity depends on equipment, geological composition and mining ratios and averages 4.8 tons per employee per hour in eastern regions of the United States, according to the EIA.
Coal Characteristics
      In general, coal of all geological compositions is characterized by end use as either steam coal or metallurgical coal. Heat value, sulfur and ash content, and volatility in the case of metallurgical coal, are the most important variables in the profitable marketing and transportation of coal. These characteristics determine the best end use of a particular type of coal. We mine, process, market and transport bituminous coal, characteristics of which are described below.

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      Heat Value. The heat value of coal is commonly measured in British thermal units, or “Btus.” A Btu is the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. All of our coal is bituminous coal, a “soft” black coal with a heat content that ranges from 9,500 to 15,000 Btus per pound. This coal is located primarily in Appalachia, Arizona, the Midwest, Colorado and Utah and is the type most commonly used for electric power generation in the United States. Bituminous coal is also used for metallurgical and industrial steam purposes. Of our estimated 489.5 million tons of proven and probable reserves, approximately 92% has a heat content above 12,500 Btus per pound.
      Sulfur Content. Sulfur content can vary from seam to seam and sometimes within each seam. When coal is burned, it produces sulfur dioxide, the amount of which varies depending on the chemical composition and the concentration of sulfur in the coal. Low sulfur coals are coals which have a sulfur content of 1.5% or less. Demand for low sulfur coal has increased, and is expected to continue to increase, as generators of electricity strive to reduce sulfur dioxide emissions to comply with increasingly stringent emission standards in environmental laws and regulations. Approximately 89% of our proven and probable reserves are low sulfur coal.
      High sulfur coal can be burned in plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by 50% to 90%. Plants without scrubbers can burn high sulfur coal by blending it with lower sulfur coal or by purchasing emission allowances on the open market, allowing the user to emit a predetermined amount of sulfur dioxide. Some older coal-fired plants have been retrofitted with scrubbers, although most have shifted to lower sulfur coals as their principal strategy for complying with Phase II of the Clean Air Act’s Acid Rain regulations. We expect that any new coal-fired generation plant built in the United States will use clean coal-burning technology.
      Ash & Moisture Content. Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from seam to seam. Ash content is an important characteristic of coal because electric generating plants must handle and dispose of ash following combustion. The absence of ash is also important to the process by which metallurgical coal is transformed into coke for use in steel production. Moisture content of coal varies by the type of coal, the region where it is mined and the location of coal within a seam. In general, high moisture content decreases the heat value and increases the weight of the coal, thereby making it more expensive to transport. Moisture content in coal, as sold, can range from approximately 5% to 30% of the coal’s weight.
      Coking Characteristics. The coking characteristics of metallurgical coal are typically measured by the coal’s fluidity, ARNU and volatility. Fluidity and ARNU tests measure the expansion and contraction of coal when it is heated under laboratory conditions to determine the strength of coke that could be produced from a given coal. Typically, higher numbers on these tests indicate higher coke strength. Volatility refers to the loss in mass, less moisture, when coal is heated in the absence of air. The volatility of metallurgical coal determines the percentage of feed coal that actually becomes coke, known as coke yield. Coal with a lower volatility produces a higher coke yield and is more highly valued than coal with a higher volatility, all other metallurgical characteristics being equal.
Mining Operations
      We currently have eight regional business units, including two in Virginia, four predominately in West Virginia, one in Pennsylvania, and one in Kentucky. As of February 1, 2006, these business units include 11 preparation plants, each of which receive, blend, process and ship coal that is produced from one or more of our 69 active mines (some of which are operated by third parties under contracts with us), using two mining methods, underground room and pillar and surface mining. Our underground mines generally consist of one or more single or dual continuous miner sections which are made up of the continuous miner, shuttle cars, roof bolters and various ancillary equipment. Our surface mines are a combination of mountain top removal, contour, highwall miner, and auger operations using truck/loader equipment fleets along with large production tractors. Most of our preparation plants are modern heavy media plants that generally have both coarse and fine coal cleaning circuits. We employ preventive maintenance and rebuild programs to ensure that our equipment is modern and well-maintained. During 2005, most of our preparation plants also processed coal

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that we purchased from third party producers before reselling it to our customers. Within each regional business unit, mines have been developed at strategic locations in close proximity to our preparation plants and rail shipping facilities. Coal is transported from our regional business units to customers by means of railroads, trucks, barge lines and ocean-going vessels from terminal facilities. The following table provides location and summary information regarding our eight regional business units and the preparation plants and active mines associated with these business units as of February 1, 2006:
Regional Business Units
                                                 
            Number and Type of        
            Mines as of        
            February 1, 2006       2005
                    Production of
        Preparation plant(s) as of   Under-           Saleable Tons
Regional Business Unit   Location   February 1, 2006   ground   Surface   Total   Railroad   (in 000’s)(1)
                             
Paramont
  Virginia   Toms Creek     9       5       14       NS       5,679  
Dickenson-Russell
  Virginia   McClure River and Moss #3     6       1       7       CSX, NS       2,056  
Kingwood
  West Virginia   Whitetail     1       0       1       CSX       1,546  
Brooks Run
  West Virginia   Erbacon     3       1       4       CSX       2,298  
Welch
  West Virginia   Litwar, Kepler and Herndon     15       0       15       NS       2,542  
AMFIRE
  Pennsylvania   Clymer and Portage     6       12       18       NS       4,291  
Enterprise
  Kentucky   Roxana     4       3       7       CSX       1,525  
Callaway
  West Virginia/ Virginia         0       3       3       NS       665  
                                       
        Total     44       25       69               20,602  
 
(1)  Includes coal purchased from third-party producers that was processed at our subsidiaries’ preparation plants in 2005. Excludes 457,000 tons of coal produced in 2004 by NKC. We sold NKC on April 14, 2005.
CSX Railroad = CSX
Norfolk Southern Railroad = NS
      The coal production and processing capacity of our mines and processing plants is influenced by a number of factors including reserve availability, labor availability, environmental permit timing and preparation plant capacity. We have obtained permits for and are currently in the process of developing Deep Mine 35 in Virginia which is operated by our Paramont business unit, Madison deep mine in Pennsylvania which is operated by our AMFIRE business unit, Seven Pines surface mine in West Virginia which is operated by our Brooks Run business unit and Cucumber deep mine in West Virginia which is operated by our Welch business unit. We spent approximately $54.0 million developing these mines during 2005. All four of these new mines have begun production and we expect them to reach full production capacity of approximately 2.8 million tons by the end of 2006, some of which is intended to replace existing production from contract-operated deep mines in Virginia and West Virginia that are being depleted or decommissioned. We expect the majority of this new production to be metallurgical coal.
      The following provides a brief description of our business units as of February 1, 2006.
      Paramont. Our Paramont business unit produces coal from nine underground mines using continuous miners and the room and pillar mining method. Two of the underground mines are operated by independent contractors. The coal from these underground mines is transported by truck to the Toms Creek preparation plant operated by Paramont, or the McClure River or Moss #3 preparation plants operated by Dickenson-Russell. At the preparation plant, the coal is cleaned, blended and loaded onto rail for shipment to customers. Paramont also operates five truck/loader surface mines. Three of these surface mines are operated by independent contractors. The coal produced by the surface mines is transported to one of our preparation plants or raw coal loading docks where it is blended and loaded onto rail for shipment to customers. During 2005, Paramont purchased approximately 200,000 tons of coal from third parties that was blended with Paramont’s coal and shipped to our customers. As of February 1, 2006, the Paramont business unit was operating at a capacity to ship approximately six million tons per year.

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      Dickenson-Russell. Our Dickenson-Russell business unit produces coal from six underground mines using continuous miners and the room and pillar mining method. Two of the underground mines are operated by independent contractors. The coal from these underground mines is transported by truck to the McClure River or Moss #3 preparation plants operated by Dickenson-Russell or the Toms Creek preparation plant operated by Paramont where it is cleaned, blended and loaded on rail or truck for shipment to customers. The Dickenson-Russell business unit also operates a fine coal recovery dredge operation where fine coals that were previously discarded by the coal cleaning process are recovered, cleaned, and blended with other coals for sale. During 2005, Dickenson-Russell purchased approximately 82,000 tons of coal from third parties that was blended with Dickenson-Russell’s coal and shipped to our customers. As of February 1, 2006, the Dickenson-Russell business unit was operating at a capacity to ship approximately two million tons per year.
      Kingwood. Our Kingwood business unit produces coal from one underground mine using continuous miners and the room and pillar mining method. The Kingwood operation is staffed and operated by Kingwood employees. The coal is belted to the Whitetail preparation plant operated by Kingwood where it is cleaned and loaded onto rail or truck for shipment to customers. The Kingwood business unit has no surface mining operations. During 2005, Kingwood purchased approximately 33,000 tons of coal from third parties that was blended with Kingwood’s coal and shipped to our customers. As of February 1, 2006, the Kingwood business unit was operating at a capacity to ship approximately one and one-half million tons per year.
      Brooks Run. Our Brooks Run business unit produces coal from three underground mines using continuous miners and the room and pillar mining method. All of the mining operations at the Brooks Run business unit are staffed and operated by Brooks Run employees. The coal is transported by truck to the Erbacon preparation plant operated by Brooks Run where it is cleaned, blended and loaded onto rail for shipment to customers. The Brooks Run business unit has one surface mine operated with Brooks Run employees. Brooks Run purchased no coal from third parties in 2005. As of February 1, 2006, the Brooks Run business unit was operating at a capacity to ship approximately two and one-half million tons per year.
      Welch. Our Welch business unit produces coal from fifteen underground mines using continuous miners and the room and pillar mining method. Three of the underground mines are operated by our employees, and the others are operated by independent contractors. The coal is transported by truck or rail to the coal preparation plants operated by Welch where it is cleaned, blended and loaded onto rail for shipment to customers. The Welch business unit has no active surface mining operations as of February 1, 2006. During 2005, the Welch business unit purchased approximately 743,000 tons of coal from third parties that was blended with other coals and shipped to our customers. As of February 1, 2006, the Welch business unit was operating at a capacity to ship approximately three and one-quarter million tons per year.
      AMFIRE. Our AMFIRE business unit produces coal from six underground mines using continuous miners and the room and pillar mining method. All of the underground mining operations at AMFIRE are staffed and operated by AMFIRE employees. The underground coal is delivered directly by truck to the customer, or to the Clymer or Portage coal preparation plants or raw coal loading docks where it is cleaned, blended and loaded onto rail or truck for shipment to customers. AMFIRE also operates twelve truck/loader surface mines, five of which are operated by independent contractors. The surface mined coal is delivered directly by truck to the customer or transported to the Clymer or Portage coal preparation plants or raw coal loading docks where it is blended and loaded onto rail or truck for shipment to customers. During 2005, AMFIRE purchased approximately 345,000 tons of coal from third parties that was blended with AMFIRE’s coal and shipped to our customers. As of February 1, 2006, the AMFIRE business unit was operating at a capacity to ship approximately four million tons per year.
      Enterprise. Our Enterprise business unit produces coal from four underground mines using continuous miners and the room and pillar mining method. All of the underground mining operations at Enterprise are staffed and operated by Enterprise employees. The coal from these underground mines is transported by truck to the Roxana coal preparation plant operated by Enterprise where it is cleaned, blended and loaded onto rail for shipment to customers. Enterprise also has three truck/loader surface mines which are operated by independent contractors. The coal produced by the surface mines is transported to the Roxana preparation plant where it is blended and loaded onto rail for shipment to customers. During 2005, Enterprise purchased

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approximately 69,000 tons of coal from third parties that was blended with Enterprise’s coal and shipped to our customers. As of February 1, 2006, the Enterprise business unit was operating at a capacity to ship approximately one and one-half million tons per year.
      Callaway. The operations we acquired in the Nicewonder Acquisition constitute our new eighth business unit, which we have named Callaway. This new business unit produces coal from three surface mining operations operated by our Callaway employees and also recovers coal from the highway construction business operated by our subsidiary Nicewonder Contracting Inc. (NCI). Coal from our White Flame Surface mine and the coal recovered by NCI is trucked to our Mate Creek load-out where it is blended and loaded onto rail for shipment to customers. Coal from the Premium Energy Surface mine is currently trucked and sold to Arch Coal Inc.’s Mingo Logan mining complex. Coal from the Twin Star surface mine is trucked to our Virginia Energy load-out where it is loaded onto rail cars for transport to customers. The Callaway business unit has no active underground operations and did not purchase any coal from third parties during 2005. As of February 1, 2006, the Callaway business unit was operating at a capacity to ship approximately four million tons per year, including coal recovered by NCI as part of its highway construction business.
Marketing, Sales and Customer Contracts
      Our marketing and sales force, which is principally based in Latrobe, Pennsylvania, included 34 employees as of December 31, 2005, and consists of sales managers, distribution/traffic managers and administrative personnel. In addition to selling coal produced in our eight regional business units, we are also actively involved in the purchase and resale of coal mined by others, the majority of which we blend with coal produced from our mines. We have coal supply commitments with a wide range of electric utilities, steel manufacturers, industrial customers and energy traders and brokers. Our overall sales philosophy is to focus first on the customer’s individual needs and specifications, as opposed to simply selling our production inventory. By offering coal of both steam and metallurgical grades blended to provide specific qualities of heat content, sulfur and ash and other characteristics relevant to our customers, we are able to serve a diverse customer base. This diversity allows us to adjust to changing market conditions and provides us with the ability to sustain high sales volumes and sales prices for our coal. Many of our larger customers are well-established public utilities who have been customers of ours or our Predecessor and acquired companies for decades.
      We sold a total of 26.7 million tons of coal in 2005, consisting of 20.6 million tons of produced and processed coal and 6.1 million tons of purchased coal that we resold without processing. Of our total purchased coal sales of 7.6 million tons in 2005, approximately 5.0 million tons were blended prior to resale, meaning the coal was mixed with coal produced from our mines prior to resale, which generally allows us to realize a higher overall margin for the blended product than we would be able to achieve selling these coals separately. Approximately 1.5 million tons of our 2005 purchased coal sales were processed by us, meaning we washed, crushed or blended the coal at one of our preparation plants or loading facilities prior to resale. We sold a total of 25.3 million tons of coal in 2004, consisting of 18.9 million tons of produced and processed coal and 6.4 million tons of purchased coal that we resold without processing. Of our total purchased coal sales of 7.3 million tons in 2004, approximately 5.9 million tons were blended prior to resale. Approximately 0.9 million tons of our 2004 purchased coal sales were processed by us. We sold a total of 21.6 million tons of coal in 2003, consisting of 17.7 million tons of produced and processed coal and 3.9 million tons of purchased coal that we resold without processing. Of our total purchased coal sales of 5.4 million tons in 2003, approximately 1.5 million tons were processed prior to resale. The breakdown of tons sold by market served for 2005, 2004 and 2003 is set forth in the table below:
                                 
    Steam Coal Sales(1)   Metallurgical Coal Sales
         
Year   Tons   % of Total Sales   Tons   % of Total Sales
                 
    (In millions, except percentages)
2005
    16.7       63 %     10.0       37 %
2004
    15.8       63 %     9.5       37 %
2003
    15.3       71 %     6.3       29 %

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(1)  Steam coal sales include sales to utility and industrial customers. Sales of steam coal to industrial customers, who we define as consumers of steam coal who do not generate electricity for sale to third parties, accounted for approximately 3%, 4% and 5% of total sales in 2005, 2004 and 2003, respectively.
      We sold coal to over 110 different customers in 2005. Our top ten customers in 2005 accounted for approximately 38% of 2005 revenues and our largest customer during 2005 accounted for approximately 6% of 2005 revenues. The following table provides information regarding our exports (including to Canada) in 2005, 2004 and 2003 by revenues and tons sold:
                                 
        Export Tons       Export Sale
        Sold as a       Revenues as a
    Export Tons   Percentage of   Export Sale   Percentage of
Year   Sold   Total Coal Sales   Revenues (1)   Total Revenues
                 
    (In millions, except percentages)
2005
    8.4       31 %   $ 737.1       45 %
2004
    8.1       32 %   $ 597.9       48 %
2003
    4.9       22 %   $ 220.8       28 %
 
(1)  Export sale revenues in 2005 and 2004 include approximately $0.6 million and $4.0 million, respectively, in equipment export sales. All other export sale revenues are coal sales revenues and freight and handling revenues.
      Our export shipments during 2005, 2004 and 2003 serviced customers in 16, 18 and 11 countries, respectively, across North America, Europe, South America, Asia and Africa. Canada was our largest export market in 2005 with sales to Canada accounting for approximately 15% of export revenues and 7% of total revenues. Japan was our largest export market in 2004 accounting for approximately 23% of export revenues and approximately 11% of total revenues, while Canada was our largest export market in 2003, with sales to Canada accounting for approximately 40% of export revenues and approximately 11%of total revenues. All of our sales are made in U.S. dollars, which reduces foreign currency risk. A portion of our sales are subject to seasonal fluctuation, with sales to certain customers being curtailed during the winter months due to the freezing of lakes that we use to transport coal to those customers.
      As is customary in the coal industry, when market conditions are appropriate and particularly in the steam coal market, we enter into long-term contracts (exceeding one year in duration) with many of our customers. These arrangements allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. A significant majority of our steam coal sales are shipped under long-term contracts. During 2003, most of our contracts to supply metallurgical coal were entered into on a one-year rolling basis or on a current market or spot basis. However, due to market conditions, the majority of the metallurgical coal sales contracts we entered into during 2004 and 2005 were long-term contracts. During 2005, approximately 86% and 75% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts and during 2004, approximately 83% and 55% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts.
      As of February 22, 2006, we had contracts to sell 91% of our planned 2006 production, 46% of our planned 2007 production, and 25% of our planned 2008 production. At December 31, 2005, we had commitments to purchase 4.5 million tons of coal during 2006 and 0.5 million tons in 2007.
      The terms of our contracts result from bidding and negotiations with customers. Consequently, the terms of these contracts typically vary significantly in many respects, including price adjustment features, provisions permitting renegotiation or modification of coal sale prices, coal quality requirements, quantity parameters, flexibility and adjustment mechanisms, permitted sources of supply, treatment of environmental constraints, options to extend and force majeure, suspension, termination and assignment provisions, and provisions regarding the allocation between the parties of the cost of complying with future governmental regulations.

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Distribution
      We employ transportation specialists who negotiate freight and terminal agreements with various providers, including railroads, trucks, barge lines, and terminal facilities. Transportation specialists also coordinate with customers, mining facilities and transportation providers to establish shipping schedules that meet the customer’s needs. Our coal sales of 26.7 million tons during 2005 were loaded from our 11 preparation plants and in certain cases directly from our mines and, in the case of purchased coal, in some cases directly from mines and preparation plants operated by third parties or from an export terminal. Virtually all of our coal is transported from the mine to our preparation plants by truck or rail, and then from the preparation plant to the customer by means of railroads, trucks, barge lines and ocean-going vessels from terminal facilities. Rail shipments constituted approximately 80% of total shipments of coal volume produced and processed coal from our mines to the preparation plant to the customer in 2005. The balance was shipped from our preparation plants, loadout facilities or mines via truck. In 2005, approximately 11% of our coal sales were ultimately delivered to customers through transport on the Great Lakes, approximately 13% was moved through the Norfolk Southern export facility at Norfolk, Virginia, approximately 6% was moved through the coal export terminal at Newport News, Virginia operated by Dominion Terminal Associates, 4% was moved through the export terminal at Baltimore, Maryland, and approximately 2% was moved through an export terminal at New Orleans, LA. We own a 32.5% interest in the coal export terminal at Newport News, Virginia operated by Dominion Terminal Associates. See “— Other Operations.” Of the 3.3 million tons of coal sold by the Nicewonder Coal Group in 2005 prior to our acquisition of that business, 50% was shipped via the Norfolk Southern Rail, and the remaining 50% was delivered via truck to other coal companies for resale
Competition
      With respect to our U.S. customers, we compete with numerous coal producers in the Appalachian region and with a large number of western coal producers in the markets that we serve. Competition from coal with lower production costs shipped east from western coal mines has resulted in increased competition for coal sales in the Appalachian region. We face limited competition from imports for our domestic customers. In 2004, only 2.5% of total U.S. coal consumption was imported. Excess industry capacity, which has occurred in the past, tends to result in reduced prices for our coal. The most important factors on which we compete are delivered coal price, coal quality and characteristics, transportation costs from the mine to the customer and the reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry, which has accounted for approximately 91% of domestic coal consumption over the last five years. These coal consumption patterns are influenced by factors beyond our control, including the demand for electricity, which is significantly dependent upon summer and winter temperatures in the United States, environmental and other government regulations, technological developments and the location, availability, quality and price of competing fuels for power such as natural gas, nuclear, fuel oil and alternative energy sources such as hydroelectric power. Demand for our low sulfur coal and the prices that we will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances in order to meet Clean Air Act requirements.
      Demand for our metallurgical coal and the prices that we will be able to obtain for metallurgical coal will depend to a large extent on the demand for U.S. and international steel, which is influenced by factors beyond our control, including overall economic activity and the availability and relative cost of substitute materials. In the export metallurgical market, during 2005 and 2004 we largely competed with producers from Australia, Canada, and other international producers of metallurgical coal.
      In addition to competition for coal sales in the United States and internationally, we compete with other coal producers, particularly in the Appalachian region, for the services of experienced coal industry employees at all levels of our mining operations.

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Other Operations
      We have other operations and activities in addition to our normal coal production, processing and sales business, including:
      Highway Construction Business. NCI operates a highway construction business under a contract with the State of West Virginia Department of Transportation. Pursuant to the contract, NCI is building approximately 11 miles of rough grade highway in West Virginia over the next five to six years and, in exchange NCI will be compensated by West Virginia based on the number of cubic yards of material excavated and/or filled to create a road bed, as well as for certain other cost components.
      Maxxim Rebuild. We own Maxxim Rebuild Co., LLC, a mining equipment company with facilities in Kentucky and Virginia. This business largely consists of repairing and reselling equipment and parts used in surface mining and in supporting preparation plant operations. Maxxim Rebuild had revenues of $29.3 million for 2005, of which approximately 41% was generated by services provided to our other subsidiaries and approximately 2% was generated by equipment sales to export customers.
      Dominion Terminal Associates. Through our subsidiary Alpha Terminal Company, LLC, we hold a 32.5% interest in Dominion Terminal Associates, a 22 million-ton annual capacity coal export terminal located in Newport News, Virginia. The terminal, constructed in 1982, provides the advantages of state of the art unloading/transloading equipment with ground storage capability, providing producers with the ability to custom blend export products without disrupting mining operations. During 2005, we shipped a total of 1.5 million tons of coal to our customers through the terminal. We make periodic cash payments in respect of the terminal for operating expenses, which are partially offset by payments we receive for transportation incentive payments and for renting our unused storage space in the terminal to third parties. Our cash payments for expenses for the terminal in 2005 were $4.1 million, partially offset by payments received in 2005 of $1.9 million. The terminal is held in a partnership with subsidiaries of three other companies, Dominion Energy (20%), Arch Coal (17.5%) and Peabody Energy (30%). Alpha Terminal Company and its other interested partners are currently pursuing an investment of approximately $35.0 million in the construction of a new coal import facility at the terminal. Engineering and permitting work on the project has been completed, and construction is expected to begin in the second half of 2006. The parties are currently in the process of determining which partners will participate in the investment.
      Miscellaneous. We engage in the sale of certain non-strategic assets such as timber, gas and oil rights as well as the leasing and sale of non-strategic surface properties and reserves. We also provide coal and environmental analysis services.
Employee and Labor Relations
      Approximately 95% of our coal production in 2005 came from mines operated by union-free employees, and as of December 31, 2005, over 92% of our subsidiaries’ approximately 3,309 employees were union-free. We believe our employee relations are good and there have been no material work stoppages at any of our subsidiaries’ properties in the past ten years.
Environmental and Other Regulatory Matters
      Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining, and the effects of mining on groundwater quality and availability. These regulations and legislation have had, and will continue to have, a significant effect on our production costs and our competitive position. Future legislation, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, may require substantial increases in equipment and operating costs to us and delays, interruptions, or a termination of operations, the extent of which we cannot predict. We intend to respond to these regulatory requirements at the appropriate time by implementing necessary modifications to facilities or

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operating procedures. Future legislation, regulations or orders may also cause coal to become a less attractive fuel source, thereby reducing coal’s share of the market for fuels used to generate electricity. As a result, future legislation, regulations or orders may adversely affect our mining operations, cost structure or the ability of our customers to use coal.
      We endeavor to conduct our mining operations in compliance with all applicable federal, state, and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations occur from time to time. None of the violations or the monetary penalties assessed upon us since our inception in 2002 has been material. Nonetheless, we expect that future liability under or compliance with environmental and safety requirements could have a material effect on our operations or competitive position. Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described below. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.
      As of December 31, 2005, we had accrued $53.5 million for reclamation liabilities and mine closures, including $7.2 million of current liabilities.
      Mining Permits and Approvals. Numerous governmental permits or approvals are required for mining operations. When we apply for these permits and approvals, we may be required to present data to federal, state or local authorities pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment. The authorization, permitting and/or implementation requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position to control another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.
      In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including us, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior or better condition, productive use or other permitted condition. Typically, we submit our necessary permit applications several months, or even years, before we plan to begin mining a new area. Although permits may take six months or longer to obtain, in the past we have generally obtained our mining permits without significant delay. However, we cannot be sure that we will not experience difficulty in obtaining mining permits in the future.
      Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals from the OSM, or from the applicable state agency if the state agency has obtained primacy. A state agency may achieve primacy if the state regulatory agency develops a mining regulatory program that is no less stringent than the federal mining regulatory program under SMCRA. States in which we have active mining operations have achieved primacy and a state agency is the regulatory authority for SMCRA permitting and enforcement activities.
      SMCRA permit provisions include a complex set of requirements which include, but are not limited to: coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; disposal of excess spoil; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; post mining land use development; and re-vegetation.
      The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes, but is not limited to, surveys and/or assessments of the following: cultural and historical resources; geology, including soils; existing vegetation; benthics; wildlife; potential for endangered species; surface and ground water hydrology; climatol-

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ogy; streams; and wetlands. The geologic data is used to define and model the soil and rock structures that will be encountered during the mining process. The geologic data and data from the other surveys and/or assessments are used to develop the mining and reclamation plans presented in the permit application. The mining and reclamation plans incorporate the provisions and performance standards of the state’s equivalent SMCRA regulatory program, and are also used to support applications for other authorizations and/or permits required to conduct coal mining activities. Also included in the permit application is information used for documenting surface and mineral ownership, variance requests, access roads, bonding information, mining methods, mining phases, other agreements that may relate to coal, other minerals, oil and gas rights, water rights, permitted areas, and ownership and control information required to determine compliance with OSM’s Applicant Violator System, including the mining and compliance history of officers, directors and principal owners of the entity.
      Once a permit application is prepared and submitted to the regulatory agency, it goes through an administrative completeness review and a thorough technical review. Also, before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of all reclamation obligations. After the application is submitted, a public notice or advertisement of the proposed permit is required to be given, which begins a notice period that is followed by a public comment period before a permit can be issued. It is not uncommon for a SMCRA mine permit application to take over a year to prepare, depending on the size and complexity of the mine, and anywhere from six months to two years or even longer for the permit to be issued. The variability in time frame required to prepare the permit and issue the permit can be attributed primarily to the various regulatory authorities’ discretion in the handling of comments and objections relating to the project received from the general public and other agencies. Also, it is not uncommon for a permit to be delayed as a result of litigation related to the specific permit or another related company’s permit.
      In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund, which was created by SMCRA, requires a fee on all coal produced. The current fee is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal, but tax rate revisions are currently pending. The main purpose of the fee proceeds is to fund the reclamation of mine lands closed or abandoned prior to SMCRA’s adoption in 1977. On April 4, 2005, the United States Court of Federal Claims ruled that this fee is unconstitutional to the extent it is levied on exported coal. We do not know whether the U.S. government will appeal this ruling.
      SMCRA stipulates compliance with many other major environmental statutes, including: the Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act (“RCRA”) and Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”).
      Surety Bonds. Mine operators are often required by federal and/or state laws to assure, usually through the use of surety bonds, payment of certain long-term obligations including, but not limited to, mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other miscellaneous obligations. Although surety bonds are usually noncancelable during their term, many of these bonds are renewable on a yearly basis. The costs of these bonds have increased in recent years while the market terms of surety bonds have generally become more unfavorable to mine operators. These changes in the terms of the bonds have been accompanied by a decrease in recent years in the number of companies willing to issue surety bonds. We have a committed bonding facility with Travelers Casualty and Surety Company of America, pursuant to which Travelers has agreed, subject to certain conditions, to issue surety bonds on our behalf in a maximum amount of $150.0 million. As of December 31, 2005, we have posted an aggregate of $116.7 million in reclamation bonds and $8.3 million of other types of bonds under this facility.
      Clean Air Act. The Clean Air Act and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter which may include controlling fugitive dust. The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of fine particulate matter measuring 2.5 micrometers in diameter or smaller, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired

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electricity generating plants. Continued tightening of the already stringent regulation of emissions from coal-fired power plants could eventually reduce the demand for coal.
      Clean Air Act requirements that may directly or indirectly affect our operations include the following:
  •  Acid Rain. Title IV of the Clean Air Act required a two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and applies to all coal-fired power plants generating greater than 25 Megawatts. Generally, the affected electricity generators have sought to meet these requirements by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances. Although we cannot accurately predict the future effect of this Clean Air Act provision on our operations, we believe that implementation of Phase II has resulted in, and will continue to result in, an upward pressure on the price of lower sulfur coals, as coal-fired power plants continue to comply with the more stringent restrictions of Title IV.
 
  •  Fine Particulate Matter. The Clean Air Act requires the U.S. Environmental Protection Agency (the “EPA”) to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for certain pollutants. Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels. For example, NAAQS currently exist for particulate matter with an aerodynamic diameter less than or equal to 10 microns, or PM10, and for fine particulate matter with an aerodynamic diameter less than or equal 2.5 microns, or PM2.5. The EPA designated all or part of 225 counties in 20 states as well as the District of Columbia as non-attainment areas with respect to the PM2.5 NAAQS. Individual states must identify the sources of emissions and develop emission reduction plans. These plans may be state-specific or regional in scope. Under the Clean Air Act, individual states have up to twelve years from the date of designation to secure emissions reductions from sources contributing to the problem. Meeting the new PM2.5 standard may require reductions of nitrogen oxide and sulfur dioxide emissions. Future regulation and enforcement of the new PM2.5 standard will affect many power plants, especially coal-fired plants and all plants in “non-attainment” areas.
 
  •  Ozone. Significant additional emissions control expenditures will be required at coal-fired power plants to meet the current NAAQS for ozone. Nitrogen oxides, which are a by-product of coal combustion, are classified as an ozone precursor. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding in the years ahead. For example, in November 2005 EPA issued a final rule, called the Phase 2 Ozone Rule, describing the action that states must take to reduce ground level ozone. The EPA designated counties in 32 states as non-attainment areas under the new standard. These states will have until June 2007 to develop plans, referred to as state implementation plans or SIPs, for pollution control measures that allow them to comply with the standards.
 
  •  NOx SIP Call. The NOx SIP Call program was established by the EPA in October of 1998 to reduce the transport of ozone on prevailing winds from the Midwest and South to states in the Northeast, which said they could not meet federal air quality standards because of migrating pollution. The program is designed to reduce nitrous oxide emissions by one million tons per year in 22 eastern states and the District of Columbia. Installation of additional control measures, such as selective catalytic reduction devices, required under the final rules will make it more costly to operate coal-fired electricity generating plants, thereby making coal a less attractive fuel.
 
  •  Clear Skies Initiative. The Bush Administration has proposed a plan, commonly referred to as the Clear Skies Initiative, that could result in dramatic reductions in nitrous oxide, sulfur dioxide, and mercury emissions by power plants through “cap-and-trade” programs similar to the existing Acid Rain regulations and current NOx budget programs. It is currently not possible to predict what, if any, new regulatory requirements will ultimately evolve out of this initiative.
 
  •  Clean Air Interstate Rule. The EPA finalized the Clean Air Interstate Rule (CAIR) on March 10, 2005. The new CAIR calls for power plants in 29 eastern states and the District of Columbia to reduce

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  emission levels of sulfur dioxide and nitrous oxide. The rule requires states to regulate power plants under a cap and trade program similar to the system now in effect for acid deposition control and to that proposed by the Clear Skies Initiative. When fully implemented, this rule is expected to reduce regional sulfur dioxide emissions by over 70% and nitrogen oxides emissions by over 60% from 2003 levels. The stringency of the cap may require many coal-fired electricity generation plants to install additional pollution control equipment, such as wet scrubbers, to comply, which could decrease the demand for low sulfur coal at these plants and thereby potentially reduce market prices for low sulfur coal. Emissions are permanently capped and cannot increase. On December 3, 2005, the EPA published a notice that it was reconsidering four specific issues that are involved in this rule and was accepting public comment until January 13, 2006. The rule is also subject to judicial challenge, which makes its impact difficult to assess.
 
  •  Clean Air Mercury Rule. On March 15, 2005, the EPA issued the Clean Air Mercury Rule to permanently cap and reduce mercury emissions from coal-fired power plants. The Clean Air Mercury Rule establishes mercury emissions limits from new and existing coal-fired power plants and creates a market-based cap-and-trade program that is expected to reduce nationwide utility emissions of mercury in two phases. Several states and environmental groups have filed suits in the U.S. Court of Appeals for the District of Columbia challenging the EPA’s decision to allow emissions trading and its decision to reverse a regulatory finding in 2000 that would have required emission limits for mercury based maximum achievable control technology under section 112 of the Clean Air Act. Many of the challenges seek to impose more stringent rules. In addition, efforts have commenced in Congress to legislatively disapprove the rules. The EPA recently announced that it is seeking further public comment on the Clean Air Mercury Rule and is reconsidering the decision not to regulate mercury and other pollutants from coal-fired power plants under the Clean Air Act’s hazardous air pollution program. Stricter limitations on mercury emissions from power plants may adversely affect the demand for coal.
 
  •  Carbon Dioxide. In February 2003, a number of states notified the EPA that they planned to sue the agency to force it to set new source performance standards for utility emissions of carbon dioxide and to tighten existing standards for sulfur dioxide and particulate matter for utility emissions. In June 2003, three of these states sued the EPA seeking a court order requiring the EPA to designate carbon dioxide as a criteria pollutant and to issue a new NAAQS for carbon dioxide. If these lawsuits result in the issuance of a court order requiring the EPA to set emission limitations for carbon dioxide and/or lower emission limitations for sulfur dioxide and particulate matter, it could reduce the amount of coal our customers would purchase from us.
 
  •  Regional Emissions Trading. Eleven Northeast and Mid-Atlantic states are working cooperatively to develop a regional cap and trade program that would initially cover carbon dioxide emissions from power plants in the region. No formal model rule has been made public to date. There are a number of uncertainties regarding this initiative, including the applicable baseline of emissions to be permitted, initial allocations, required emissions reductions, availability of offsets, the extent to which states will adopt the program, whether it will be linked with programs in other states or in Canadian provinces, and the timing for implementation of the program. There can be no assurance at this time that a carbon dioxide cap and trade program, if implemented by the states where our customers operate, will not affect the future market for coal in this region.
 
  •  Regional Haze. The EPA has initiated a regional haze program designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could affect the future market for coal.

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      Clean Water Act. The Clean Water Act of 1972 (the “CWA”) and comparable state laws that regulate waters of the United States (“Jurisdictional waters”) can affect coal mining operations both directly and indirectly. One of the direct impacts on coal mining and processing operations is Clean Water Act permitting requirements relating to the discharge of pollutants into Jurisdictional Waters. Indirect impacts of the CWA include discharge limits placed on coal-fired power plant ash handling facilities’ discharges. Continued litigation of CWA issues could eventually reduce the demand for coal.
      Clean Water Act requirements that may directly or indirectly affect our operations include, but are not limited to, the following:
  •  Section 402 of the Clean Water Act. Section 402 of the CWA establishes in-stream water quality criteria and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring and compliance with reporting requirements and performance standards are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water. The imposition of future restrictions on the discharge of certain pollutants into waters of the United States could affect the permitting process, increase the costs and difficulty of obtaining and complying with NPDES permits and could adversely affect our coal production.
        Total Maximum Daily Load (“TMDL”) regulations established a process by which states designate stream segments as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, will be required to meet new TMDL effluent standards for these stream segments. Some of our operations currently discharge effluents into stream segments that have been designated as impaired. The adoption of new TMDL related effluent limitations for our coal mines could require more costly water treatment and could adversely affect our coal production.
        Under the CWA, states must conduct an anti-degradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality. A state’s anti-degradation regulations would prohibit the diminution of water quality in these streams. Several environmental groups and individuals recently challenged, and in part successfully, West Virginia’s anti-degradation policy. In general, waters discharged from coal mines to high quality streams will be required to meet or exceed new “high quality” standards. This could cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits, and could adversely affect our coal production.
  •  Section 404 of the Clean Water Act. Permits under Section 404 of the CWA are required for coal companies to conduct dredging or filling activities in jurisdictional waters for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. Jurisdictional waters typically include ephemeral, intermittent, and perennial streams and may in certain instances include man-made conveyances that have a hydrologic connection to a stream or wetland.
        The Army Corps of Engineers (the “COE”) is empowered to issue “nationwide” permits for specific categories of filling activities that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404. Nationwide Permit 21 authorizes the disposal of dredge-and- fill material from mining activities into the waters of the United States. On October 23, 2003, several citizens groups sued the COE in the U.S. District Court for the Southern District of West Virginia seeking to invalidate “nationwide” permits utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. Although the lower court enjoined the issuance of Nationwide 21 permits, that decision was overturned by the Fourth Circuit Court of Appeals, which concluded that the COE complied with the CWA in promulgating this permit. Although Alpha had no operations that were interrupted, the lower court’s decision required us to convert certain ongoing and planned applications for Nationwide 21 permits to applications for individual permits. A similar lawsuit was filed on January 27, 2005 in the U.S. District Court for the Eastern District of Kentucky, and other lawsuits may be filed in other states where Alpha operates.

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      Mine Safety and Health. Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. In addition to federal regulatory programs, all of the states in which we operate also have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. In reaction to the recent mine tragedies in West Virginia, additional regulatory scrutiny and legislative activities targeting mine safety at both the state and federal levels have occurred. While existing and proposed regulations have a significant effect on our operating costs, our U.S. competitors are subject to the same degree of regulation.
      Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface- mined coal, neither amount to exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the United States. In 2005, we recorded $12.2 million of expense related to this excise tax.
      Coal Industry Retiree Health Benefit Act of 1992. Unlike many companies in the coal business, we do not have any liability under the Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”), which requires the payment of substantial sums to provide lifetime health benefits to union-represented miners (and their dependents) who retired before 1992, because liabilities under the Coal Act that had been imposed on our Predecessor or acquired companies were retained by the sellers and, if applicable, their parent companies, in the applicable acquisition agreements. We should not be liable for these liabilities retained by the sellers unless they and, if applicable, their parent companies, fail to satisfy their obligations with respect to Coal Act claims and retained liabilities covered by the acquisition agreements.
      Endangered Species Act. The federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to the areas in which we operate are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.
      Resource Conservation and Recovery Act. The RCRA may affect coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. Currently, certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management.
      Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion wastes generated at electric utility and independent power producing facilities, such as coal ash. In May 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under RCRA. The EPA is retaining the hazardous waste exemption for these wastes. However, the EPA has determined that national non-hazardous waste regulations under RCRA Subtitle D are needed for coal combustion wastes disposed in surface impoundments and landfills and used as mine-fill. The agency also concluded beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. As long as this exemption remains in effect, it is not anticipated that regulation of coal combustion waste will have any material effect on the amount of coal used by electricity generators. Most state hazardous waste laws also exempt coal combustion waste, and instead treat it as either

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a solid waste or a special waste. Any costs associated with handling or disposal of hazardous wastes would increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of ash can lead to material liability.
      Due to the hazardous waste exemption for coal combustion waste such as ash, much coal combustion waste is currently put to beneficial use. For example, in one Pennsylvania mine from which we have the right to receive coal, we have used some ash as mine fill. The ash we use for this purpose is mixed with lime and serves to help alleviate the potential for acid mine drainage.
      Federal and State Superfund Statutes. Superfund and similar state laws may affect coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault. In addition, mining operations may have reporting obligations under the Emergency Planning and Community Right to Know Act and the Superfund Amendments and Reauthorization Act.
      Climate Change. One major by-product of burning coal is carbon dioxide, which is considered a greenhouse gas and is a major source of concern with respect to global warming. In November 2004, Russia ratified the Kyoto Protocol to the 1992 Framework Convention on Global Climate Change (the “Protocol”), which establishes a binding set of emission targets for greenhouse gases. With Russia’s accedence, the Protocol now has sufficient support and became binding on all those countries that have ratified it on February 16, 2005. Four industrialized nations have refused to ratify the Protocol — Australia, Liechtenstein, Monaco, and the United States. Although the targets vary from country to country, if the United States were to ratify the Protocol our nation would be required to reduce greenhouse gas emissions to 93% of 1990 levels from 2008 to 2012. Canada, which accounted for 6% of our sales volume in 2004, ratified the Protocol in 2002. Under the Protocol, Canada will be required to cut greenhouse gas emissions to 6% below 1990 levels in 2008 to 2012, either in direct reductions in emissions or by obtaining credits through the Protocol’s market mechanisms. This could result in reduced demand for coal by Canadian electric power generators.
      Future regulation of greenhouse gases in the United States could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act, state adoption of a greenhouse regulatory scheme, or otherwise. The Bush Administration has proposed a package of voluntary emission reductions for greenhouse gases reduction targets which provide for certain incentives if targets are met. Some states, such as Massachusetts, have already issued regulations regulating greenhouse gas emissions from large power plants. Further, in 2002, the Conference of New England Governors and Eastern Canadian Premiers adopted a Climate Change Action Plan, calling for reduction in regional greenhouse emissions to 1990 levels by 2010, and a further reduction of at least 10% below 1990 levels by 2020. Increased efforts to control greenhouse gas emissions, including the future ratification of the Protocol by the U.S., could result in reduced demand for coal.
Additional Information
      We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You may access and read our SEC filings through our website, at www.alphanr.com, or the SEC’s website, at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. You may also request copies of our filings, at no cost, by telephone at (276) 619-4410 or by mail at: Alpha Natural Resources, Inc., One Alpha Place, P.O. Box 2345, Abingdon, Virginia 24212, attention: Investor Relations.
      Our Audit Committee Charter, Compensation Committee Charter, Nominating and Corporate Governance Committee Charter, Corporate Governance Practices and Policies, and Code of Business Ethics are also available on our website and available in print to any stockholder who requests it.

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Item 1A. Risk Factors
A substantial or extended decline in coal prices could reduce our revenues and the value of our coal reserves.
      Our results of operations are substantially dependent upon the prices we receive for our coal. The prices we receive for coal depend upon factors beyond our control, including:
  •  the supply of and demand for domestic and foreign coal;
 
  •  the demand for electricity;
 
  •  domestic and foreign demand for steel and the continued financial viability of the domestic and/or foreign steel industry;
 
  •  the proximity to, capacity of, and cost of transportation facilities;
 
  •  domestic and foreign governmental regulations and taxes;
 
  •  air emission standards for coal-fired power plants;
 
  •  regulatory, administrative, and judicial decisions;
 
  •  the price and availability of alternative fuels, including the effects of technological developments; and
 
  •  the effect of worldwide energy conservation measures.
      Declines in the prices we receive for our coal could adversely affect our operating results and our ability to generate the cash flows we require to improve our productivity and invest in our operations.
Our coal mining production and delivery is subject to conditions and events beyond our control, which could result in higher operating expenses and/or decreased production and sales and adversely affect our operating results.
      Our coal mining operations are conducted, in large part, in underground mines and, to a lesser extent, at surface mines. The level of our production at these mines is subject to operating conditions and events beyond our control that could disrupt operations, affect production and the cost of mining at particular mines for varying lengths of time and have a significant impact on our operating results. Adverse operating conditions and events that we or our Predecessor have experienced in the past include:
  •  delays and difficulties in acquiring, maintaining or renewing necessary permits or mining or surface rights;
 
  •  changes or variations in geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;
 
  •  mining and processing equipment failures and unexpected maintenance problems;
 
  •  limited availability of mining and processing equipment and parts from suppliers;
 
  •  interruptions due to transportation delays;
 
  •  adverse weather and natural disasters, such as heavy rains and flooding;
 
  •  accidental mine water discharges;
 
  •  the termination of material contracts by state or other governmental authorities;
 
  •  the unavailability of qualified labor;
 
  •  strikes and other labor-related interruptions; and
 
  •  unexpected mine safety accidents, including fires and explosions from methane and other sources.

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      If any of these conditions or events occur in the future at any of our mines or affect deliveries of our coal to customers, they may increase our cost of mining and delay or halt production at particular mines or sales to our customers either permanently for varying lengths of time, which could adversely affect our operating results. For example, in 2004 we experienced mine roof stability issues at our Kingwood underground mine, which resulted in a 23% decrease in production at this mine for 2004 as compared to 2003 full-year production (including production in 2003 prior to our acquisition of the mine). In addition, Hurricanes Katrina and Rita, which struck the Gulf Coast in August and September 2005, resulted in delayed shipments of our coal to our customers.
Any change in coal consumption patterns by steel producers or North American electric power generators resulting in a decrease in the use of coal by those consumers could result in lower prices for our coal, which would reduce our revenues and adversely impact our earnings and the value of our coal reserves.
      Steam coal accounted for approximately 63% of our coal sales volume during 2005 and 2004. The majority of our sales of steam coal for 2005 and 2004 were to U.S. and Canadian electric power generators. Domestic electric power generation accounted for approximately 92% of all U.S. coal consumption in 2004, according to the EIA. The amount of coal consumed for U.S. and Canadian electric power generation is affected primarily by the overall demand for electricity, the location, availability, quality and price of competing fuels for power such as natural gas, nuclear, fuel oil and alternative energy sources such as hydroelectric power, technological developments, and environmental and other governmental regulations. We expect many new power plants will be built to produce electricity during peak periods of demand, when the demand for electricity rises above the “base load demand,” or minimum amount of electricity required if consumption occurred at a steady rate. However, we also expect that many of these new power plants will be fired by natural gas because they are cheaper to construct than coal-fired plants and because natural gas is a cleaner burning fuel. In addition, the increasingly stringent requirements of the Clean Air Act may result in more electric power generators shifting from coal to natural gas-fired power plants. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of steam coal that we mine and sell, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.
      We produce metallurgical coal that is used in both the U.S. and foreign steel industries. Metallurgical coal accounted for approximately 37% of our coal sales volume during 2005 and 2004. In recent years, U.S. steel producers have experienced a substantial decline in the prices received for their products, due at least in part to a heavy volume of foreign steel imported into the United States. Although prices for some U.S. steel products increased moderately after the Bush administration imposed steel import tariffs and quotas in March 2002, those tariffs and quotas were lifted in December 2003. Furthermore, recent reports by the American Iron and Steel Institute indicate that the volume of shipments by U.S. steel mills in September 2005 was down 3.4% from the previous month and 6.5% from September 2004 and that, based on preliminary data for October 2005, U.S. steel imports for October 2005 and the ten months ended October 31, 2005 were approximately 28% and 10% lower, respectively, than in the applicable prior year periods, which may be leading indicators of declining demand in the U.S. steel industry generally. Any deterioration in conditions in the U.S. steel industry would reduce the demand for our metallurgical coal and could impact the collectibility of our accounts receivable from U.S. steel industry customers. In addition, the U.S. steel industry increasingly relies on electric arc furnaces or pulverized coal processes to make steel. These processes do not use coke. If this trend continues, the amount of metallurgical coal that we sell and the prices that we receive for it could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves. In the international market for metallurgical coal, there are indications that coal prices may have begun to level off or decline from their current, historically high levels. In a report issued at the end of November, the EIA reported that 2005 steel production in China has been well above projections, resulting in a glut of steel despite China’s current position as the world’s largest consumer of steel. Despite the restrictions on metallurgical coal exports announced by China in 2003, the EIA noted reports of Chinese producers offering coke for export at Chinese ports. If the demand and pricing for metallurgical coal in international markets decreases in the future, the amount of metallurgical coal that we sell and the prices that we receive

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for it could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.
A decline in demand for metallurgical coal would limit our ability to sell our high quality steam coal as higher-priced metallurgical coal and could affect the economic viability of certain of our mines that have higher operating costs.
      Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on the prevailing conditions in the metallurgical and steam coal markets. We decide whether to mine, process and market these coals as metallurgical or steam coal based on management’s assessment as to which market is likely to provide us with a higher margin. We consider a number of factors when making this assessment, including the difference between the current and anticipated future market prices of steam coal and metallurgical coal, the lower volume of saleable tons that results from producing a given quantity of reserves for sale in the metallurgical market instead of the steam market, the increased costs incurred in producing coal for sale in the metallurgical market instead of the steam market, the likelihood of being able to secure a longer-term sales commitment by selling coal into the steam market and our contractual commitments to deliver different types of coals to our customers. During 2004, we believe that we sold approximately 8% of our produced and processed coal as metallurgical coal that we would have sold as steam coal in the market conditions prevalent during 2003. We believe that we generated approximately $65.0 million in additional revenues by selling this production as metallurgical coal rather than steam coal during 2004, based on a comparison of the actual sales price and volume versus the then-prevailing market price for steam coal and the volume of coal that we would have sold if the coal had been mined, processed and marketed as steam coal. A decline in the metallurgical market relative to the steam market could cause us to shift coal from the metallurgical market to the steam market, thereby reducing our revenues and profitability.
      Most of our metallurgical coal reserves possess quality characteristics that enable us to mine, process and market them as high quality steam coal. However, some of our mines operate profitably only if all or a portion of their production is sold as metallurgical coal to the steel market. If demand for metallurgical coal declined to the point where we could earn a more attractive return marketing the coal as steam coal, these mines may not be economically viable and may be subject to closure. Such closures would lead to accelerated reclamation costs, as well as reduced revenue and profitability.
Acquisitions that we have completed since our formation, as well as acquisitions 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 December 2002, we have completed four significant acquisitions and several smaller acquisitions and investments. We continually seek to expand our operations and coal reserves through acquisitions. If we are unable to successfully integrate the companies, businesses or properties we are able to acquire, our profitability may decline and we could experience a material adverse effect on our business, financial condition, or results of operations. Acquisition transactions involve various inherent risks, including:
  •  uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental or mine safety liabilities) of, acquisition candidates;
 
  •  the potential loss of key customers, management and employees of an acquired business;
 
  •  the ability to achieve identified operating and financial synergies anticipated to result from an acquisition;
 
  •  problems that could arise from the integration of the acquired business; and
 
  •  unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the acquisition.

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      Any one or more of these factors could cause us not to realize the benefits anticipated to result from an acquisition. For example, in combining our Predecessor and acquired companies, we have incurred significant expenses to develop unified reporting systems and standardize our accounting functions. Additionally, we were unable to profitably operate NKC, which we acquired in connection with our acquisition of AMCI. In September 2004, we recorded an impairment charge of $5.1 million to reduce the carrying value of the assets of NKC to their estimated fair value, and we sold the assets of NKC on April 14, 2005.
      The recently completed Nicewonder Acquisition has increased the size of our operations. Our ability to integrate the operations of the Nicewonder Coal Group with our own is important to our future success. If we are unable to realize the anticipated benefits of the Nicewonder Acquisition due to our inability to address the challenges of integrating the Nicewonder Coal Group or for any other reason, it could have a material adverse effect on our business and financial and operating results and require significant additional time on the part of our senior management dedicated to resolving integration issues.
      Moreover, any acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. For instance, in connection with the Nicewonder Acquisition, we issued and subsequently repaid $221.0 million principal amount of promissory installment notes of one of our indirect, wholly owned subsidiaries, we issued 2,180,233 shares of our common stock valued at approximately $53.2 million, and we entered into a new $525.0 million credit facility, a portion of the net proceeds of which we used to pay the cash purchase price, acquisition expenses and the first installment of principal due on the promissory notes. In addition, future acquisitions could result in our assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous acquisitions.
The inability of the sellers of our Predecessor and acquired companies to fulfill their indemnification obligations to us under our acquisition agreements could increase our liabilities and adversely affect our results of operations and financial position.
      In the acquisition agreements we entered into with the sellers of our Predecessor and acquired companies, including the acquisition agreements we entered into related to the Nicewonder Acquisition, the respective sellers and, in some of our acquisitions, their parent companies, agreed to retain responsibility for and indemnify us against damages resulting from certain third-party claims or other liabilities, such as workers’ compensation liabilities, black lung liabilities, postretirement medical liabilities and certain environmental or mine safety liabilities. The failure of any seller and, if applicable, its parent company, to satisfy their obligations with respect to claims and retained liabilities covered by the acquisition agreements could have an adverse effect on our results of operations and financial position if claimants successfully assert that we are liable for those claims and/or retained liabilities. The obligations of the sellers and, in some instances, their parent companies, to indemnify us with respect to their retained liabilities will continue for a substantial period of time, and in some cases indefinitely. The sellers’ indemnification obligations with respect to breaches of their representations and warranties in the acquisition agreements will terminate upon expiration of the applicable indemnification period (generally 18-24 months from the acquisition date for most representations and warranties, and from two to five years from the acquisition date for environmental representations and warranties), are subject to deductible amounts and will not cover damages in excess of the applicable coverage limit. The assertion of third-party claims after the expiration of the applicable indemnification period or in excess of the applicable coverage limit, or the failure of any seller to satisfy its indemnification obligations with respect to breaches of its representations and warranties, could have an adverse effect on our results of operations and financial position. See “— If our assumptions regarding our likely future expenses related to benefits for non-active employees are incorrect, then expenditures for these benefits could be materially higher than we have predicted.”
Our inability to continue or expand the existing road construction and mining business of the Nicewonder Companies could adversely affect the expected benefits from the Nicewonder Acquisition.
      One of our subsidiaries acquired the business of Nicewonder Contracting, Inc. (“NCI”) pursuant to the Nicewonder Acquisition. NCI operates a highway construction business under a contract with the State of

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West Virginia. Pursuant to the contract, NCI is building approximately 11 miles of rough grade highway in West Virginia over the next six years and, in exchange, NCI will be compensated by West Virginia based on the number of cubic yards of material excavated and/or filled to create a road bed, as well as for certain other cost components. In the course of the road construction, NCI will recover any coal encountered and sell the coal to its customers, subject to certain costs, including coal loading, transportation, coal royalty payments and applicable taxes and fees.
      This road construction operation is in its early stages and the State of West Virginia has only approved funding for the first phases of highway construction. If West Virginia does not fund the remaining sections of the highway project, it would adversely affect NCI’s earnings. Even if West Virginia funds the remainder of this project through the next six years, we are uncertain whether the state will fund any similar projects in the future. In addition, we have no current experience conducting and completing road projects and will rely on the expertise of the existing employees of NCI in order to operate the project, and other road projects we may undertake, profitably. Furthermore, litigation has been filed against NCI and the State of West Virginia claiming that the project violated competitive bidding and prevailing wage laws and regulations. If successful, the litigation could make the project considerably less advantageous to NCI or restrict or prohibit NCI from completing the project.
The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues and profitability.
      Our largest customer during 2005 accounted for approximately 6% of our total revenues. We derived approximately 38% of our 2005 total revenues from sales to our ten largest customers. These customers may not continue to purchase coal from us under our current coal supply agreements, or at all. If these customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our revenues and profitability could suffer materially.
Changes in purchasing patterns in the coal industry may make it difficult for us to extend existing supply contracts or enter into new long-term supply contracts with customers, which could adversely affect the capability and profitability of our operations.
      We sell a significant portion of our coal under long-term coal supply agreements, which are contracts with a term greater than 12 months. The execution of a satisfactory long-term coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract. We believe that approximately 82% of our 2005 sales volume was sold under long-term coal supply agreements. At December 31, 2005, our long-term coal supply agreements had remaining terms of up to 11 years and an average remaining term of approximately two years. When our current contracts with customers expire or are otherwise renegotiated, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including pricing terms less favorable to us. As of February 22, 2006, approximately 9%, 54% and 75%, respectively, of our planned production for 2006, 2007 and 2008 was uncommitted. We may not be able to enter into coal supply agreements to sell this production on terms, including pricing terms, as favorable to us as our existing agreements. For additional information relating to our long-term coal supply contracts, see “Business — Marketing, Sales and Customer Contracts.”
      As electric utilities continue to adjust to frequently changing regulations, including the Acid Rain regulations of the Clean Air Act, the Clean Air Mercury Rule, the Clean Air Interstate Rule and the possible deregulation of their industry, they are becoming increasingly less willing to enter into long-term coal supply contracts and instead are purchasing higher percentages of coal under short-term supply contracts. The industry shift away from long-term supply contracts could adversely affect us and the level of our revenues. For example, fewer electric utilities will have a contractual obligation to purchase coal from us, thereby increasing the risk that we will not have a market for our production. The prices we receive in the spot market may be less than the contractual price an electric utility is willing to pay for a committed supply. Furthermore, spot market prices tend to be more volatile than contractual prices, which could result in decreased revenues.

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Certain provisions in our long-term supply contracts may reduce the protection these contracts provide us during adverse economic conditions or may result in economic penalties upon our failure to meet specifications.
      Price adjustment, “price reopener” and other similar provisions in long-term supply contracts may reduce the protection from short-term coal price volatility traditionally provided by these contracts. Price reopener provisions are particularly common in international metallurgical coal sales contracts. Some of our coal supply contracts contain provisions that allow for the price to be renegotiated at periodic intervals. Price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to agree on a new price, sometimes between a pre-set “floor” and “ceiling.” In some circumstances, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Any adjustment or renegotiation leading to a significantly lower contract price could result in decreased revenues. Accordingly, supply contracts with terms of one year or more may provide only limited protection during adverse market conditions.
      Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of our agreements where the customer bears transportation costs permit the customer to terminate the contract if the transportation costs borne by them increase substantially. In addition, some of these contracts allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that increase the price of coal beyond specified limits.
      Due to the risks mentioned above with respect to long-term supply contracts, we may not achieve the revenue or profit we expect to achieve from these sales commitments.
Disruption in supplies of coal produced by contractors and other third parties could temporarily impair our ability to fill customers’ orders or increase our costs.
      In addition to marketing coal that is produced by our subsidiaries’ employees, we utilize contractors to operate some of our mines. Operational difficulties at contractor-operated mines, changes in demand for contract miners from other coal producers, and other factors beyond our control could affect the availability, pricing, and quality of coal produced for us by contractors. For example, during 2005, production at our contractor operations ran approximately 25% behind plan, primarily due to shortages in the supply of labor. As a result of this shortfall, we were forced to purchase coal at a higher cost than planned so that we can meet commitments to customers. To meet customer specifications and increase efficiency in fulfillment of coal contracts, we also purchase and resell coal produced by third parties from their controlled reserves. The majority of the coal that we purchase from third parties is blended with coal produced from our mines prior to resale and we also process (which includes washing, crushing or blending coal at one of our preparation plants or loading facilities) a portion of the coal that we purchase from third parties prior to resale. We sold 7.6 million tons of coal purchased from third parties during 2005, representing approximately 28% of our total sales during 2005. We believe that approximately 67% of our purchased coal sales in 2005 was blended with coal produced from our mines prior to resale, and approximately 6% of our total sales in 2005 consisted of coal purchased from third parties that we processed before resale. The availability of specified qualities of this purchased coal may decrease and prices may increase as a result of, among other things, changes in overall coal supply and demand levels, consolidation in the coal industry and new laws or regulations. Disruption in our supply of contractor-produced coal and purchased coal could temporarily impair our ability to fill our customers’ orders or require us to pay higher prices in order to obtain the required coal from other sources. Any increase in the prices we pay for contractor-produced coal or purchased coal could increase our costs and therefore lower our earnings. Although increases in market prices for coal generally benefit us by allowing us to sell coal at higher prices, those increases also increase our costs to acquire purchased coal, which lowers our earnings.

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Competition within the coal industry may adversely affect our ability to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.
      We compete with numerous other coal producers in various regions of the United States for domestic and international sales. During the mid-1970s and early 1980s, increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in additional production capacity throughout the industry, all of which led to increased competition and lower coal prices. Recent increases in coal prices could encourage the development of expanded capacity by new or existing coal producers. Any resulting overcapacity could reduce coal prices and therefore reduce our revenues.
      Coal with lower production costs shipped east from western coal mines and from offshore sources has resulted in increased competition for coal sales in the Appalachian region. In addition, coal companies with larger mines that utilize the long-wall mining method typically have lower mine operating costs than we do and may be able to compete more effectively on price, particularly if the current favorable market weakens. This competition could result in a decrease in our market share in this region and a decrease in our revenues.
      Demand for our low sulfur coal and the prices that we can obtain for it are also affected by, among other things, the price of emissions allowances. Decreases in the prices of these emissions allowances could make low sulfur coal less attractive to our customers. In addition, more widespread installation by electric utilities of technology that reduces sulfur emissions (which could be accelerated by increases in the prices of emissions allowances), may make high sulfur coal more competitive with our low sulfur coal. This competition could adversely affect our business and results of operations.
      We also compete in international markets against coal produced in other countries. Measured by tons sold, exports accounted for approximately 31% of our sales in 2005. The demand for U.S. coal exports is dependent upon a number of factors outside of our control, including the overall demand for electricity in foreign markets, currency exchange rates, the demand for foreign-produced steel both in foreign markets and in the U.S. market (which is dependent in part on tariff rates on steel), general economic conditions in foreign countries, technological developments, and environmental and other governmental regulations. For example, if the value of the U.S. dollar were to rise against other currencies in the future, our coal would become relatively more expensive and less competitive in international markets, which could reduce our foreign sales and negatively impact our revenues and net income. In addition, if the amount of coal exported from the United States were to decline, this decline could cause competition among coal producers in the United States to intensify, potentially resulting in additional downward pressure on domestic coal prices.
Fluctuations in transportation costs and the availability or reliability of transportation could affect the demand for our coal or temporarily impair our ability to supply coal to our customers.
      Transportation costs represent a significant portion of the total cost of coal for our customers. Increases in transportation costs, such as those experienced during 2005, 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, coordination of the many eastern loading facilities, the large number of small shipments, terrain and labor issues all combine to make shipments originating in the eastern United States inherently more expensive on a per-mile basis than shipments originating in the western United States.
      Historically, high coal transportation rates from the western coal producing areas into Central Appalachian markets limited the use of western coal in those markets. More recently, however, lower rail rates from the western coal producing areas to markets served by eastern U.S. producers have created major competitive challenges for eastern producers. This increased competition could have a material adverse effect on our business, financial condition and results of operations.
      We depend upon railroads, trucks, beltlines, ocean vessels and barges to deliver coal to our customers. Disruption of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair our ability to supply coal to our customers,

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resulting in decreased shipments. Certain shipments of our coal to customers were delayed by the recent hurricanes in the Gulf Coast. In some cases, this delay will affect the timing of our recognition of revenue from these sales. Decreased performance levels over longer periods of time could cause our customers to look to other sources for their coal needs, negatively affecting our revenues and profitability.
      In 2005, 80% of our produced and processed coal volume was transported from the preparation plant to the customer by rail. Beginning in the Spring of 2004, we have experienced a general deterioration in the reliability of the service provided by rail carriers, which increased our internal coal handling costs. If there are continued disruptions of the transportation services provided by the railroad companies we use and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.
      We have investments in mines, loading facilities, and ports that in most cases are serviced by a single rail carrier. Our operations that are serviced by a single rail carrier are particularly at risk to disruptions in the transportation services provided by that rail carrier, due to the difficulty in arranging alternative transportation. If a single rail carrier servicing our operations does not provide sufficient capacity, revenue from these operations and our return on investment could be adversely impacted. The states of West Virginia and Kentucky 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 could undertake similar actions to increase enforcement of weight limits. Such stricter enforcement actions 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 on a profit-making basis and could therefore adversely affect revenues and earnings.
Our business will be adversely affected if we are unable to develop or acquire additional coal reserves that are economically recoverable.
      Our profitability depends substantially on our ability to mine coal reserves possessing quality characteristics desired by our customers in a cost-effective manner. As of December 31, 2005, we owned or leased 489.5 million tons of proven and probable coal reserves that we believe will support current production levels for more than 20 years, which is less than the publicly reported amount of proven and probable coal reserves and reserve lives (based on current publicly reported production levels) of the other large publicly traded coal companies. We have not yet applied for the permits required, or developed the mines necessary, to mine all of our reserves. Permits are becoming increasingly more difficult and expensive to obtain and the review process continues to lengthen. In addition, we may not be able to mine all of our reserves as profitably as we do at our current operations.
      Because our reserves are depleted as we mine our coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. If we are unable to replace or increase our coal reserves on acceptable terms, our production and revenues will decline as our reserves are depleted. 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 acquire additional coal reserves through acquisitions in the future also 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.
We face numerous uncertainties in estimating our recoverable coal reserves, and inaccuracies in our estimates could result in decreased profitability from lower than expected revenues or higher than expected costs.
      Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our estimates of reserve information on engineering, economic and geological data assembled and analyzed by our internal engineers and which is periodically reviewed by third-party consultants. There are numerous uncertainties inherent in estimating the quantities and qualities of, and costs to mine, recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and

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assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:
  •  future coal prices, operating costs, capital expenditures, severance and excise taxes, royalties and development and reclamation costs;
 
  •  future mining technology improvements;
 
  •  the effects of regulation by governmental agencies; and
 
  •  geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experiences in areas we currently mine. As a result, actual coal tonnage recovered from identified reserve areas or properties, and costs associated with our mining operations, may vary from estimates. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.
Defects in title of any leasehold interests in our properties could limit our ability to mine these properties or result in significant unanticipated costs.
      We conduct a significant part of our mining operations on properties that we lease. Title to most of our leased properties and mineral rights is not thoroughly verified until a permit to mine the property is obtained, and in some cases title with respect to leased properties is not verified at all. Our right to mine some of our reserves may be materially adversely affected by defects in title or boundaries. In order to obtain leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs, which could adversely affect our profitability.
Mining in Central and Northern Appalachia is more complex and involves more regulatory constraints than mining in other areas of the United States, which could affect our mining operations and cost structures in these areas.
      The geological characteristics of Central and Northern Appalachian coal reserves, such as depth of overburden and coal seam thickness, make them complex 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, as compared to mines in other regions, permitting, licensing and other environmental and regulatory requirements 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 in Central and Northern Appalachia.
Our work force could become increasingly unionized in the future, which could adversely affect the stability of our production and reduce our profitability.
      Approximately 95% of our 2005 coal production came from mines operated by union-free employees. As of December 31, 2005, over 92% of our subsidiaries’ approximately 3,309 employees are union-free. However, our subsidiaries’ employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. Any further unionization of our subsidiaries’ employees, or the employees of third-party contractors who mine coal for us, could adversely affect the stability of our production and reduce our profitability.
Our unionized work force could strike in the future, which could disrupt production and shipments of our coal and increase costs.
      One of our subsidiaries has two negotiated wage agreements with the United Mine Workers of America (“UMWA”). These agreements, covering approximately 252 employees as of December 31, 2005, expire on December 31, 2009. Two of our other subsidiaries have negotiated wage agreements with the UMWA covering an aggregate of 30 employees as of December 31, 2005 that will expire in December 2006. Some or all of the affected employees at each location could strike, which would adversely affect our productivity, increase our costs, and disrupt shipments of coal to our customers.

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Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.
      Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. During 2005, we had $25,000 of bad debt expense. Our customer base is changing with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear on payment default. These new power plant owners may have credit ratings that are below investment grade. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default.
      We have contracts to supply coal to energy trading and brokering companies under which those companies sell coal to end users. If the creditworthiness of the energy trading and brokering companies declines, this would increase the risk that we may not be able to collect payment for all coal sold and delivered to or on behalf of these energy trading and brokering companies.
The government extensively regulates our mining operations, which imposes significant costs on us, and future regulations could increase those costs or limit our ability to produce and sell coal.
      The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to matters such as:
  •  employee health and safety;
 
  •  mandated benefits for retired coal miners;
 
  •  mine permitting and licensing requirements;
 
  •  reclamation and restoration of mining properties after mining is completed;
 
  •  air quality standards;
 
  •  water pollution;
 
  •  plant and wildlife protection;
 
  •  the discharge of materials into the environment;
 
  •  surface subsidence from underground mining; and
 
  •  the effects of mining on groundwater quality and availability.
      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. Failure to comply with these regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we are pursued for these sanctions, costs and liabilities, our mining operations and, as a result, our profitability could be adversely affected.
      The possibility exists that new legislation and/or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. For example, in reaction to the recent mine tragedies in West Virginia, additional regulatory scrutiny and legislative activities targeting mine safety at both the state and federal levels have occurred, and compliance with any new resulting mine health and safety regulations could increase our mining costs. New legislation or administrative regulations (or new judicial interpretations or administrative enforcement of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. These regulations, if proposed and enacted in the future, could have a material adverse effect on our financial condition and results of operations.

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Extensive environmental regulations affect our customers and could reduce the demand for coal as a fuel source and cause our sales to decline.
      The Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. Such regulations will require significant emissions control expenditures for many coal-fired power plants to comply with applicable ambient air quality standards. As a result, these generators may switch to other fuels that generate less of these emissions or install more effective pollution control equipment, possibly reducing future demand for coal and the construction of coal-fired power plants.
      Various new and proposed laws and regulations may require further reductions in emissions from coal-fired utilities. For example, under the new Clean Air Interstate Rule issued on March 10, 2005, the EPA will further regulate sulfur dioxide and nitrogen oxides from coal-fired power plants. When fully implemented, this rule is expected to reduce sulfur dioxide emissions in affected states by over 70% and nitrogen oxides emissions by over 60% from 2003 levels. The stringency of this cap may require many coal-fired sources to install additional pollution control equipment, such as wet scrubbers, to comply. Installation of additional pollution control equipment required by this rule could result in a decrease in the demand for low sulfur coal (because sulfur would be removed by the new emissions control equipment), potentially driving down prices for low sulfur coal. In addition, under the Clean Air Act, coal-fired power plants will be required to control hazardous air pollution emissions by no later than 2009, which likely will require significant new investment in pollution-control devices by power plant operators. Further, on March 15, 2005, the EPA finalized the Clean Air Mercury Rule intended to control mercury emissions from power plants, which could require coal-fired power plants to install new pollution controls or comply with a mandatory, declining cap on the total mercury emissions allowed from coal-fired power plants nationwide. Both the Clean Air Mercury Rule and the Clean Air Interstate Rule are subject to administrative reconsideration and judicial challenge. These standards and future standards could have the effect of making coal-fired plants unprofitable, thereby decreasing demand for coal. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use.
      Several proposals are pending in Congress and various states that are designed to further reduce emissions of sulfur dioxide, nitrogen oxides and mercury from power plants, and certain ones could regulate additional air pollutants. If such initiatives are enacted into law, power plant operators could choose fuel sources other than coal to meet their requirements, thereby reducing the demand for coal. Current and possible future governmental programs are or may be in place to require the purchase and trading of allowances associated with the emission of various substances such as sulfur dioxide, nitrous oxide, mercury and carbon dioxide. Changes in the markets for and prices of allowances could have a material effect on demand for and prices received for our coal.
      A regional haze program initiated by the EPA to protect and to improve visibility at and around national parks, national wilderness areas and international parks restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas, and may require some existing coal-fired power plants, and certain thermal dryers, to install additional control measures designed to limit haze-causing emissions.
      One major by-product of burning coal is carbon dioxide, which is considered a greenhouse gas and is a major source of concern with respect to global warming. In November 2004, Russia ratified the Kyoto Protocol to the 1992 Framework Convention on Global Climate Change (the “Protocol”), which establishes a binding set of emission targets for greenhouse gases. With Russia’s accedence, the Protocol now has sufficient support and became binding on all those countries that have ratified it on February 16, 2005. Four industrialized nations have refused to ratify the Protocol — Australia, Liechtenstein, Monaco, and the United States. Although the targets vary from country to country, if the United States were to ratify the Protocol, our nation would be required to reduce greenhouse gas emissions to 93% of 1990 levels in a series of phased reductions from 2008 to 2012. Canada, which accounted for approximately 7% of our 2005 sales volume,

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ratified the Protocol in 2002. Under the Protocol, Canada will be required to cut greenhouse gas emissions to 6% below 1990 levels in a series of phased reductions from 2008 to 2012, either in direct reductions in emissions or by obtaining credits through the Protocol’s market mechanisms. This could result in reduced demand for coal by Canadian electric power generators.
      Future regulation of greenhouse gases in the United States could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act, or otherwise. The Bush Administration has proposed a package of voluntary emission reductions for greenhouse gases reduction targets which provide for certain incentives if targets are met. Some states, such as Massachusetts, have already issued regulations regulating greenhouse gas emissions from large power plants. Further, in 2002, the Conference of New England Governors and Eastern Canadian Premiers adopted a Climate Change Action Plan, calling for reduction in regional greenhouse emissions to 1990 levels by 2010, and a further reduction of at least 10% below 1990 levels by 2020. Increased efforts to control greenhouse gas emissions, including the future ratification of the Protocol by the United States, could result in reduced demand for our coal. See “Environmental and Other Regulatory Matters.”
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.
      Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Our Predecessor and acquired companies also utilized certain hazardous materials and generated similar wastes. We may be subject to claims under federal and state statutes and/or common law doctrines for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of current or former conditions at sites that we own or operate currently, as well as at sites that we or our Predecessor and acquired companies owned or operated in the past, and at contaminated sites that have always been owned or operated by third parties. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share. We have not been subject to claims arising out of contamination at our facilities, and are not aware of any such contamination, but may incur such liabilities in the future.
      We maintain extensive coal slurry impoundments at a number of our mines. Such impoundments are subject to extensive regulation. Slurry impoundments maintained by other coal mining operations have been known to fail, releasing large volumes of coal slurry. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as streams or bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.
      These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect us.
We may be unable to obtain and renew permits necessary for our operations, which would reduce our production, cash flow and profitability.
      Mining companies must obtain numerous permits that impose strict regulations on various environmental and safety matters in connection with coal mining. These include permits issued by various federal and state agencies and regulatory bodies. The permitting rules are complex and may change over time, making our ability to comply with the applicable requirements more difficult or even impossible, thereby precluding continuing or future mining operations. Private individuals and the public have certain rights to comment upon, submit objections to, and otherwise engage in the permitting process, including through court intervention. Accordingly, the permits we need 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 conduct our

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mining operations. An inability to conduct our mining operations pursuant to applicable permits would reduce our production, cash flow, and profitability.
      Permits under Section 404 of the Clean Water Act are required for coal companies to conduct dredging or filling activities in jurisdictional waters for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. The Army Corps of Engineers (the “COE”) is empowered to issue “nationwide” permits for specific categories of filling activity that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404. Nationwide Permit 21 authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. On October 23, 2003, several citizens groups sued the COE in the U.S. District Court for the Southern District of West Virginia seeking to invalidate “nationwide” permits utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. Although the lower court enjoined the issuance of Nationwide 21 permits, that decision was overturned by the Fourth Circuit Court of Appeals, which concluded that the COE complied with the Clean Water Act in promulgating this permit. Although we had no operations that were immediately impacted or interrupted, the lower court’s decision required us to convert certain current and planned applications for Nationwide 21 permits to applications for individual permits. A similar lawsuit was filed on January 27, 2005 in the U.S. District Court for the Eastern District of Kentucky and remains pending, and other lawsuits may be filed in other states where we operate. Although it is not possible to predict the results of the Kentucky litigation, it could adversely affect our Kentucky operations.
We may not be able to implement required public-company internal controls over financial reporting in the required time frame or with adequate compliance, and implementation of the controls will increase our costs.
      Our current operations consist primarily of the assets of our Predecessor and the other operations we have acquired, each of which had different historical operating, financial, accounting and other systems. Due to our rapid growth and limited history operating our acquired operations as an integrated business, our internal control over financial reporting may not currently meet all the standards contemplated by Section 404 of the Sarbanes-Oxley Act that we will be required to meet as of December 31, 2006. Several areas of deficiency in our internal control over financial reporting have been identified in the past, including such items as documentation of controls and procedures; segregation of duties; timely reconciliation of accounts; methods of reconciling fixed asset accounts, the structure of our general ledger and the level of experience of our accounting and finance staff related to public company reporting. The following additional deficiencies were identified by our evaluation of our internal control systems and through the audit of our financial statements as of and for the year ended December 31, 2005: inconsistent practices in applying our accounting procedures, insufficient second reviews, insufficient verification and updating of data used in our accounting procedures, and inadequate controls over information technology such as access to data and changes to software. Many improvements in these and other areas have been implemented, although our evaluation of our internal control systems is on-going, as are our efforts to further enhance these systems. Certain of these deficiencies have previously resulted in out-of-period adjustments to our financial statements. Although we have determined that such adjustments have been immaterial and several improvements have been made to the related accounting processes, continued deficiencies in our internal control over financial reporting may result in future out-of-period adjustments, which could be material and require us to restate our financial statements. If we are not able to successfully meet the requirements of Section 404 in a timely manner or with adequate compliance, our independent auditors may not be able to attest as to the adequacy of our internal controls over financial reporting. This result may subject us to adverse regulatory consequences, and there could also be a negative reaction in the financial markets due to a loss of confidence in the reliability of our financial statements. We could also suffer a loss of confidence in the reliability of our financial statements if our auditors were to report a material weakness in our internal controls. We have incurred, and will continue to incur, incremental costs in order to comply with Section 404, including increased consulting, auditing and legal fees and costs associated with hiring additional accounting and administrative staff with experience managing public companies.

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Our ability to operate our company effectively could be impaired if we fail to attract and retain key personnel.
      Our ability to operate our business and implement our strategies depends, in part, on the efforts of our executive officers and other key employees. In addition, our future success will depend on, among other factors, our ability to attract and retain other qualified personnel. The successful integration of the Nicewonder Coal Group also requires us to, among other things, retain key employees. Our future performance depends, in part, on our ability to successfully integrate these new employees into our company. The loss of the services of any of our executive officers or other key employees or the inability to attract or retain other qualified personnel in the future could have a material adverse effect on our business or business prospects.
      Certain of our subsidiaries have entered into employment agreements with three of our executive officers — Michael J. Quillen, our President and Chief Executive Officer, and D. Scott Kroh and Kevin S. Crutchfield, our Executive Vice Presidents. Each of our other executive officers are employed on an at-will basis. The current terms of the employment agreements between Messrs. Quillen, Kroh and Crutchfield and our subsidiaries end on December 31, 2006, with respect to Messrs. Quillen and Crutchfield, and March 11, 2007, in the case of Mr. Kroh, with automatic renewals for successive one year terms unless the executive or our employing subsidiary provides advance notice of non-renewal. When the terms of these agreements expire, we may not be able to renew or extend these employment agreements on terms acceptable to us. In addition, the employment agreements with Mr. Quillen and Mr. Crutchfield provide that if either executive resigns for “good reason” (as defined in the applicable agreement) or our employing subsidiary terminates either executive without “employer cause” (as defined in the applicable agreement), the vesting of all stock options, restricted stock and other equity rights of the employee awarded after the date of his employment agreement will be fully accelerated, and we will be required to pay the executive his earned but unpaid salary through the date of termination, any bonuses payable for prior years, the pro rata portion of his bonus payable for the current year, and an amount equal to 200% of his then current base salary and target annual bonus in installments over the following twenty-four months in the case of Mr. Quillen or 150% his then current base salary and target annual bonus in installments over the following twelve months in the case of Mr. Crutchfield, except that if the resignation by executive for good cause or termination by our employing subsidiary without employer cause occurs during the 90 days prior to or on or within one year after a “change in control” (as defined in the applicable agreement), then we will be required to pay the executive an amount equal to 300% (instead of 200%) of his then current base salary and target annual bonus in the case of Mr. Quillen, or 200% (instead of 150%) of his then current base salary and target annual bonus in the case of Mr. Crutchfield, and we will also be required to pay the executive an amount equal to the difference between the present value of his accrued benefits on the termination date under our defined benefit plans and supplemental retirement plan and the present value of benefits to which he would have been entitled had he continued to participate in such plans for an additional three years, in the case of Mr. Quillen, or two years, in the case of Mr. Crutchfield. The employment agreement with Mr. Kroh provides that if he resigns for “employee cause” (as defined in the applicable agreement), we will be required to pay him his earned but unpaid salary through the date of termination, and to continue to pay his then current base salary for the following twelve months, and he would be entitled to receive any bonuses payable for prior years, plus the pro rata bonus payable for the current year, at the same time as bonuses are paid to similarly situated employees. The employment agreement with Mr. Kroh provides that a resignation by him for “employee cause” includes, among other things, his resignation during the period beginning three months, and ending nine months following the liquidation or sale by First Reserve of more than 75% of its ownership in ANR Holdings and its affiliates, which liquidation or sale occurred pursuant to First Reserve’s sale of shares of our common stock in a secondary offering completed on January 24, 2006 pursuant to our registration statement on Form S-1 (file no. 333-129030).
A shortage of skilled labor in the Appalachian region could pose a risk to achieving improved 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 a year of experience and proficiency in multiple mining tasks. In recent years, a shortage of trained coal

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miners in the Appalachian region has caused us to operate certain units without full staff, which decreases our productivity and increases our costs. For example, during the year of 2005, production at our contractor operations was running approximately 25% behind plan, primarily due to shortages in the supply of labor. 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.
Our significant indebtedness could harm our business by limiting our available cash and our access to additional capital and could force us to sell material assets or take other actions to attempt to reduce our indebtedness.
      We are a highly leveraged company. Our financial performance could be affected by our significant indebtedness. At December 31, 2005, we had approximately $486.0 million of indebtedness outstanding, representing 70% of our total capitalization. This indebtedness consisted of $175.0 million principal of our 10% senior notes due 2012, a $250.0 million term loan under new credit facility and $60.8 million of other indebtedness, including the second installment of the Nicewonder Coal Group acquisition note of $39.9 million, $1.5 million of capital lease obligations extending through March 2009, $0.3 million principal amount in variable rate term notes maturing in April 2006 that we incurred in connection with equipment financing and $19.1 million payable to an insurance premium finance company. In addition, under our credit facility we had $65.5 million of letters of credit outstanding at December 31, 2005.
      In connection with the Nicewonder Acquisition, we refinanced all outstanding indebtedness under our prior credit facility with a new credit facility, which provides for up to $525.0 million of borrowings, including a $275.0 million revolving credit facility and a $250.0 million term loan. In addition, under the terms of the Nicewonder Acquisition, one of our indirect, wholly-owned subsidiaries issued $221.0 million in promissory installment notes, payable in two installments of which $181.1 million was paid on November 2, 2005 and $39.9 million was paid on January 13, 2006. We may also incur additional indebtedness in the future.
      This level of indebtedness could have important consequences to our business. For example, it could:
  •  increase our vulnerability to general adverse economic and industry conditions;
 
  •  make it more difficult to self-insure and obtain surety bonds or letters of credit;
 
  •  limit our ability to enter into new long-term sales contracts;
 
  •  make it more difficult for us to pay interest and satisfy our debt obligations, including our obligations with respect to the notes;
 
  •  require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions and other general corporate activities;
 
  •  limit our ability to obtain additional financing to fund future working capital, capital expenditures, research and development, debt service requirements or other general corporate requirements;
 
  •  limit our flexibility in planning for, or reacting to, changes in our business and in the coal industry;
 
  •  place us at a competitive disadvantage compared to less leveraged competitors; and
 
  •  limit our ability to borrow additional funds.
      If our cash flows and capital resources are insufficient to fund our debt service obligations or our requirements under our other long-term liabilities, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations, including our obligations with respect to the notes, or our requirements under our other long term liabilities. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our new credit facility and the indenture

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under which our senior notes were issued restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due. Furthermore, substantially all of our material assets secure our indebtedness under our new credit facility.
Despite our current leverage, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our significant indebtedness.
      We may be able to incur substantial additional indebtedness in the future. The terms of our new credit facility and the indenture governing our senior notes do not prohibit us from doing so. Our new credit facility provides for a revolving line of credit of up to $275.0 million, of which $209.5 million was available as of December 31, 2005. The addition of new debt to our current debt levels could increase the related risks that we now face. For example, the spread over the variable interest rate applicable to loans under our credit facility is dependent on our leverage ratio, and it would increase if our leverage ratio increases. Additional drawings under our revolving line of credit could also limit the amount available for letters of credit in support of our bonding obligations, which we will require as we develop and acquire new mines.
The covenants in our credit facility and the indenture governing the notes impose restrictions that may limit our operating and financial flexibility.
      Our new credit facility and the indenture governing our senior notes contain a number of significant restrictions and covenants that limit our ability and our subsidiaries’ ability to, among other things, incur additional indebtedness or enter into sale and leaseback transactions, pay dividends, make redemptions and repurchases of certain capital stock, make loans and investments, create liens, engage in transactions with affiliates and merge or consolidate with other companies or sell substantially all of our assets.
      These covenants could adversely affect our ability to finance our future operations or capital needs or to execute preferred business strategies. In addition, if we violate these covenants and are unable to obtain waivers from our lenders, our debt under these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able repay our debt or borrow sufficient funds to refinance it. Even if we were able to obtain new financing, it may not be on commercially reasonable terms, on terms that are acceptable to us, or at all. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected.
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal.
      Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations. These bonds are typically renewable annually. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral or other less favorable terms upon those renewals. The ability of surety bond issuers and holders to demand additional collateral or other less favorable terms has increased as the number of companies willing to issue these bonds has decreased over time. Our failure to maintain, or our inability to acquire, surety bonds that are required by state and federal law would affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal. That failure could result from a variety of factors including, without limitation:
  •  lack of availability, higher expense or unfavorable market terms of new bonds;
 
  •  restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our credit facility or the indenture governing our senior notes; and
 
  •  the exercise by third-party surety bond issuers of their right to refuse to renew the surety.
                  Failure to maintain capacity for required letters of credit could limit our available borrowing capacity under our credit facility, limit our ability to obtain or renew surety bonds and negatively impact our

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ability to obtain additional financing to fund future working capital, capital expenditure or other general corporate requirements.
      At December 31, 2005, we had $65.5 million of letters of credit in place, of which $58.3 million served as collateral for reclamation surety bonds and $7.2 million secured miscellaneous obligations. Our new credit facility provides for revolving commitments of up to $275.0 million, all of which can be used to issue additional letters of credit. In addition, obligations secured by letters of credit may increase in the future. Any such increase would limit our available borrowing capacity under our current or future credit facilities and could negatively impact our ability to obtain additional financing to fund future working capital, capital expenditure or other general corporate requirements. Moreover, if we do not maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our mining operations.
If our assumptions regarding our likely future expenses related to benefits for non-active employees are incorrect, then expenditures for these benefits could be materially higher than we have predicted.
      At the times that we acquired the assets of our Predecessor and acquired companies, the Predecessor and acquired operations were subject to long-term liabilities under a variety of benefit plans and other arrangements with active and inactive employees. We assumed a portion of these long-term obligations and are continuing to incur additional costs from our operations for postretirement, workers’ compensation and black lung liabilities. The current and non-current accrued portions of these long-term obligations, as reflected in our consolidated financial statements as of December 31, 2005, included $24.5 million of postretirement medical obligations and $6.9 million of self-insured workers’ compensation and black lung obligations, and our accumulated postretirement benefit obligation at December 31, 2005 is $49.5 million. These obligations have been estimated based on assumptions that are described in the notes to our consolidated financial statements included elsewhere in this annual report. However, if our assumptions are incorrect, we could be required to expend greater amounts than anticipated.
      Several states in which we operate consider changes in workers’ compensation laws from time to time, which, if enacted, could adversely affect us. In addition, if any of the sellers from whom we acquired our operations fail to satisfy their indemnification obligations to us with respect to postretirement claims and retained liabilities, then we could be required to expend greater amounts than anticipated. See “— The inability of the sellers of our Predecessor and acquired companies to fulfill their indemnification obligations to us under our acquisition agreements could increase our liabilities and adversely affect our results of operations.” Moreover, under certain acquisition agreements, we agreed to permit responsibility for black lung claims related to the sellers’ former employees who are employed by us for less than one year after the acquisition to be determined in accordance with law (rather than specifically assigned to one party or the other in the agreements). We believe that the sellers remain liable as a matter of law for black lung benefits for their former employees who work for us for less than one year; however, an adverse ruling on this issue could increase our exposure to black lung benefit liabilities.
Demand for our coal changes seasonally and could have an adverse effect on the timing of our cash flows and our ability to service our existing and future indebtedness.
      Our business is seasonal, with operating results varying from quarter to quarter. We have historically experienced lower sales during winter months primarily due to the freezing of lakes that we use to transport coal to some of our customers. As a result, our first quarter cash flow and profits have been, and may continue to be, negatively impacted. Lower than expected sales by us during this period could have a material adverse effect on the timing of our cash flows and therefore our ability to service our obligations with respect to our existing and future indebtedness.

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Our earnings will be reduced in future periods as a result of our issuance of shares of our common stock to members of management as part of the Internal Restructuring.
      As part of the Internal Restructuring, our executive officers and certain other key employees exchanged their interests in ANR Holdings for shares of our common stock and the right to participate in a distribution of the proceeds received by us from the underwriters as a result of the underwriters’ exercise of their over-allotment option in connection with the IPO. As a result, we recorded stock-based compensation expense equal to the fair value of the vested shares issued and distributions paid in the amount of $45.8 million for 2005. In addition, as a result of the conversion of outstanding options held by members of our management to purchase units of Alpha Coal Management into options to purchase up to 596,985 shares of our common stock in connection with the Internal Restructuring (the “ACM Converted Options”), we recorded stock-based compensation of $0.7 million for 2005. The aggregate amount of stock-based compensation expense we recorded in 2005 was $46.5 million, equal to the $45.8 million of expense associated with distributions paid and the vested portions of shares issued in the Internal Restructuring and amortization expense from the unvested portions of shares issued in the Internal Restructuring, and $0.7 million of amortization expense from the ACM Converted Options. In addition, we had deferred stock-based compensation at December 31, 2005 of $15.6 million, consisting primarily of $12.8 million and $2.6 million associated with the unvested portions of shares issued in the Internal Restructuring and the ACM Converted Options, respectively, that we will record as non-cash stock-based compensation expense over the remaining term of the applicable two-year and five-year vesting periods, respectively. The amortization of the deferred stock-based compensation relating to the unvested shares issued in the Internal Restructuring and the ACM converted options over the applicable two-year and five- year vesting periods will result in a non-cash amortization expense in these periods, thereby reducing our earnings in those periods.
The AMCI Parties may have significant influence on our company and may have conflicts of interest with us or you in the future.
      Persons affiliated with AMCI (the “AMCI Parties”) beneficially owned approximately 17.62% of our common stock as of February 28, 2006. The AMCI Parties are in the business of making investments in companies and they may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. For example, the AMCI Parties held a combined 3.3% ownership interest in Foundation Coal Holdings, Inc. (“Foundation”) as of December 31, 2005. These other investments may create competing financial demands on the AMCI Parties, potential conflicts of interest and require efforts consistent with applicable law to keep the other businesses separate from our operations. The AMCI Parties may also pursue acquisition opportunities that may be complementary to our business, and as a result, those acquisition opportunities may not be available to us. Additionally, our amended and restated certificate of incorporation provides that the AMCI Parties may compete with us. The designees of the persons affiliated with AMCI on our board of directors will not be required to offer corporate opportunities to us and may take any such opportunities for themselves, other than any opportunities offered to the designees solely in their capacity as one of our directors. So long as the AMCI Parties continue to own a significant amount of our equity, even if such amount is less than 50%, they will continue to be able to strongly influence or effectively control our decisions. For example, the AMCI Parties could cause us to make acquisitions that increase our amount of indebtedness or sell revenue-generating assets.
Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations.
      Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition, and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may materially adversely affect our operations and those of our customers. As a result, there could be delays or losses in transportation and

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deliveries of coal to our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
Item 2. Properties
Coal Reserves
      We estimate that, as of December 31, 2005, we had total proven and probable reserves of approximately 489.5 million tons. We believe that our total proven and probable reserves will support current production levels for more than 20 years. “Reserves” are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. “Proven (Measured) Reserves” are defined by SEC Industry Guide 7 as reserves for which (1) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (2) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. “Probable reserves” are defined by SEC Industry Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.
      Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our internal engineers, geologists and finance associates. We periodically update our reserve estimates to reflect past coal production, new drilling information and other geological or mining data, and acquisitions or sales of coal properties. Coal tonnages are categorized according to coal quality, mining method, permit status, mineability and location relative to existing mines and infrastructure. In accordance with applicable industry standards, proven reserves are those for which reliable data points are spaced no more than 2,700 feet apart. Probable reserves are those for which reliable data points are spaced 2,700 feet to 7,900 feet apart. Further scrutiny is applied using geological criteria and other factors related to profitable extraction of the coal. These criteria include seam height, roof and floor conditions, yield and marketability.
      We periodically retain outside experts to independently verify our estimates of our coal reserves. The most recent of these reviews for our operations other than the Callaway reserves was completed in November 2004, and we obtained an independent third party review of the Callaway reserves that was completed in September 2005. These reviews included the preparation of reserve maps and the development of estimates by certified professional geologists based on data supplied by us and using standards accepted by government and industry, including the methodology outlined in U.S. Geological Survey Circular 891. Reserve estimates were developed using criteria to assure that the basic geologic characteristics of the reserves (such as minimum coal thickness and wash recovery, interval between deep mineable seams and mineable area tonnage for economic extraction) were in reasonable conformity with existing and recently completed mine operation capabilities on our various properties. As a result of the November 2004 review, we increased our reserve estimate from 326.5 million tons as of January 1, 2004 to 514.5 million tons as of October 15, 2004.
      As with most coal-producing companies in Appalachia, the great majority of our coal reserves are subject to leases from third-party landowners. These leases convey mining rights to the coal producer in exchange for a percentage of gross sales in the form of a royalty payment to the lessor, subject to minimum payments. A small portion of our reserve holdings are owned and require no royalty or per-ton payment to other parties. The average royalties paid by us for coal reserves from our producing properties was $3.02 per ton in 2005, representing 4.1% of our 2005 coal sales revenue.

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      Although our coal leases have varying renewal terms and conditions, they generally last for the economic life of the reserves. According to our current mine plans, any leased reserves assigned to a currently active operation will be mined during the tenure of the applicable lease. Because the great majority of our leased or owned properties and mineral rights are covered by detailed title abstracts prepared when the respective properties were acquired by predecessors in title to us and our current lessors, we generally do not thoroughly verify title to, or maintain title insurance policies on, our leased or owned properties and mineral rights.
      The following table provides the “quality” (sulfur content and average Btu content per pound) of our coal reserves as of December 31, 2005.
                                                         
        Recoverable   Sulfur Content   Average Btu
        Reserves Proven &        
Regional Business Unit   State   Probable(1)   <1%   1.0%-1.5%   >1.5%   >12,500   <12,500
                             
        (In millions of tons)        
            (In millions of tons)   (In millions of tons)
Paramont/ Alpha Land and Reserves(2)
    Virginia       153.3       110.1       31.4       11.8       150.7       2.6  
Dickenson-Russell
    Virginia       30.9       30.9       0       0       30.9       0  
Kingwood
    West Virginia       29.2       0       17.7       11.6       29.2       0  
Brooks Run
    West Virginia       25.4       7.1       18.3       0       10.5       14.9  
Welch
    West Virginia       96.4       96.4       0       0       96.4       0  
AMFIRE
    Pennsylvania       65.5       14.7       21.8       29.0       56.9       8.6  
Enterprise
    Kentucky       63.7       24.8       37.2       1.6       62.3       1.4  
Callaway
  West Virginia and Virginia     25.1       25.1       0       0       10.9       14.2  
                                           
Totals
            489.5       309.1       126.4       54.0       447.8       41.7  
Percentages
                    63 %     26 %     11 %     92 %     8 %
 
(1)  Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law. The reserve numbers set forth in the table exclude reserves for which we have leased our mining rights to third parties. Reserve information reflects a moisture factor of 6.5%. This moisture factor represents the average moisture present on our delivered coal.
 
(2)  Includes proven and probable reserves in Virginia controlled by our subsidiary Alpha Land and Reserves, LLC as of December 31, 2005. Alpha Land and Reserves, LLC subleases a portion of the mining rights to its proven and probable reserves in Virginia to our subsidiary Paramont Coal Company Virginia, LLC.

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      The following table summarizes, by regional business unit, the tonnage of our coal reserves that is assigned to our operating mines, our property interest in those reserves and whether the reserves consist of steam or metallurgical coal, as of December 31, 2005.
                                                     
        Recoverable   Total Tons   Total Tons    
        Reserves Proven &            
Regional Business Unit   State   Probable(1)   Assigned(2)   Unassigned(2)   Owned   Leased   Coal Type(3)
                             
        (In millions of tons)            
            (In millions of tons)   (In millions of    
                tons)    
Paramont/ Alpha Land and Reserves(4)
    Virginia       153.3       71.0       82.3       0       153.3     Steam and Metallurgical
Dickenson-Russell
    Virginia       30.9       28.7       2.2       0       30.9     Steam and Metallurgical
Kingwood
    West Virginia       29.2       20.8       8.4       0       29.2     Steam and Metallurgical
Brooks Run
    West Virginia       25.4       12.6       12.8       2.9       22.5     Steam and Metallurgical
Welch
    West Virginia       96.4       50.8       45.6       1.3       95.1     Steam and Metallurgical
AMFIRE
    Pennsylvania       65.5       62.4       3.1       3.4       62.1     Steam and Metallurgical
Enterprise
    Kentucky       63.7       10.8       52.9       7.1       56.6     Steam
Callaway
  West Virginia and Virginia     25.1       22.9       2.2       1.1       24.0     Steam and Metallurgical
                                         
Totals
            489.5       280.0       209.5       15.8       473.7      
Percentages
                    57 %     43 %     3 %     97 %    
 
(1)  Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law. The reserve numbers set forth in the table exclude reserves for which we have leased our mining rights to third parties. Reserve information reflects a moisture factor of 6.5%. This moisture factor represents the average moisture present on our delivered coal.
 
(2)  Assigned reserves represent recoverable coal reserves that can be mined without a significant capital expenditure for mine development, whereas unassigned reserves will require significant capital expenditures to mine the reserves.
 
(3)  Almost all of our reserves that we currently market as metallurgical coal also possess quality characteristics that would enable us to market them as steam coal.
 
(4)  Includes proven and probable reserves in Virginia controlled by our subsidiary Alpha Land and Reserves, LLC as of December 31, 2005. Alpha Land and Reserves, LLC subleases a portion of the mining rights to its proven and probable reserves in Virginia to our subsidiary Paramont Coal Company Virginia, LLC.

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      The following map shows the locations of Alpha’s properties, including the number of mines and preparation plants as of February 1, 2006 and 2005 production of saleable tons for each of our eight regional business units:
(MAP OF APPALACHIAN COALFIELD)
      See Item 1. Business, of this report for additional information regarding our coal operations and properties.

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Item 3. Legal Proceedings
      General. The Company is a party to a number of legal proceedings incident to their normal business activities. While we cannot predict the outcome of these proceedings, we do not believe that any liability arising from these matters individually or in the aggregate should have a material impact upon the consolidated cash flows, results of operations or financial condition of the Company.
      Nicewonder Litigation. The Affiliated Construction Trades Foundation brought an action against Nicewonder Contracting, Inc. (“NCI”) and the West Virginia Department of Transportation, Division of Highways in the United States District Court in the Southern District of West Virginia. (The Affiliated Construction Trades Foundation v. West Virginia Department of Transportation and Nicewonder Contracting Inc., (SDWV CA No. 2:04-1344)). The plaintiff seeks a declaration that the contract between NCI and the State of West Virginia related to NCI’s road construction project is illegal as a violation of applicable West Virginia and federal competitive bidding and prevailing wage laws. The plaintiff also is seeking an injunction prohibiting performance of the contract but has not sought monetary damages. The sellers in the Nicewonder Acquisition have agreed to indemnify us for any losses we may incur as a result of this litigation, net of the net revenues of NCI from post-acquisition coal sales and the value of certain reserves, surface property and mining equipment of NCI.
Item 4. Submission of Matters to a Vote of Security Holders
      There were no matters submitted to a vote of security holders of Alpha Natural Resources, Inc. through a solicitation of proxies or otherwise during the fourth quarter of the Company’s fiscal year ended December 31, 2005.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
      The initial public offering of our common stock commenced on February 15, 2005. The Company’s common stock has been listed on the New York Stock Exchange since that time under the symbol “ANR.” There was no public market for our common stock prior to this date.
Price range of our common stock
      Trading in our common stock commenced on the New York Stock Exchange on February 15, 2005 under the symbol “ANR”. The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock reported in the New York Stock Exchange consolidated tape.
                 
2005   High   Low
         
First Quarter
  $ 30.50     $ 21.65  
Second Quarter
    29.50       22.00  
Third Quarter
    32.73       23.83  
Fourth Quarter
    30.47       18.70  
      As of March 15, 2006, there were approximately 44 registered holders of record of our common stock. The transfer agent and registrar for our common stock is Computershare Trust Company, N.A.
Dividend Policy
      We do not presently pay dividends on our common stock. We expect to consider a policy of paying quarterly dividends beginning sometime in 2006 to the holders of our common stock. If adopted, we would expect our board to commence and continue this dividend policy for the foreseeable future subject to (1) our results of operations and the amount of our surplus available to be distributed, (2) dividend availability and

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restrictions under our credit facility and indenture, (3) the dividend rate being paid by comparable companies in the coal industry, (4) our liquidity needs and financial condition, (5) the level of cash investments we may make in connection with potential future acquisitions and (6) other factors that our board of directors may deem relevant. The terms of our new credit facility and the indenture governing our senior notes restrict our ability to pay dividends to our stockholders. See Item 1A “Risk Factors — Our ability to pay regular dividends to our stockholders is subject to the discretion of our board of directors and may be limited by our holding company structure, the covenants in our debt instruments and applicable provisions of Delaware law,” and “Risk Factors — The covenants in our credit facility and the indenture governing our senior notes impose restrictions that may limit our operating and financial flexibility.”
Equity Compensation Plan Information
                         
            (c) Number of securities
        (b) Weighted-   remaining available for
    (a) Number of   average exercise   future issuance under
    securities to be issued   price of   equity compensation
    upon exercise of   outstanding   plans (excluding
    outstanding options,   options, warrants   securities reflected in
Plan Category   warrants and rights   and rights   column (a))
             
Equity compensation plans approved by security holders
    1,265,593     $ 16.71       2,654,632 (1)
Equity compensation plans not approved by security holders
                 
                   
Total
    1,265,593     $ 16.71       2,654,632  
 
(1)  The Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan has 2,654,632 shares of common stock available for future issuance to qualified participants as of December 31, 2005 (refer to column (c)).
Item 6. Selected Financial Data
      The following table presents selected financial and other data about us and our Predecessor for the most recent five fiscal periods. The selected financial data as of December 31, 2005 and for the year then ended have been derived from the audited consolidated financial statements and related notes of Alpha Natural Resources, Inc. and subsidiaries included in this annual report. The selected historical financial data as of December 31, 2004, 2003, and for the period from December 14, 2002 to December 31, 2002 and for the years ended December 31, 2004 and 2003 have been derived from the combined financial statements of ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. and subsidiaries (the owners of a majority of the membership interests of ANR Holdings prior to the Internal Restructuring) and the related notes, included elsewhere in this annual report, which have been audited by KPMG LLP (“KPMG”), an independent registered public accounting firm. The selected historical financial data as of December 31, 2002 have been derived from the audited combined balance sheet of ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. and subsidiaries not included in this annual report. The selected historical financial data for the period from January 1, 2002 through December 13, 2002 (the “Predecessor Period”) have been derived from our Predecessor’s combined financial statements not included in this annual report, which have been audited by KPMG. The selected historical financial data as of December 31, 2001, and for the year ended December 31, 2001 have been derived from our Predecessor’s audited combined financial statements not included in this annual report. You should read the following table in conjunction with the financial statements, the related notes to those financial statements, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
      The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, see Item 1A “Risk Factors” of this report for a discussion of risk factors that could impact our future results of operations.

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    Alpha Natural   ANR Fund IX Holdings, L.P. and Alpha NR    
    Resources, Inc.   Holding, Inc. and Subsidiaries   Predecessor
             
            December 14,   January 1,    
    Year Ended   Year Ended   Year Ended   2002 to   2002 to   Year Ended
    December 31,   December 31,   December 31,   December 31,   December 13,   December 31,
    2005   2004   2003   2002   2002   2001
                         
    (In thousands, except per share amounts)
Statement of Operations Data:
                                               
Revenues:
                                               
 
Coal revenues
  $ 1,414,513     $ 1,079,733     $ 694,591     $ 6,260     $ 154,715     $ 227,237  
 
Freight and handling revenues
    185,555       141,100       73,800       1,009       17,001       25,808  
 
Other revenues
    27,267       31,869       13,458       101       6,031       8,472  
                                     
   
Total revenues
    1,627,335       1,252,702       781,849       7,370       177,747       261,517  
                                     
Costs and expenses:
                                               
 
Cost of coal sales (exclusive of items shown separately below)
    1,184,092       920,359       626,265       6,268       158,924       219,545  
 
Freight and handling costs
    185,555       141,100       73,800       1,009       17,001       25,808  
 
Cost of other revenues
    23,675       22,994       12,488       120       7,973       8,156  
 
Depreciation, depletion and amortization
    73,122       55,261       35,385       274       6,814       7,866  
 
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)
    88,812       43,881       21,926       471       8,797       9,370  
 
Costs to exit business
                            25,274       3,500  
                                     
   
Total costs and expenses
    1,555,256       1,183,595       769,864       8,142       224,783       274,245  
                                     
Refund of federal black lung excise tax
                            2,049       16,213  
Other operating income, net
                            1,430       94  
                                     
   
Income (loss) from operations
    72,079       69,107       11,985       (772 )     (43,557 )     3,579  
                                     
Other income (expense):
                                               
 
Interest expense
    (29,937 )     (20,041 )     (7,848 )     (203 )     (35 )      
 
Interest income
    1,064       531       103       6       2,072       1,993  
 
Miscellaneous income
    91       722       574                   1,250  
                                     
   
Total other income (expense), net
    (28,782 )     (18,788 )     (7,171 )     (197 )     2,037       3,243  
                                     
   
Income (loss) before income taxes and minority interest
    43,297       50,319       4,814       (969 )     (41,520 )     6,822  
Income tax expense (benefit)
    18,953       5,150       898       (334 )     (17,198 )     (1,497 )
Minority interest
    2,918       22,781       1,164                    
                                     
   
Income (loss) from continuing operations
    21,426       22,388       2,752       (635 )     (24,322 )     8,319  
Loss from discontinued operations
    (213 )     (2,373 )     (490 )                  
                                     
   
Net income (loss)
  $ 21,213     $ 20,015     $ 2,262     $ (635 )   $ (24,322 )   $ 8,319  
                                     

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    Alpha Natural   ANR Fund IX Holdings, L.P. and Alpha NR    
    Resources, Inc.   Holding, Inc. and Subsidiaries   Predecessor
             
            December 14,   January 1,    
    Year Ended   Year Ended   Year Ended   2002 to   2002 to   Year Ended
    December 31,   December 31,   December 31,   December 31,   December 13,   December 31,
    2005   2004   2003   2002   2002   2001
                         
    (In thousands, except per share amounts)
Earnings per share data:
                                               
 
Net income (loss) per share, as adjusted(1)
                                               
   
Basic and diluted:
                                               
     
Income from continuing operations
  $ 0.38     $ 1.52     $ 0.19                          
     
Loss from discontinued operations
          (0.16 )     (0.04 )                        
                                     
     
Net income per basic and diluted share
  $ 0.38     $ 1.36     $ 0.15                          
                                     
 
Pro forma net income (loss) per share(2) 
                                               
   
Basic and diluted:
                                               
     
Income from continuing operations
  $ 0.35     $ 0.25                                  
     
Loss from discontinued operations
          (0.07 )                                
                                     
     
Net income per basic and diluted share
  $ 0.35     $ 0.18                                  
                                     
Balance sheet data (at period end):
                                               
Cash and cash equivalents
  $ 39,622     $ 7,391     $ 11,246     $ 8,444     $ 88     $ 175  
Operating and working capital
    35,074       56,257       32,714       (12,223 )     (4,268 )     (22,958 )
Total assets
    1,013,658       477,121       379,336       108,442       156,328       139,467  
Notes payable and long-term debt, including current portion
    485,803       201,705       84,964       25,743              
Stockholders’ equity and partners’ capital (deficit)
    212,765       45,933       86,367       23,384       (132,997 )     (136,593 )
Statement of cash flows data:
                                               
Net cash provided by (used in):
                                               
 
Operating activities
  $ 149,643     $ 106,776     $ 54,104     $ (295 )   $ (13,816 )   $ 10,655  
 
Investing activities
    (339,387 )     (86,202 )     (100,072 )     (38,893 )     (22,054 )     (9,203 )
 
Financing activities
    221,975       (24,429 )     48,770       47,632       35,783       (1,462 )
Capital expenditures
    122,342       72,046       27,719       960       21,866       10,218  
Other financial data
                                               
 
EBITDA, as adjusted(3)
  $ 145,197     $ 119,327     $ 47,663     $ (498 )                
 
(1)  Basic earnings per share is computed by dividing net income or loss by the weighted average number of shares of common stock outstanding during the periods. Diluted earnings per share is computed by dividing net income or loss by the weighted average number of shares of common stock and dilutive common stock equivalents outstanding during the periods. Common stock equivalents include the number of shares issuable on exercise of outstanding options less the number of shares that could have been purchased with the proceeds from the exercise of the options based on the average price of common stock during the period. Due to the Internal Restructuring on February 11, 2005 and initial public offering of common stock completed on February 18, 2005, the calculation of earnings per share reflects certain adjustments, as described below.
  The numerator for purposes of computing basic and diluted net income (loss) per share, as adjusted, includes the reported net income (loss) and a pro forma adjustment for income taxes to reflect the pro forma income taxes for ANR Fund IX Holdings, L.P.’s portion of reported pre-tax income (loss), which would have been recorded if the issuance of the shares of common stock received by the FR Affiliates in exchange for their ownership in ANR Holdings in connection with the Internal Restructuring had occurred as of January 1, 2003. For purposes of the computation of basic and diluted net income (loss)

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  per share, as adjusted, the pro forma adjustment for income taxes only applies to the percentage interest owned by ANR Fund IX Holding, L.P., the non-taxable FR Affiliate. No pro forma adjustment for income taxes is required for the percentage interest owned by Alpha NR Holding, Inc., the taxable FR Affiliate, because income taxes have already been recorded in the historical results of operations. Furthermore, no pro forma adjustment to reported net income (loss) is necessary subsequent to February 11, 2005 because Alpha is subject to income taxes.
 
  The denominator for purposes of computing basic net income (loss) per share, as adjusted, reflects the retroactive impact of the common shares received by the FR Affiliates in exchange for their ownership in ANR Holdings in connection with the Internal Restructuring on a weighted-average outstanding share basis as being outstanding as of January 1, 2003. The common shares issued to the minority interest owners of ANR Holdings in connection with the Internal Restructuring, including the immediately vested shares granted to management, have been reflected as being outstanding as of February 11, 2005 for purposes of computing the basic net income (loss) per share, as adjusted. The unvested shares granted to management on February 11, 2005 that vest monthly over the two-year period from January 1, 2005 to December 31, 2006 are included in the basic net income (loss) per share, as adjusted, computation as they vest on a weighted-average outstanding share basis starting on February 11, 2005. The 33,925,000 new shares issued in connection with the initial public offering have been reflected as being outstanding since February 14, 2005, the date of the initial public offering, for purposes of computing the basic net income (loss) per share, as adjusted.
 
  The unvested shares issued to management are considered options for purposes of computing diluted net income (loss) per share, as adjusted. Therefore, for diluted purposes, all remaining unvested shares granted to management are added to the denominator subsequent to February 11, 2005 using the treasury stock method, if the effect is dilutive. In addition, the treasury stock method is used for outstanding stock options, if dilutive, beginning with the November 10, 2004 grant of options to management to purchase units in ACM that were automatically converted into options to purchase up to 596,985 shares of Alpha Natural Resources, Inc. common stock at an exercise price of $12.73 per share.

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  The computations of basic and diluted net income (loss) per share, as adjusted, are set forth below:
                           
    Year Ended December 31,
     
    2005   2004   2003
             
    (in thousands, except share and per share amounts)
Numerator:
                       
 
Reported income from continuing operations
  $ 21,426     $ 22,388     $ 2,752  
 
Deduct: Income tax effect of ANR Fund IX Holdings, L.P. income from continuing operations prior to Internal Restructuring
    (91 )     (1,149 )     (138 )
                   
 
Income from continuing operations, as adjusted
    21,335       21,239       2,614  
                   
 
Reported loss from discontinued operations
    (213 )     (2,373 )     (490 )
 
Add: Income tax effect of ANR Fund IX Holdings, L.P. loss from discontinued operations prior to Internal Restructuring
    2       149       27  
                   
 
Loss from discontinued operations, as adjusted
    (211 )     (2,224 )     (463 )
                   
 
Net income, as adjusted
  $ 21,124     $ 19,015     $ 2,151  
                   
Denominator:
                       
 
Weighted average shares — basic
    55,664,081       13,998,911       13,998,911  
 
Dilutive effect of stock options and restricted stock grants
    385,465              
                   
 
Weighted average shares — diluted
    56,049,546       13,998,911       13,998,911  
                   
Net income per share, as adjusted — basic and diluted:
                       
 
Income from continuing operations, as adjusted
  $ 0.38     $ 1.52     $ 0.19  
 
Loss from discontinued operations, as adjusted
          (0.16 )     (0.04 )
                   
 
Net income per share, as adjusted
  $ 0.38     $ 1.36     $ 0.15  
                   
(2)  Pro forma net income (loss) per share gives effect to the following transactions as if each of these transactions had occurred on January 1, 2004: the Nicewonder Acquisition and related debt refinancing in October 2005, the Internal Restructuring and initial public offering in February 2005, the issuance in May 2004 of $175.0 million principal amount of 10% senior notes due 2012, and the entry into a $175.0 million revolving credit facility in May 2004.
 
(3)  EBITDA, as adjusted, is defined as net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, less interest income, and adjusted for minority interest. EBITDA, as adjusted, is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because EBITDA, as adjusted, is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.
      EBITDA, as adjusted, is calculated as follows (unaudited, in thousands):
                                 
                December 14,
        2002 to
    Year Ended December 31,   December 31,
         
    2005   2004   2003   2002
                 
Net income (loss)
  $ 21,213     $ 20,015     $ 2,262     $ (635 )
Interest expense
    29,937       20,041       7,848       203  
Interest income
    (1,064 )     (531 )     (103 )     (6 )
Income tax expense (benefit)
    18,860       3,960       668       (334 )
Depreciation, depletion and amortization
    73,405       56,012       36,054       274  
                         
EBITDA
    142,351       99,497       46,729       (498 )
Minority interest
    2,846       19,830       934        
                         
EBITDA, as adjusted
  $ 145,197     $ 119,327     $ 47,663     $ (498 )
                         

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
      You should read the following discussion and analysis in conjunction with our financial statements and related notes and our “Selected Historical Financial Data” included elsewhere in this annual report. The historical financial information discussed below for periods prior to the completion of our Internal Restructuring on February 11, 2005, is for ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. and subsidiaries, which prior to the completion of our Internal Restructuring were the owners of a majority of the membership interests of ANR Holdings, our top-tier holding company, and for Alpha Natural Resources, Inc. and subsidiaries for periods from and after the completion of our Internal Restructuring.
Overview
      We produce, process and sell steam and metallurgical coal from eight regional business units, which, as of February 1, 2006, are supported by 44 active underground mines, 25 active surface mines and 11 preparation plants located throughout Virginia, West Virginia, Kentucky, and Pennsylvania, as well as a highway construction business in West Virginia that produces coal. We also sell coal produced by others, the majority of which we process and/or blend with coal produced from our mines prior to resale, providing us with a higher overall margin for the blended product than if we had sold the coals separately. Our sales of steam coal in 2005 and 2004 accounted for approximately 63% of our annual coal sales volume, and our sales of metallurgical coal in 2005 and 2004, which generally sells at a premium over steam coal, accounted for approximately 37% of our annual coal sales volume. Our sales of steam coal during 2005 and 2004 were made primarily to large utilities and industrial customers in the Eastern region of the United States, and our sales of metallurgical coal during those years were made primarily to steel companies in the Northeastern and Midwestern regions of the United States and in several countries in Europe, Asia and South America. Approximately 45% of our sales revenue in 2005 and 48% of our sales revenue in 2004 was derived from sales made outside the United States, primarily in Japan, Canada, Brazil, Korea and several countries in Europe.
      In addition, we generate other revenues from equipment and parts sales, equipment repair, highway construction, rentals, royalties, commissions, coal handling, terminal and processing fees, and coal and environmental analysis fees. We also record revenue for freight and handling charges incurred in delivering coal to our customers, which we treat as being reimbursed by our customers. However, these freight and handling revenues are offset by equivalent freight and handling costs and do not contribute to our profitability.
      Our business is seasonal, with operating results varying from quarter to quarter. We generally experience lower sales and hence build coal inventory during the winter months primarily due to the freezing of lakes that we use to transport coal to some of our customers.
      Our primary expenses are for wages and benefits, supply costs, repair and maintenance expenditures, cost of purchased coal, royalties, freight and handling costs, and taxes incurred in selling our coal. Historically, our cost of coal sales per ton is lower for sales of our produced and processed coal than for sales of purchased coal that we do not process prior to resale.
      We have one reportable segment, Coal Operations, which includes all of our revenues and costs from coal production and sales, freight and handling, rentals, commissions, coal handling and processing operations and coal recovery incidental to our highway construction operations. These revenues and costs included in our Coal Operations segment are reported by us in our coal revenues and cost of coal sales, except for the revenues and costs from rentals, commissions, and coal handling and processing operations, which we report in our other revenues and cost of other revenues, respectively.
      Predecessor and 2003 Acquisitions. On December 13, 2002, we acquired our Predecessor, the majority of the Virginia coal operations of Pittston Coal Company, from The Brink’s Company (formerly known as The Pittston Company), for $62.9 million. On January 31, 2003, we acquired Coastal Coal Company for $67.8 million. In connection with our acquisition of Coastal Coal Company, we acquired an overriding royalty interest in certain properties located in Virginia and West Virginia owned by El Paso CPG Company for $11.0 million in cash. Effective February 1, 2003, we sold the overriding royalty interest to affiliates of Natural Resource Partners, L.P. (“NRP”) for $11.8 million in cash. Effective April 1, 2003, we also sold substantially

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all of our fee-owned Virginia mineral properties to NRP for approximately $53.6 million in cash in a sale/leaseback transaction. On March 11, 2003, we acquired AMCI for $121.3 million and on November 17, 2003, we acquired the assets of Mears for $38.0 million in cash. We refer to the acquisitions of Coastal Coal Company, AMCI and Mears, collectively, as the “2003 Acquisitions.”
      Internal Restructuring and Our Initial Public Offering. On February 11, 2005, we completed a series of transactions in connection with the Internal Restructuring for the purpose of transitioning our top-tier holding company from a limited liability company to a corporation, and on February 18, 2005, we completed the initial public offering of our common stock. Further information regarding our Internal Restructuring and our initial public offering can be found in Note 2 to our consolidated financial statements included in this annual report. As a result of our initial public offering and our Internal Restructuring, we have incurred during the period after the initial public offering and Internal Restructuring and will continue to incur additional expenses that we have not incurred in prior periods, including expenses associated with compliance with corporate governance and periodic financial reporting requirements for public companies. Moreover, all of our income is now subject to income tax and therefore the effective tax rates reflected in our financial statements for periods prior to the Internal Restructuring are not indicative of our effective tax rates after our Internal Restructuring.
      As part of our Internal Restructuring, our executive officers and certain other key employees exchanged their interests in ANR Holdings for shares of our common stock and the right to participate in a distribution of the proceeds we received from the underwriters as a result of the underwriters’ exercise of their over-allotment option in connection with the initial public offering. As a result, we recorded stock-based compensation expense equal to the fair value of the unrestricted shares issued and distributions paid in the amount of $45.8 million for the year ended December 31, 2005. In addition, as a result of the conversion of outstanding options held by members of our management to purchase units of Alpha Coal Management into the ACM Converted Options, we recorded stock-based compensation of $0.7 million in 2005. The aggregate amount of stock-based compensation expense we recorded in 2005 was $46.5 million, equal to the $45.8 million of expense associated with distributions paid and the vested portions of shares issued in the Internal Restructuring and amortization expense from the unvested portions of shares issued in the Internal Restructuring, and $0.7 million of amortization expense from the ACM Converted Options. In addition, we had deferred stock-based compensation of $15.6 million, including $12.8 million and $2.6 million related to our Internal Restructuring and the ACM Converted Options, respectively, that we will record as non-cash stock-based compensation expense over the remaining term of the applicable two-year and five-year vesting periods, respectively, thereby reducing our earnings in those periods.
      In connection with our Internal Restructuring, we assumed the obligation of ANR Holdings to make distributions to (1) affiliates of AMCI in an aggregate amount of $6.0 million, representing the approximate incremental tax resulting from the recognition of additional tax liability resulting from our Internal Restructuring, and (2) First Reserve Fund IX, L.P. in an aggregate amount of approximately $4.5 million, representing the approximate value of tax attributes conveyed as a result of the Internal Restructuring (collectively, the “Tax Distributions”). The Tax Distributions to affiliates of AMCI are payable in five equal installments on the dates for which estimated income tax payments are due in each of April 2005, June 2005, September 2005, January 2006 and April 2006. The first four of these payments were made on April 15, 2005, June 15, 2005, September 15, 2005 and January 13, 2006, in the amount of $1.2 million each in cash. The Tax Distributions to First Reserve Fund IX, L.P. will be paid in three installments of approximately $2.1 million, $2.1 million and $0.3 million on December 15, 2007, 2008 and 2009, respectively. We will pay the Tax Distributions in cash or, to the extent our subsidiaries are not permitted by the terms of our credit facility or the indenture governing our senior notes to distribute cash to us to pay the Tax Distributions, in shares of our common stock.
      NKC Disposition. On April 14, 2005, we sold the assets of NKC to an unrelated third party for cash in the amount of $4.4 million, plus an amount in cash equal to the fair market value of NKC’s coal inventory, and the assumption by the buyer of certain liabilities of NKC. For the six months ended June 30, 2005, NKC contributed revenues of $4.5 million, an after-tax and minority interest loss of $0.2 million on 0.1 million tons of steam coal sold. In connection with the closing of the transaction, National King Coal, LLC was renamed NatCoal LLC, and Gallup Transportation and Transloading Company, LLC was renamed GTTC LLC.

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Giving effect to this disposition as if it had occurred on January 1, 2005, our revenues would have been reduced by $4.5 million and our net income would have increased by $0.2 million. We recorded a gain on this sale of $0.7 million and are reporting NKC as discontinued operations for all periods presented herein. Our historical financial statements have been reissued to report the disposition of NKC as discontinued operations and the components of the operating results included in discontinued operations are shown in Note 25 to our consolidated financial statements included elsewhere in this annual report.
      Nicewonder Acquisition and 2005 Financing. On October 26, 2005, we completed the acquisition of certain privately held coal reserves and operations of the Nicewonder Coal Group in southern West Virginia and southwestern Virginia for an aggregate purchase price of $328.2 million, consisting of cash at closing in the amount of $35.2 million, a cash payment of $1.9 million to be made to the sellers in April 2006, transaction costs of $4.7 million, $221.0 million principal amount of promissory installment notes of one of our indirect, wholly owned subsidiaries (of which $181.1 million was paid on November 2, 2005 and $39.9 million was paid on January 13, 2006), a final payment on February 6, 2006 in the amount of $12.3 million for working capital, and 2,180,233 shares of our common stock valued at approximately $53.2 million for accounting purposes. For this purpose, the value of the common stock issued was based on the average closing prices of our common stock for the five trading days surrounding October 20, 2005, the date the number of shares to be issued under the terms of the acquisition agreement became fixed without subsequent revision. In connection with the Nicewonder Acquisition, we also agreed to make royalty payments to the former owners of the acquired companies in the amount of $0.10 per ton of coal mined and sold from White Flame Energy’s Surface Mine No. 10. The Nicewonder Acquisition consisted of the purchase of the outstanding capital stock of White Flame Energy, Inc., Twin Star Mining, Inc. and Nicewonder Contracting, Inc., the equity interests of Powers Shop, LLC and Buchanan Energy, LLC and substantially all of the assets of Mate Creek Energy of W. Va., Inc. and Virginia Energy Company, and the business of Premium Energy, Inc. by merger.
      Also on October 26, 2005, in connection with our acquisition of the Nicewonder Coal Group, we entered into a new $525.0 million credit facility consisting of a $250.0 term loan facility and a $275.0 revolving credit facility. We used the net proceeds of the term loan facility and a portion of the proceeds from drawings under the revolving credit facility to finance the Nicewonder Acquisition and to refinance our $175.0 million prior credit facility.
Coal Pricing Trends and Uncertainties
      During 2005 and 2004, prices for our coal increased due to a combination of conditions in the United States and internationally, including an improving U.S. economy and robust economic growth in Asia, relatively low customer stockpiles, limited availability of high-quality coal from competing producers in Central Appalachia, capacity constraints of U.S. nuclear-powered electricity generators, high current and forward prices for natural gas and oil, and increased international demand for U.S. coal. This strong coal pricing environment has contributed to our growth in revenues during 2005 and 2004. While our outlook on coal pricing remains positive, future coal prices are subject to factors beyond our control and we cannot predict whether and for how long this strong coal pricing environment will continue. As of February 22, 2006, approximately 9%, 54% and 75%, respectively, of our planned production for 2006, 2007 and 2008, including production from the operations we acquired in the Nicewonder Acquisition, was uncommitted and was not yet priced. For the tons for which we have firm commitments in 2006, the average price for steam coal is $47.16 per ton and the average price for metallurgical coal is $73.72 per ton.
      During 2005 and 2004, we experienced increased costs for purchased coal which have risen with coal prices generally, and increased operating costs for steel manufactured equipment and supplies, employee wages and salaries and contract mining and trucking. We anticipate that cost pressures will persist in 2006, including higher costs for purchased coal, contractor mining, trucking and general mining supplies. Variable costs such as royalties and severance taxes are also expected to rise in 2006 in parallel with rising sales volumes and prices. We also experienced disruptions in railroad service beginning in the second half of 2004 and continuing through 2005, which caused delays in delivering products to customers and increased our internal coal handling costs at our operations. We expect disruptions in railroad service to continue during 2006.

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Conditions affecting railroad service are subject to factors beyond our control and we cannot predict whether and for how long these railroad-related costs will continue to increase in the future.
      We experienced a tight market for supplies of mining and processing equipment and parts during 2004 and 2005, due to increased demand by coal producers attempting to increase production in response to the strong market demand for coal. Although we are attempting to obtain adequate supplies of mining and processing equipment and parts to meet our production forecasts, continued limited availability of equipment and parts could prevent us from meeting those forecasts. The supply of mining and processing equipment and parts is subject to factors beyond our control and we cannot predict whether and for how long this supply market will remain limited.
      We are also experiencing a tight market for skilled mining employees and certified supervisors, due to increased demand by coal producers attempting to increase production in response to the strong market demand for coal, and demographic changes as existing miners in Appalachia retire at a faster rate than new miners are added to the Appalachian mining workforce. Although we have initiated training programs to create new skilled miners and raise the skill levels of existing miners, continued limited availability of skilled miners could prevent us from being able to meet our production and sales forecasts. The supply of skilled mining employees is subject to factors beyond our control and we cannot predict whether and for how long this employee market will remain limited.
      Due to Hurricane Katrina, we recorded a net pre-tax charge of $0.7 million in the third quarter of 2005 for loss of tonnage at a coal loading facility in New Orleans, representing the estimated total loss less the portion of the loss expected to be recovered through insurance claims. Based upon actual shipping data in the fourth quarter of 2005 and January 2006, surveys and visual inspections of remaining coal inventory, we determined that a loss of tonnage did not occur and the charge taken in the third quarter was reversed in our fourth quarter results.
      For additional information regarding some of the risks and uncertainties that affect our business, see Item 1A “Risks Factors.”
Unaudited Pro Forma Financial Information
      The following unaudited pro forma statement of income data for the years ended December 31, 2005 and 2004 gives effect to the 2004 Financings, Internal Restructuring, initial public offering, Nicewonder Acquisition and 2005 Financing as if each of these transactions described above had occurred on January 1, 2004 (in thousands):
                   
    Year Ended December 31,
     
    2005   2004
         
Revenues
  $ 1,799,129       1,397,315  
             
Income from continuing operations
  $ 22,315       15,676  
Loss from discontinued operations
    (266 )     (4,054 )
             
Net income
  $ 22,049       11,622  
             
Pro forma earnings per share data:
               
Basic and diluted:
               
 
Income from continuing operations
  $ 0.35       0.25  
 
Loss from discontinued operations
          (0.07 )
             
 
Pro Forma net income
  $ 0.35       0.18  
             
 
Pro Forma weighted average shares
    63,359,431       63,047,913  
 
Pro Forma weighted average diluted
    63,895,431       63,394,263  

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Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Summary
      For the year ended December 31, 2005, we recorded revenues of $1,627.3 million compared to $1,252.7 million for the year ended December 31, 2004, an increase of $374.6 million over the previous year. Net income increased from $20.0 million in 2004 to $21.2 million for 2005 and operating income increased $3.0 million to $72.1 million. Included in our 2005 results were after-tax stock-based compensation charges of $46.5 million related to our IPO. Tons sold increased from 25.3 million tons in 2004 to 26.7 million tons in 2005 mainly due to the impact of the Nicewonder acquisition and the opening of new mines as a result of our organic growth strategy. Coal margin, which we define as coal revenues less cost of coal sales, divided by coal revenues, increased from 14.8% in 2004 to 16.3% in 2005.
Revenues
                                 
    Year Ended December 31,   Increase (Decrease)
         
    2005   2004   $ or Tons   %
                 
    (In thousands, except per ton data)
Coal revenues
  $ 1,414,513     $ 1,079,733     $ 334,780       31 %
Freight and handling revenues
    185,555       141,100       44,455       32 %
Other revenues
    27,267       31,869       (4,602 )     (14 %)
                         
Total revenues
  $ 1,627,335     $ 1,252,702     $ 374,633       30 %
                         
Tons sold
    26,698       25,326       1,372       5 %
Coal sales realization per ton sold
  $ 52.98     $ 42.63     $ 10.35       24 %
      Coal Revenues. Coal revenues increased for the year ended December 31, 2005 by $334.8 million or 31%, to $1,414.5 million, as compared to the year ended December 31, 2004. This increase was due to a $10.35 per ton increase in the average sales price of our coal and the sale of 1.4 million additional tons over the comparable period last year. The acquisition of the Nicewonder Coal Group accounted for almost one-half of the increase in tons sold. The increase in the average sales price of our coal was due to the general increase in coal prices during the period and to our ability to take advantage of the exceptionally high metallurgical coal (met coal) sale prices by processing and marketing as met coal some coal qualities that would traditionally have been marketed as steam coal. Met coal prices increased by $13.06 per ton to $72.24 per ton as steam coal prices increased by $8.69 per ton to an average of $41.41 per ton. Our sales mix of met coal and steam coal in 2005 was essentially unchanged from 2004 at 37% and 63%, respectively. We sold 0.5 million more met tons in 2005 than in the prior year.
      Freight and Handling Revenues. Freight and handling revenues increased to $185.6 million for the year ended December 31, 2005, an increase of $44.5 million compared to the year ended December 31, 2004 due to an increase of 0.3 million tons of export shipments and a general increase in freight costs. However, these revenues are offset by equivalent costs and do not contribute to our profitability.
      Other Revenues. Other revenues decreased for the year ended December 31, 2005 by $4.6 million, or 14%, to $27.3 million, as compared to the same period for 2004. Revenues from our Maxxim Rebuild operation decreased by $4.4 million as that operation has directed more of its services to our companies and revenues from contract buy-outs decreased by $4.2 million in the current year. In addition to these decreases in other revenues, our other revenues in 2004 included a gain of $1.5 million on the partial satisfaction of our obligation to reclaim certain properties retained by the seller in the Pittston acquisition. Partially offsetting these decreases were increases in our coal processing and handling revenues of $1.9 million and highway construction revenues in the amount of $3.8 million. The highway construction revenues began with our acquisition of the Nicewonder Coal Group. Other revenues attributable to our Coal Operations segment were $9.9 million in 2005 and $13.8 million in 2004.

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Costs and Expenses
                                 
    Year Ended December 31.   Increase (Decrease)
         
    2005   2004   $   %
                 
    (In thousands, except per ton data)
Cost of coal sales (exclusive of items shown separately below)
  $ 1,184,092     $ 920,359     $ 263,733       29 %
Freight and handling costs
    185,555       141,100       44,455       32 %
Cost of other revenues
    23,675       22,994       681       3 %
Depreciation, depletion and amortization
    73,122       55,261       17,861       32 %
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)
    88,812       43,881       44,931       102 %
                         
Total costs and expenses
  $ 1,555,256     $ 1,183,595     $ 371,661       31 %
                         
Cost of coal sales per ton sold
  $ 44.35     $ 36.34     $ 8.01       22 %
      Cost of Coal Sales. For the year ended December 31, 2005, our cost of coal sales, which excludes charges for depreciation, depletion and amortization, increased $263.7 million, or 29%, to $1,184.1 million compared to the year ended December 31, 2004. Included in the increase in costs of $263.7 million was approximately $20.7 million of cost from our new Callaway business unit. Our cost of coal sales increased as a result of increased prices for labor, mine supplies, the performance and cost of contract mining services, higher prices for purchased coal, and increased variable sales-related costs, such as royalties and severance taxes. The average cost per ton sold increased 22% from $36.34 per ton in 2004 to $44.35 per ton in 2005. Our cost of coal sales as a percentage of coal revenues decreased from 85% in 2004 to 84% in 2005. For the years ended December 31, 2005 and 2004 our average cost per ton for our produced and processed coal sales was $40.07 and $33.04, respectively, and our average cost per ton for coal that we purchased from third parties and resold without processing was $58.88 and $45.21, respectively.
      Freight and Handling Costs. Freight and handling costs increased $44.5 million to $185.6 million during 2005 as compared to 2004, mainly due to a 0.3 million ton increase in export shipments where we initially pay the freight and handling costs and are then reimbursed by the customer as well as a general increase in freight rates. These costs are offset by an equivalent amount of freight and handling revenue.
      Cost of Other Revenues. Cost of other revenues increased $0.7 million, or 3%, to $23.7 million for the year ended December 31, 2005 as compared to the prior year due to the higher costs associated with our coal processing and handling operations in the amount of $2.3 million and the $2.7 million cost attributed to our highway construction operations acquired from the Nicewonder Coal Operations. These cost increases were almost offset by a reduction of costs at our Maxxim Rebuild operations in the amount of $4.4 million.
      Depreciation, Depletion and Amortization. Depreciation, depletion, and amortization increased $17.9 million, or 32%, to $73.1 million for the year ended December 31, 2005 as compared to the same period of 2004 due to capital additions resulting in additional depreciation and due to the impact of the Nicewonder Acquisition. Depreciation, depletion and amortization attributable to our Coal Operations segment were $70.8 million in 2005 and $51.7 million 2004. Depreciation, depletion and amortization per ton sold for our produced and processed coal increased from $2.93 per ton for the year ended December 31, 2004 to $3.55 per ton in the same period of 2005.
      Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $44.9 million, or 102%, to $88.8 million for the year ended December 31, 2005 compared to the same period in 2004. This increase is mainly attributable to our stock-based compensation charges in the amount of $46.5 million related to our IPO. Excluding the stock-based compensation charge of $46.5 million, our selling, general and administrative expenses as a percentage of total revenues decreased from 3.5% in 2004 to 2.6% in 2005.

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Interest Expense
      Interest expense increased $9.9 million to $29.9 million during 2005 compared to 2004. The increase was mainly due to higher levels of borrowings and higher variable interest rates in 2005.
Interest Income
      Interest income increased from $0.5 million to $1.1 million as a result of interest received on a note receivable issued in 2004 and an improved cash management system that allows us to put excess cash to work in secure cash equivalents.
Income Tax Expense
      Income tax expense from continuing operations increased $13.8 million to $19.0 million for the year ended December 31, 2005 as compared to the year ended December 31, 2004. Our effective tax rates for the year ended December 31, 2005 and 2004 were 43.8% and 10.2%, respectively.
      The effective tax rate for 2005 is higher than the statutory federal tax rate due primarily to the portion of the stock-based compensation charge associated with the issuance of common stock to management in connection with the Internal Restructuring and initial public offering that is not deductible for tax purposes. To a much lesser extent, state income taxes increased the effective tax rate above the statutory rate. The increase in expected income tax expense related to the stock-based compensation charge and state income taxes is offset in part primarily by the tax benefits associated with percentage depletion, the extraterritorial income exclusion, reduction in valuation allowance ($6.1 million), and taxes not being provided for on the minority interest and pass-through entity prior to the Internal Restructuring.
      The effective tax rate for 2004 is lower than the statutory federal tax rate primarily due to the Company not being subject to tax with respect to the portion of our income before taxes which is attributable to ANR Fund IX Holdings, L. P.’s portion of our earnings and the minority interest’s share in the earnings of ANR Holdings prior to the Internal Restructuring. In addition, income tax expense was further reduced by the tax benefits associated with percentage depletion and the extraterritorial income exclusion, partially offset by state income taxes and the increase in the valuation allowance of $0.6 million.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Summary
      For the year ended December 31, 2004, we recorded revenues of $1,252.7 million compared to $781.8 million for the year ended December 31, 2003, an increase of $470.9 million over the previous year. Net income increased from $2.3 million in 2003 to $20.0 million for 2004 and operating income increased $57.1 million to $69.1 million. Tons sold increased from 21.6 million tons in 2003 to 25.3 million tons in 2004 mainly due to the impact of our 2003 Acquisitions. Coal margin, which we define as coal revenues less cost of coal sales, divided by coal revenues, increased from 9.8% in 2003 to 14.8% in 2004.
Revenues
                                 
    Year Ended December 31,   Increase (Decrease)
         
    2004   2003   $ or Tons   %
                 
    (In thousands, except per ton data)
Coal revenues
  $ 1,079,733     $ 694,591     $ 385,142       55 %
Freight and handling revenues
    141,100       73,800       67,300       91 %
Other revenues
    31,869       13,458       18,411       137 %
                         
Total revenues
  $ 1,252,702     $ 781,849     $ 470,853       60 %
                         
Tons sold
    25,326       21,613       3,713       17 %
Coal sales realization per ton sold
  $ 42.63     $ 32.14     $ 10.49       33 %

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      Coal Revenues. Coal revenues increased for the year ended December 31, 2004 by $385.1 million or 55%, to $1,079.7 million, as compared to the year ended December 31, 2003. This increase was due to a $10.49 per ton increase in the average sales price of our coal and the sale of 3.7 million additional tons over the comparable period last year. The increase in the average sales price of our coal was due to the general increase in coal prices during the period and to our ability to take advantage of the exceptionally high metallurgical coal sale prices by processing and marketing as metallurgical coal some coal qualities that would traditionally have been marketed as steam coal. Approximately 63% and 37% of our tons sold during 2004 were steam coal and metallurgical coal, respectively, as compared to 71% and 29% during the same period in 2003. Our tons sold in 2004 increased by 3.7 million, or 17%, to 25.3 million, primarily due to the effect of our 2003 Acquisitions, which provided approximately 3.4 million additional tons.
      Freight and Handling Revenues. Freight and handling revenues in 2004 increased $67.3 million from $73.8 million in 2003 mainly due to an increase in overseas exports of approximately 3.6 million tons where we paid the freight and handling costs. These revenues are offset by equivalent costs and do not contribute to our profitability.
      Other Revenues. Other revenues increased for the year ended December 31, 2004 by $18.4 million, or 137%, to $31.9 million, as compared to the same period for 2003 primarily due to higher equipment and parts sales and equipment repairs in the amount of $8.4 million, an increase in coal handling and processing fees of $6.1 million, and higher sales commissions of $3.4 million. Other revenues for 2004 include a gain of $1.5 million on the partial satisfaction of an obligation to reclaim certain properties retained by the seller in the Pittston acquisition. Other revenues attributable to our Coal Operations segment were $13.8 million in 2004 and $3.4 million in 2003.
Costs and Expenses
                                 
    Year Ended December 31,   Increase (Decrease)
         
    2004   2003   $   %
                 
    (In thousands, except per ton data)
Cost of coal sales (exclusive of items shown separately below)
  $ 920,359     $ 626,265     $ 294,094       47 %
Freight and handling costs
    141,100       73,800       67,300       91 %
Cost of other revenues
    22,994       12,488       10,506       84 %
Depreciation, depletion and amortization
    55,261       35,385       19,876       56 %
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)
    43,881       21,926       21,955       100 %
                         
Total costs and expenses
  $ 1,183,595     $ 769,864     $ 413,731       54 %
                         
Cost of coal sales per ton sold
  $ 36.34     $ 28.98     $ 7.36       25 %
      Cost of Coal Sales. For the year ended December 31, 2004, our cost of coal sales, which excludes charges for depreciation, depletion and amortization and includes gain/loss on sale of fixed assets, increased $294.1 million, or 47%, to $920.4 million compared to the year ended December 31, 2003. Our cost of coal sales increased as a result of added costs involved in increasing the proportion of our sales made to the metallurgical markets, such as higher preparation and trucking costs, increased prices for steel-related mine supplies, contract mining services, higher prices for purchased coal, and increased variable sales-related costs, such as royalties and severance taxes. Approximately $80.0 million of the increase in the cost of coal sales was due to the 2003 Acquisitions which provided approximately 87% of our increase in tons sold. The average cost per ton sold increased 25% from $28.98 per ton in 2003 to $36.34 per ton in 2004. Our cost of coal sales as a percentage of coal revenues decreased from 90% in 2003 to 85% in 2004. For the years ended December 31, 2004 and 2003 our average cost per ton for our produced and processed coal sales was $33.04 and $28.34, respectively, and our average cost per ton for coal that we purchased from third parties and resold without

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processing was $45.21 and $31.91, respectively. Cost of coal sales in 2004 included $2.0 million of incentive bonus payments and accruals.
      Freight and Handling Costs. Freight and handling costs increased $67.3 million to $141.1 million during 2004 as compared to 2003, mainly due to a 3.6 million ton increase in overseas export shipments where we paid the freight and handling costs which we treated as being reimbursed by the customer. These costs were offset by an equivalent amount of freight and handling revenue.
      Cost of Other Revenues. Cost of other revenues increased $10.5 million, or 84%, to $23.0 million for the year ended December 31, 2004 as compared to the prior year due to higher volumes of equipment and part sales, equipment repairs, and processing and handling fees. Cost of equipment sales and repairs increased $7.3 million and processing and handling costs increased $2.6 million for the year ended December 31, 2004 as compared to the prior year. The cost of trucking revenues increased by $0.5 million for 2004 as compared to the prior year. Cost of other revenues attributable to our Coal Operations segment were $7.4 million in 2004 and $2.3 million in 2003.
      Depreciation, Depletion and Amortization. Depreciation, depletion, and amortization increased $19.9 million, or 56%, to $55.3 million for the year ended December 31, 2004 as compared to the same period of 2003 due to capital additions during 2004, resulting in additional depreciation of approximately $9.1 million. The remaining increase is attributable to the impact of the 2003 Acquisitions and 2003 capital additions of $27.7 million. Depreciation, depletion and amortization attributable to our Coal Operations segment were $51.7 million in 2004 and $32.4 million 2003. Depreciation, depletion and amortization per produced and processed ton sold increased from $2.00 per ton for the year ended December 31, 2003 to $2.93 per ton in the same period of 2004.
      Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $21.9 million, or 100%, to $43.9 million for the year ended December 31, 2004 compared to the same period in 2003. The increase is attributed to higher staffing levels and resulting salaries, wages and benefits of approximately $4.7 million, increased incentive bonus payments and accruals in the amount of $6.0 million, coal contract buyouts of $3.3 million, increased professional fees of approximately $3.2 million including $1.7 million incurred in documenting, assessing, and improving our controls and procedures due to the requirements of the Sarbanes-Oxley Act of 2002, and a net increase in all other sales, general and administrative expenses of approximately $4.7 million. Our selling, general and administrative expenses as a percentage of total revenues increased from 2.8% in 2003 to 3.5% in 2004.
Interest Expense
      Interest expense increased $12.2 million to $20.0 million during 2004 compared to 2003. The increase was mainly due to the additional interest expense of $10.8 million related to our 10% senior notes issued in May 2004 and the write-off of deferred financing costs of $2.8 million related to our previous credit facility.
Interest Income
      Interest income increased from $0.1 million to $0.5 million as a result of interest received on notes receivable issued in 2004.
Income Tax Expense
      Income tax expense increased $4.3 million to $5.2 million for the year ended December 31, 2004 as compared to the year ended December 31, 2003. Our effective tax rates from continuing operations for the year ended December 31, 2004 and 2003 were 10.2% and 18.7%, respectively. The effective tax rates are lower than the statutory tax rate since we are not subject to tax with respect to the portion of our income before taxes which is attributable to ANR Fund IX Holdings, L.P.’s portion of our earnings and the minority interest’s share in the earnings of ANR Holdings. In addition, our taxable income is reduced by percentage depletion allowances (computed as a percentage of coal revenue, subject to certain income limitations) and the extraterritorial income exclusion (ETI) deduction (computed as a percentage of exported coal revenue,

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subject to certain income limitations) which reduces our effective tax rates. These reductions in our effective tax rates are offset by the effect of increases in our valuation allowance for deferred tax assets of $0.6 million and $0.8 million recorded in the year ended December 31, 2004 and 2003, respectively. The reduction in our effective tax rate in 2004 compared to 2003 is due primarily to the ETI deduction in 2004 generated from significant export coal revenue, a lower valuation allowance as a percentage of pre-tax income in 2004, and a larger percentage of minority interest in 2004 which has no income tax provision.
Liquidity and Capital Resources
      Our primary liquidity and capital resource requirements are to finance the cost of our coal production and purchases, to make capital expenditures, pay income taxes, and to service our debt and reclamation obligations. Our primary sources of liquidity are cash flow from sales of our produced and purchased coal, other income and borrowings under our senior credit facility.
      At December 31, 2005, our available liquidity was $249.1 million, including cash and cash equivalents of $39.6 million and $209.5 million available under our credit facility. Our total indebtedness was $485.8 million at December 31, 2005, an increase of $284.1 million from the year ended December 31, 2004. As previously discussed, on October 26, 2005, we closed our 2005 Financing.
      Our cash capital spending for the year ended December 31, 2005 was $122.3 million, and we expect to spend from $140.0 million to $150.0 million in cash capital spending in 2006. These expenditures have been and will be used to develop new mines and replace or add equipment. Based on the terms of our outstanding capital lease obligations and indebtedness as of December 31, 2005, projected 2006 payments of principal on capital lease obligations and indebtedness, including repayment of the final installment due on the promissory notes issued to the sellers in connection with the Nicewonder Acquisition, are $62.3 million in the aggregate, of which $46.2 million is payable in the first quarter of 2006, $5.9 million is payable in each of the two succeeding quarters and the balance is payable in the fourth quarter. Based on our projection of cash to be generated from operations in 2006 and projected availability under our revolving line of credit, we believe that cash from operations and available borrowings will be sufficient to meet our working capital requirements, anticipated capital expenditures and debt repayment requirements during each quarter of 2006.
Cash Flows
      Net cash provided by operations in 2005 was $149.6 million, an increase of $42.9 million from the $106.8 million of net cash provided by operations during 2004. An increase in our net income and an increase in our non-cash charges (mainly due to our stock-based compensation) provided more cash in 2005 than the comparable period in 2004 in the amount of $38.9 million and a decrease in our net investment in operating assets and liabilities contributed $4.0 million to our operating cash flow increase this year.
      Net cash used in investing activities consumed $253.2 million more cash in 2005 over the year ago period mainly due to the Nicewonder Coal Group acquisition ($220.9 million) and an increase in capital expenditures in the amount of $50.3 million.
      Net cash provided by financing activities increased by $246.4 million to $222.0 million in the year ended December 31, 2005 over the year ended December 31, 2004. During the year ended December 31, 2004, we recapitalized our company by issuing $175.0 million of 10% senior notes and entered into a new credit facility. We used the proceeds to repay our then existing credit facility and to pay distributions to the members of ANR Holdings, LLC. Net cash used by financing activities was $24.4 million during 2004. In the year ended December 31, 2005, we completed our previously discussed Internal Restructuring, IPO and 2005 Financing. The proceeds from the IPO were used to repay shareholders’ notes issued as part of the Internal Restructuring. The proceeds from the new credit facility we entered into in connection with the 2005 Financing were used to repay the 2004 credit facility and to finance the Nicewonder Coal Group acquisition. Our long-term debt increased approximately $126.7 million during 2005 and has been used to fund our cash needs for the purchase of capital equipment and the Nicewonder acquisition.

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      Cash provided by operating activities was $106.8 million for the year ended December 31, 2004, an increase of $52.7 million from the same period in 2003. Cash provided by operations for 2004 benefited from the effects of our 2003 Acquisitions and the strength of the coal markets during the period. This increase is attributable to an increase in net income of $17.7 million for 2004 over 2003, an increase in non-cash charges included in net income of $49.9 million and partially offset by the effects of a $15.0 million increase in net operating assets and liabilities.
      Net cash used in investing activities was $86.2 million during the year ended December 31, 2004, $13.9 million less than the same period of 2003. Capital expenditures increased $44.3 million, to $72.0 million during 2004. The increase in capital expenditures was primarily due to the replacement of equipment, new mine development and upgrades to a preparation plant. In the second quarter of 2003, we sold our interest in certain coal properties acquired in the purchase of our Predecessor, and a royalty interest acquired in our Coastal Coal Company acquisition for cash of $65.2 million. We also paid $133.8 million for the Coastal Coal Company, U.S. AMCI and Mears acquisitions in 2003. As part of a coal supply agreement, we loaned an unrelated coal supplier $10.0 million in June 2004 at a variable rate to be repaid in installments over a two-year period beginning in August 2004. The loan is secured by the assets of the debtor and personally guaranteed by the debtor’s owner. The related coal supply agreement with the debtor has provided us with approximately 27,000 tons of coal per month through December 31, 2005. In September 2004, we also acquired an equity interest for a subscription price of $6.5 million in a company which is developing a mining property in Venezuela. Payments totaling $4.5 million were made during the year ended December 31, 2004.
      Net cash used in financing activities during the year ended December 31, 2004 was $24.4 million compared with net cash provided by financing activities of $48.8 million in the prior year. Net cash used by financing activities included the net proceeds of $171.5 million received as a result of the issuance of our $175 million 10% senior notes in May 2004 offset by distributions made to our equity owners of $115.6 million, the repayment of bank and other debt in the amount of $75.8 million, $10.5 million paid for debt issuance costs and $1.7 million for deferred stock offering costs during the year ended December 31, 2004. We received $18.3 million in capital contributions and $20.0 million in advances from affiliates during the year ended December 31, 2003. In addition, we incurred bank and other debt in the net amount of $12.9 million during the year ended December 31, 2003.
Credit Facility and Long-term Debt
      As of December 31, 2005, our total long-term indebtedness, including capital lease obligations, consisted of the following (in thousands):
           
    December 31,
    2005
     
10% Senior notes due 2012
  $ 175,000  
Term Loan B
    250,000  
Variable rate term notes
    293  
Capital lease obligation
    1,496  
       
 
Total long-term debt
    426,789  
Less current portion
    (3,242 )
       
 
Long-term debt, net of current portion
  $ 423,547  
       
      Our current credit facility and the indenture governing the senior notes each impose certain restrictions on our subsidiaries, including restrictions on our subsidiaries’ ability to: incur debt; grant liens; enter into agreements with negative pledge clauses; provide guarantees in respect of obligations of any other person; pay dividends and make other distributions; make loans, investments, advances and acquisitions; sell assets; make redemptions and repurchases of capital stock; make capital expenditures; prepay, redeem or repurchase debt; liquidate or dissolve; engage in mergers or consolidations; engage in affiliate transactions; change businesses; change our fiscal year; amend certain debt and other material agreements; issue and sell capital stock of

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subsidiaries; engage in sale and leaseback transactions; and restrict distributions from subsidiaries. In addition, our current credit facility provides that we must meet or exceed certain interest coverage ratios and must not exceed certain leverage ratios.
      Borrowings under our current credit facility are subject to mandatory prepayment (1) with 100% of the net cash proceeds received from asset sales or other dispositions of property by Alpha NR Holding, Inc. and its subsidiaries (including insurance and other condemnation proceedings), subject to certain exceptions and reinvestment provisions, and (2) with 100% of the net cash proceeds received by Alpha NR Holding, Inc. and its subsidiaries from the issuance of debt securities or other incurrence of debt, excluding certain indebtedness.
Other
      As a regular part of our business, we review opportunities for, and engage in discussions and negotiations concerning, the acquisition of coal mining assets and interests in coal mining companies, and acquisitions of, or combinations with, coal mining companies. When we believe that these opportunities are consistent with our growth plans and our acquisition criteria, we will make bids or proposals and/or enter into letters of intent and other similar agreements, which may be binding or nonbinding, that are customarily subject to a variety of conditions and usually permit us to terminate the discussions and any related agreement if, among other things, we are not satisfied with the results of our due diligence investigation. Any acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. There can be no assurance that additional financing will be available on terms acceptable to us, or at all.
Analysis of Material Debt Covenants
      We were in compliance with all covenants under our current credit facility and the indenture governing our senior notes as of December 31, 2005.
      The financial covenants in our current credit facility require, among other things, that:
  •  Alpha NR Holding Inc. must maintain a leverage ratio, defined as the ratio of consolidated adjusted debt (consolidated debt less unrestricted cash and cash equivalents) to Adjusted EBITDA (as defined in the new credit agreement), of not more than 4.00 at December 31, 2005, March 31, June 30, September 30 and December 31, 2006, 3.75 at March 31, June 30, September 30 and December 31, 2007, and 3.50 at March 31, 2008 and each quarter end thereafter, with Adjusted EBITDA being computed using the most recent four quarters; and
 
  •  Alpha NR Holding Inc. must maintain an interest coverage ratio, defined as the ratio of Adjusted EBITDA to cash interest expense, of 2.50 or greater on the last day of any fiscal quarter.
      Based upon Adjusted EBITDA (as defined in our current credit agreement), Alpha NR Holding Inc.’s leverage ratio and interest coverage ratio (as such ratios are defined in the credit agreement) at December 31, 2005 were 1.85 and 8.12, respectively. Adjusted EBITDA is used in our current credit facility to determine compliance with many of the covenants under the facility. A breach of the covenants in the credit facility that are tied to ratios based on Adjusted EBITDA could result in a default under the credit facility and the lenders could elect to declare all amounts borrowed due and payable. Any acceleration under our credit facility would also result in a default under our indenture.
      Adjusted EBITDA is defined in our current credit facility as EBITDA, further adjusted to exclude non-recurring items, non-cash items and other adjustments permitted in calculating covenant compliance under our credit facility, as shown in the table below. We believe that the inclusion of supplementary adjustments to

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EBITDA applied in presenting Adjusted EBITDA is appropriate to provide additional information to investors to demonstrate compliance with our financial covenants.
                                         
    Three Months   Three Months   Three Months   Three Months   Twelve Months
    Ended   Ended   Ended   Ended   Ended
    March 31,   June 30,   September 30,   December 31,   December 31,
    2005   2005   2005   2005   2005
                     
    (In thousands)
Net Income
  $ (25,429 )   $ 26,019     $ 8,210     $ 12,413     $ 21,213  
Interest expense, net
    5,533       6,456       6,439       10,155       28,583  
Income tax expense
    2,457       9,050       3,542       3,812       18,861  
Depreciation, depletion, and amortization
    14,480       15,048       16,277       27,600       73,405  
                               
EBITDA
    (2,959 )     56,573       34,468       53,980       142,062  
Minority interest(1)
    2,846                         2,846  
Other allowable adjustments
            683               452       1,135  
Accretion expense
    878       878       878       880       3,514  
Amortization of deferred gains
    (358 )     (358 )     (358 )     (402 )     (1,476 )
Nicewonder EBITDA
    16,509       16,509       18,581       4,832       56,431  
Stock-based compensation charge
    36,407       3,381       3,381       3,350       46,519  
                               
Adjusted EBITDA
  $ 53,323     $ 77,666     $ 56,950     $ 63,092     $ 251,031  
                               
Leverage ratio(2)
                                    1.85  
Interest coverage ratio(3)
                                    8.12  
 
(1)  Because our credit facility and our senior notes are issued by our subsidiaries, we are required to adjust our EBITDA for our minority interest which does not exist at the subsidiary level.
 
(2)  Leverage ratio is defined in our credit facility as total debt divided by adjusted EBITDA.
 
(3)  Interest coverage ratio is defined in our credit facility as adjusted EBITDA divided by cash interest expense.
Contractual Obligations
      The following is a summary of our significant contractual obligations as of December 31, 2005 (in thousands):
                                         
    2006   2007-2008   2009-2010   After 2010   Total
                     
Long-term debt and capital leases(1)
  $ 3,242     $ 5,816     $ 5,231     $ 412,500     $ 426,789  
Equipment purchase commitments
    64,342                         64,342  
Operating leases
    5,099       4,668       1,590       7,284       18,641  
Minimum royalties
    10,388       18,821       16,650       27,859       73,718  
Coal purchase commitments
    258,490       27,420                   285,910  
Coal contract buyout
    680       1,360       1,247             3,287  
                               
Total
  $ 342,241     $ 58,085     $ 24,718     $ 447,643     $ 872,687  
                               
 
(1)  Long-term debt and capital leases include principal amounts due in the years shown. Interest payable on these obligations, assuming a rate of 8.0% on our variable rate loan, would be approximately $37.6 million in 2006, $74.3 million in 2007 to 2008, $73.4 million in 2009 to 2010, and $62.4 million after 2010.

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      Additionally, we have long-term liabilities relating to mine reclamation and end-of-mine closure costs, workers’ compensation benefits and all of our operating and management-services subsidiaries have long-term liabilities relating to retiree health care (postretirement benefits). The table below reflects the estimated payments for these obligations:
                                         
    Within                
    1 Year   2-3 Years   4-5 Years   After 5 Years   Total
                     
Reclamation
  $ 7,190     $ 9,873     $ 12,865     $ 45,895     $ 75,823  
Postretirement
    115       711       2,707       283,833       287,366  
Workers’ compensation benefits
    1,019       875       309       4,717       6,920  
                               
Total
  $ 8,324     $ 11,459     $ 15,881     $ 334,445     $ 370,109  
                               
Off-Balance Sheet Arrangements
      In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.
      From time to time, we provide guarantees to financial institutions to facilitate the acquisition of mining equipment by third parties who mine coal for us. This arrangement is beneficial to us because it helps insure a continuing source of coal production.
      Federal and state laws require us to secure payment of certain long-term obligations such as mine closure and reclamation costs, federal and state workers’ compensation, coal leases and other obligations. We typically secure these payment obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond or a bank letter of credit, either of which would require a greater use of our credit facility. We then use bank letters of credit to secure our surety bonding obligations as a lower cost alternative than securing those bonds with cash. Under our $150.0 million committed bonding facility, we are required to provide bank letters of credit in an amount up to 50% of the aggregate bond liability. Recently, surety bond costs have increased, while the market terms of surety bonds have generally become less favorable to us. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.
      As of December 31, 2005, we had outstanding surety bonds with third parties for post-mining reclamation totaling $116.7 million plus $8.3 million for miscellaneous purposes. We maintained letters of credit as of December 31, 2005 totaling $65.5 million to secure reclamation and other obligations.
      In connection with our acquisition of Coastal Coal Company, the seller, El Paso CGP Company, agreed to retain and indemnify us for all workers’ compensation and black lung claims incurred prior to the acquisition date of January 31, 2003. The majority of this liability relates to claims in the state of West Virginia. If El Paso CGP Company fails to honor its agreement with us, then we would be liable for the payment of those claims, which were estimated in April 2004 to be approximately $5.4 million on an undiscounted basis using claims data through June 2003. El Paso CGP Company has posted a bond with the state of West Virginia for the required discounted amount of $3.7 million for claims incurred prior to the acquisition.
Outlook
      While our business is subject the general risks of the coal industry and specific individual risks, we believe that the outlook for coal markets remains positive worldwide, assuming continued growth in the U.S., China, Pacific Rim, Europe and other industrialized economies that are increasing coal demand for electricity generation and steelmaking. Published indices show improved year-over- year coal prices in most U.S. and global coal markets, and worldwide coal supply/demand fundamentals remain tight due to high market demand, transportation constraints and production difficulties in most countries. Metallurgical coal is

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generally selling at a significant premium to steam coal, and we expect that pricing relationship to continue based on the same assumptions made above.
      For 2006, we are targeting annual production of 24 million to 25 million tons and total sales volume of 28 million to 30 million tons. Approximately 91%, 46% and 25% of our planned production in 2006, 2007 and 2008, respectively, has been priced as of February 22, 2006.
      We anticipate continued challenges with railroad service, hopefully with gradual improvement in rail service beginning in the second half of 2006. We are working with our customers and the railroads in an effort to address these issues in a timely manner.
      Based on current market conditions in the steam and metallurgical coal markets, we anticipate increasing the proportion of our metallurgical coal sales that are committed under long-term contracts as compared to prior years and continuing to market portions of our high quality steam coal production as metallurgical coal. We plan to focus on organic growth by continuing to develop our existing reserves. In addition, we also plan to evaluate attractively priced acquisitions that create potential synergies with our existing operations.
      We will record a charge in the amount of $3.2 million in each quarter during 2006, as the result of stock-based compensation related to our IPO. See “— Overview — Internal Restructuring and Our Initial Public Offering.” See Item 1A “Risks Factors” for a discussion of other factors that could affect us in the future.
Critical Accounting Estimates and Assumptions
      Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). GAAP requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.
      Reclamation. Our asset retirement obligations arise from the federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. We account for the costs of our reclamation activities in accordance with the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based upon third-party costs. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. In accordance with the provisions of SFAS No. 143, we determine the fair value of our asset retirement obligations. In order to determine fair value, we must also estimate a discount rate and third-party margin. Each is discussed further below:
  •  Discount Rate. SFAS No. 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of SFAS No. 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.
 
  •  Third-Party Margin. SFAS No. 143 requires the measurement of an obligation to be based upon the amount a third party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin was added to the estimated costs of these activities. This margin was estimated based upon our historical experience with contractors performing similar types of reclamation activities. The inclusion of this margin will

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  result in a recorded obligation that is greater than our estimates of our cost to perform the reclamation activities. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is completed.
      On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revisions to cost estimates and productivity assumptions, to reflect current experience. At December 31, 2005, we had recorded asset retirement obligation liabilities of $53.5 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2005, we estimate that the aggregate undiscounted cost of final mine closure is approximately $75.8 million.
      Coal Reserves. There are numerous uncertainties inherent in estimating quantities of economically recoverable coal reserves. Many of which are beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled by our internal engineers and geologists and reviewed by a third party consultant. Some of the factors and assumptions that impact economically recoverable reserve estimates include:
  •  geological conditions;
 
  •  historical production from the area compared with production from other producing areas;
 
  •  the assumed effects of regulations and taxes by governmental agencies;
 
  •  assumptions governing future prices; and
 
  •  future operating costs.
      Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and these variances may be material.
      Postretirement Medical Benefits. We have long-term liabilities for postretirement benefit cost obligations. Detailed information related to these liabilities is included in the notes to our financial statements included elsewhere in this annual report. Liabilities for postretirement benefit costs are not funded. The liability is actuarially determined, and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for postretirement benefit costs. The discount rate assumption reflects the rates available on high quality fixed income debt instruments. The discount rate used to determine the net periodic benefit cost for postretirement benefits other than pensions was 5.75% for the year ended December 31, 2005 and 6.25% for the year ended December 31, 2004. We make assumptions related to future trends for medical care costs in the estimates of retiree health care and work-related injury and illness obligations. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our requirement to satisfy these or additional obligations. Below we have provided two sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.
      Health care cost trend rate (dollars in thousands):
                 
    One-Percentage-   One-Percentage-
    Point Increase   Point Decrease
         
Effect on total service and interest cost components
  $ 97     $ (60 )
Effect on accumulated postretirement benefit obligation
    959       (740 )
      Discount rate (dollars in thousands):
                 
    One Half-   One Half-
    Percentage-   Percentage-
    Point Increase   Point Decrease
         
Effect on total service and interest cost components
  $ (367 )   $ 384  
Effect on accumulated postretirement benefit obligation
    (4,350 )     4,813  

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      Effective July 1, 2004, we began offering postretirement medical benefits to active, union-free employees that will provide a credit equal to $20 per month per year of service for pre-65 year-old retirees, and $9 per month per year of service for post-65-year old retirees toward the purchase of medical benefits (as defined) from us. This new plan resulted in prior service cost of $27.1 million which will be amortized over the remaining service lives of the union-free employees. This amortization of prior service cost is expected to be approximately $2.8 million per year. We recorded $8.0 million in costs with respect to this new plan in 2005, consisting of service cost, amortization of prior service cost and interest cost.
      Effective April 1, 2005 and October 3, 2005, our plan was amended to replace two union retiree medical plans with a defined dollar benefit similar to the union-free plan, which resulted in a prior service credit of approximately $6.2 million. In addition, on October 26, 2005 upon the acquisition of the Nicewonder Coal Group, we granted the acquired employees up to ten years of credited service under our plan resulting in an estimated $2.0 million of prior service cost.
      Workers’ Compensation. Workers’ compensation is a system by which individuals who sustain personal injuries due to job-related accidents are compensated for their disabilities, medical costs, and on some occasions, for the costs of their rehabilitation, and by which the survivors of workers who suffer fatal injuries receive compensation for lost financial support. The workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee who is injured in the course of employment. Our operations are covered through a combination of a self-insurance program, participation in a state run program, and an insurance policy. We accrue for any self-insured liability by recognizing costs when it is probable that a covered liability has been incurred and the cost can be reasonably estimated. Our estimates of these costs are adjusted based upon actuarial studies. Actual losses may differ from these estimates, which could increase or decrease our costs.
      Coal Workers’ Pneumoconiosis. We are responsible under various federal statutes, including the Coal Mine Health and Safety Act of 1969, and various states’ statutes, for the payment of medical and disability benefits to eligible employees resulting from occurrences of coal workers’ pneumoconiosis disease (black lung). Our operations are covered through a combination of a self-insurance program, in which we are a participant in a state run program, and an insurance policy. We accrue for any self-insured liability by recognizing costs when it is probable that a covered liability has been incurred and the cost can be reasonably estimated. Our estimates of these costs are adjusted based upon actuarial studies. Actual losses may differ from these estimates, which could increase or decrease our costs.
      Income Taxes. We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes”, which requires the recognition of deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, we take into account various factors, including objective evidence obtained from historical earnings, future sales commitments, the expected level of future taxable income and available tax planning strategies, and the impact the alternative minimum tax has on utilization of deferred tax assets. If future taxable income is lower than expected or if expected tax planning strategies are not available as anticipated, we may record a change to the valuation allowance through income tax expense in the period the determination is made. If historical earnings, future sales commitments, and expected future earnings and tax planning strategies support additional utilization of deferred tax assets than previously recorded, we may record a change to the valuation allowance through income tax expense in the period the determination is made.
      Changes in the valuation allowance due to increases in the tax basis of assets caused by transactions between us and our stockholders (the 2005 Internal Restructuring) are charged to additional paid-in capital, and not income tax expense, in the calendar year that the transaction occurred. Adjustments to the valuation allowance in subsequent years are charged (credited) to income tax expense.

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New Accounting Pronouncements
      In December 2004, the Financial Accounting Standards Board issued SFAS No. 123(R), Share-Based Payment, which requires companies to expense the fair value of equity awards over the required service period. This Statement is a revision of SFAS No. 123, Accounting for Stock — Based Compensation. SFAS No. 123(R) supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, which uses the intrinsic value method to value stock-based compensation. On April 14, 2005, the Securities and Exchange Commission adopted a new rule that amends the effective date of SFAS No. 123(R) to allow registrants to implement SFAS No. 123(R) as of the beginning of the first annual reporting period that begins after June 15, 2005. We adopted SFAS No. 123(R) effective January 1, 2006 and used the modified prospective method, in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS No. 123(R) for all share-based payments granted after the effective date and based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the effective date. The expected impact of applying the modified prospective method to unvested options as of January 1, 2006 is an increase to pre-tax expense of approximately $1.3 million for the year ended December 31, 2006. Such amount could vary depending on the level of forfeitures that occur or other circumstances. We currently anticipate utilizing restricted stock for equity-based compensation in 2006 instead of stock option grants. Accounting for restricted stock awards is not impacted by SFAS No. 123(R),
      In March 2005, the Emerging Issues Task Force issued EITF Issue No. 04-6, “Accounting for Stripping Costs in the Mining Industry,” which states 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 Issue No. 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005. Our existing accounting practices are consistent with EITF Issue No. 04-06, therefore this pronouncement will not effect our results of operations or financial condition.
Discussion of Seasonality Impacts on Operations
      Our business is seasonal, with operating results varying from quarter to quarter. We have historically experienced lower sales during winter months primarily due to the freezing of lakes that we use to transport coal to some of our customers. As a result, our first quarter cash flow and profits have been, and may continue to be, negatively impacted. Lower than expected sales by us during this period could have a material adverse effect on the timing of our cash flows and therefore our ability to service our obligations with respect to our existing and future indebtedness.
Item 7A. Quantitative and Qualitative Discussions about Market Risk
      In addition to risks inherent in operations, we are exposed to market risks. The following discussion provides additional detail regarding our exposure to the risks of changing coal prices, interest rates and customer credit.
      We are exposed to market price risk in the normal course of selling coal. As of February 22, 2006, approximately 9%, 54% and 75% of our estimated 2006, 2007 and 2008 production tonnage, respectively, was uncommitted. We have increased the proportion of our planned future production for which we have contracts to sell coal, which has the effect of lessening our market price risk.
      All of our borrowings under the revolving credit facility are at a variable rate, so we are exposed to rising interest rates in the United States. A one percentage point increase in interest rates would result in an annualized increase to interest expense of $2.5 million based on our variable rate borrowings as of December 31, 2005.
      Our concentration of credit risk is substantially with electric utilities, producers of steel and foreign customers. Our policy is to independently evaluate a customer’s creditworthiness prior to entering into transactions and to periodically monitor the credit extended.

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Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors
Alpha Natural Resources, Inc.:
      We have audited the accompanying consolidated balance sheets of Alpha Natural Resources, Inc. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, stockholders’ equity and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Alpha Natural Resources, Inc. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
  /s/ KPMG LLP
Roanoke, VA
March 28, 2006

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
                     
    December 31,
     
    2005   2004
         
    (In thousands)
ASSETS
Current assets:
               
 
Cash and cash equivalents
  $ 39,622     $ 7,391  
 
Trade accounts receivable, net
    147,961       95,828  
 
Notes and other receivables
    10,330       10,835  
 
Inventories
    84,885       54,569  
 
Due from affiliate
          323  
 
Deferred income taxes
          4,674  
 
Prepaid expenses and other current assets
    36,117       28,915  
             
   
Total current assets
    318,915       202,535  
Property, plant, and equipment, net
    582,750       217,964  
Goodwill
    18,641       18,641  
Other intangibles, net
    11,014       1,155  
Deferred income taxes
    38,967        
Other assets
    43,371       36,826  
             
   
Total assets
  $ 1,013,658     $ 477,121  
             
 
LIABILITIES AND STOCKHOLDERS’ EQUITY AND PARTNERS’ CAPITAL
Current liabilities:
               
 
Current portion of long-term debt
  $ 3,242     $ 1,693  
 
Notes payable
    59,014       15,228  
 
Bank overdraft
    17,065       10,024  
 
Trade accounts payable
    99,746       51,050  
 
Deferred income taxes
    11,243        
 
Accrued expenses and other current liabilities
    93,531       68,283  
             
   
Total current liabilities
    283,841       146,278  
Long-term debt, net of current portion
    423,547       184,784  
Workers’ compensation benefits
    5,901       4,678  
Postretirement medical benefits
    24,461       15,637  
Asset retirement obligation
    46,296       32,888  
Deferred gains on sale of property interests
    5,762       5,516  
Deferred income taxes
          7,718  
Other liabilities
    11,085       4,911  
             
   
Total liabilities
    800,893       402,410  
             
Minority interest
          28,778  
             
Stockholders’ equity and partners’ capital:
               
Alpha Natural Resources, Inc.:
               
 
Preferred stock — par value $0.01, 10,000,000 shares authorized, none issued
           
 
Common stock — par value $0.01, 100,000,000 shares authorized, 64,420,414 shares issued and outstanding
    644        
 
Additional paid-in capital
    209,210        
 
Unearned stock-based compensation
    (15,602 )      
 
Retained earnings
    18,513        
             
   
Total Alpha Natural Resources, Inc. stockholders’ equity
    212,765        
Alpha NR Holding, Inc.:
               
 
Preferred stock — par value $0.01, 1,000 shares authorized, none issued
           
 
Common stock — par value $0.01, 1,000 shares authorized, 100 shares issued and outstanding
           
 
Additional paid-in capital
            22,153  
 
Retained earnings
            18,828  
             
   
Total Alpha NR Holding, Inc. stockholder’s equity
          40,981  
Alpha Fund IX Holdings, L.P.:
               
 
Partners’ capital
          4,952  
             
   
Total stockholders’ equity and partners’ capital
    212,765       45,933  
             
   
Total liabilities and stockholders’ equity and partners’ capital
  $ 1,013,658     $ 477,121  
             
See accompanying notes to consolidated financial statements.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
                               
    Year Ended December 31,
     
    2005   2004   2003
             
    (In thousands, except per share amounts)
Revenues:
                       
 
Coal revenues
  $ 1,414,513     $ 1,079,733     $ 694,591  
 
Freight and handling revenues
    185,555       141,100       73,800  
 
Other revenues
    27,267       31,869       13,458  
                   
   
Total revenues
    1,627,335       1,252,702       781,849  
                   
Costs and expenses:
                       
 
Cost of coal sales (exclusive of items shown separately below)
    1,184,092       920,359       626,265  
 
Freight and handling costs
    185,555       141,100       73,800  
 
Cost of other revenues
    23,675       22,994       12,488  
 
Depreciation, depletion and amortization
    73,122       55,261       35,385  
 
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)
    88,812       43,881       21,926  
                   
   
Total costs and expenses
    1,555,256       1,183,595       769,864  
                   
   
Income from operations
    72,079       69,107       11,985  
                   
Other income (expense):
                       
 
Interest expense
    (29,937 )     (20,041 )     (7,848 )
 
Interest income
    1,064       531       103  
 
Miscellaneous income
    91       722       574  
                   
   
Total other income (expense), net
    (28,782 )     (18,788 )     (7,171 )
                   
   
Income from continuing operations before income taxes and minority interest
    43,297       50,319       4,814  
Income tax expense
    18,953       5,150       898  
                   
   
Income before minority interest
    24,344       45,169       3,916  
Minority interest
    2,918       22,781       1,164  
                   
   
Income from continuing operations
    21,426       22,388       2,752  
                   
Discontinued operations (Note 25):
                       
   
Loss from discontinued operations before income taxes and minority interest
    (378 )     (6,514 )     (950 )
   
Income tax benefit
    (93 )     (1,190 )     (230 )
   
Minority interest
    (72 )     (2,951 )     (230 )
                   
   
Loss from discontinued operations
    (213 )     (2,373 )     (490 )
                   
     
Net income
  $ 21,213     $ 20,015     $ 2,262  
                   
Net income per share, as adjusted (Note 4):
                       
 
Basic and diluted:
                       
   
Income from continuing operations
  $ 0.38     $ 1.52     $ 0.19  
   
Loss from discontinued operations
          (0.16 )     (0.04 )
                   
   
Net income, as adjusted
  $ 0.38     $ 1.36     $ 0.15  
                   
See accompanying notes to consolidated financial statements.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND PARTNERS’ CAPITAL
                                                                                                 
            ANR Fund IX    
    Alpha Natural Resources, Inc.   Alpha NR Holding, Inc.   Holdings, L.P.    
                Total
                Retained           Stockholders’
    Common Stock   Additional   Unearned       Total       Additional   Earnings   Total       Equity and
        Paid-In   Stock-Based   Retained   Stockholders’   Common   Paid-In   (Accumulated   Stockholder’s   Partners’   Partners’
    Shares   Amount   Capital   Compensation   Earnings   Equity   Stock   Capital   Deficit)   Equity   Capital   Capital
                                                 
    (In thousands, except per share amounts)
Balances, December 31, 2002
  $     $     $     $     $     $     $     $ 21,384     $ (529 )   $ 20,855     $ 2,529     $ 23,384  
Net income
                                                      1,971       1,971       291       2,262  
Contributed capital
                                              15,153             15,153       1,868       17,021  
Note payable to affiliate contributed to capital
                                              39,173             39,173       4,827       44,000  
Noncash distribution of Virginia Tax Credit
                                                                (300 )     (300 )
                                                                         
Balances, December 31, 2003
                                              75,710       1,442       77,152       9,215       86,367  
Net income
                                                    17,386       17,386       2,629       20,015  
Noncash distribution of Virginia Tax Credit
                                                                (292 )     (292 )
Distributions
                                              (53,557 )           (53,557 )     (6,600 )     (60,157 )
                                                                         
Balances, December 31, 2004
                                              22,153       18,828       40,981       4,952       45,933  
Noncash distribution of Virginia Tax Credit
                                                                (40 )     (40 )
Net income prior to Internal Restructuring
                                                    2,320       2,320       379       2,699  
Distribution to First Reserve Fund IX, L.P. and ANR Fund IX Holdings, L.P. prior to the Internal Restructuring
                                                    (7,920 )     (7,920 )     (1,243 )     (9,163 )
Contribution by First Reserve Fund IX, L.P. of all of the outstanding common stock of Alpha NR Holding, Inc. in exchange for shares of Alpha Natural Resources, Inc. common stock
    12,463       125       35,256                   35,381             (22,153 )     (13,228 )     (35,381 )            
Contribution by ANR Fund IX Holdings, L.P. of its membership interest in ANR Holdings, LLC in exchange for shares of Alpha Natural Resources, Inc. common stock upon completion of the Internal Restructuring
    1,536       15       4,033                   4,048                               (4,048 )      
See accompanying notes to consolidated financial statements.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND PARTNERS’ CAPITAL
                                                                                                 
            ANR Fund IX    
    Alpha Natural Resources, Inc.   Alpha NR Holding, Inc.   Holdings, L.P.    
                Total
                Retained           Stockholders’
    Common Stock   Additional   Unearned       Total       Additional   Earnings   Total       Equity and
        Paid-In   Stock-Based   Retained   Stockholders’   Common   Paid-In   (Accumulated   Stockholder’s   Partners’   Partners’
    Shares   Amount   Capital   Compensation   Earnings   Equity   Stock   Capital   Deficit)   Equity   Capital   Capital
                                                 
    (In thousands, except per share amounts)
Contribution by minority interest holders, including certain members of management, of their membership interests in ANR Holdings, LLC in exchange for shares of Alpha Natural Resources, Inc. common stock and recognition of unearned stock-based compensation
    14,289       143       85,424       (29,122 )           56,445                                     56,445  
Issuance of Restructuring Notes
                (517,692 )                 (517,692 )                                   (517,692 )
Tax Distributions payable recorded upon the completion of the Internal Restructuring
                (10,500 )                 (10,500 )                                   (10,500 )
Change in net deferred income taxes recognized upon the completion of the Internal Restructuring
                34,504                   34,504                                     34,504  
Proceeds from initial public offering of common shares ($19 per share), net of offering costs of $48,296
    33,925       339       596,072                   596,411                                     596,411  
Distribution of net proceeds received from underwriters’ exercise of over-allotment option
                (71,135 )                 (71,135 )                                   (71,135 )
Issuance of restricted shares
    12             330       (330 )                                                
Shares issued in connection with acquisition
    2,180       22       53,162                   53,184                                     53,184  
Amortization of unearned stock-based compensation
                      13,407             13,407                                     13,407  
Exercise of stock options
    15               199                   199                                     199  
Cancellation of nonvested stock options
                (443 )     443                                                  
Net income subsequent to Internal Restructuring
                            18,513       18,513                                     18,513  
                                                                         
Balances, December 31, 2005
  $ 64,420     $ 644     $ 209,210     $ (15,602 )   $ 18,513     $ 212,765     $     $     $     $     $     $ 212,765  
                                                                         
See accompanying notes to consolidated financial statements.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 
    Year Ended December 31,
     
    2005   2004   2003
             
    (In thousands)
Operating activities:
                       
 
Net income
  $ 21,213     $ 20,015     $ 2,262  
 
Adjustments to reconcile net income to net cash provided by operating activities:
                       
   
Depreciation, depletion and amortization
    73,405       56,012       36,054  
   
Amortization and write-off of debt issuance costs
    3,357       4,474       1,276  
   
Minority interest
    2,846       19,830       934  
   
Accretion of asset retirement obligation
    3,514       3,301       2,699  
   
Virginia tax credit
    (343 )     (4,872 )     (4,313 )
   
Stock-based compensation — non-cash
    39,045       91        
   
Gain on sale of discontinued operations
    (704 )            
   
Impairment charge
          5,100        
   
Deferred income taxes
    3,736       2,711       668  
   
Other non-cash items
    (515 )     42       (550 )
   
Changes in operating assets and liabilities:
                       
     
Trade accounts receivable
    (52,102 )     (25,775 )     (21,056 )
     
Notes and other receivables
    13,276       (1,062 )     (2,358 )
     
Inventories
    (24,279 )     (21,040 )     13,014  
     
Prepaid expenses and other current assets
    12,445       5,568       793  
     
Other assets
    (6,033 )     805       (3,051 )
     
Trade accounts payable
    48,462       9,742       12,234  
     
Accrued expenses and other current liabilities
    5,453       27,243       16,392  
     
Workers’ compensation benefits
    1,155       3,018       1,660  
     
Postretirement medical benefits
    8,824       4,975       1,236  
     
Asset retirement obligation expenditures
    (4,142 )     (3,306 )     (2,252 )
     
Other liabilities
    1,030       (96 )     (1,538 )
                   
       
Net cash provided by operating activities
    149,643       106,776       54,104  
                   
Investing activities:
                       
 
Capital expenditures
    (122,342 )     (72,046 )     (27,719 )
 
Proceeds from disposition of property, plant, and equipment
    5,450       1,096       65,174  
 
Purchase of net assets of acquired companies
    (221,869 )     (2,891 )     (133,757 )
 
Equity investment
    (1,234 )     (4,500 )      
 
Issuance of note receivable to coal supplier
          (10,000 )      
 
Collections on note receivable from coal supplier
    5,608       1,519        
 
Payment of additional consideration on previous acquisition
    (5,000 )     0        
 
Decrease (increase) in due from affiliate
          620       (3,770 )
                   
       
Net cash used in investing activities
    (339,387 )     (86,202 )     (100,072 )
                   
See accompanying notes to consolidated financial statements.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
                             
    Year Ended December 31,
     
    2005   2004   2003
             
    (In thousands)
Financing activities:
                       
 
Repayments of notes payable
    (15,228 )     (14,425 )     (15,600 )
 
Proceeds from issuance of long-term debt
    323,000       175,000       58,518  
 
Repayments on long-term debt
    (82,743 )     (61,422 )     (30,054 )
 
Increase in bank overdraft
    7,041       4,170       5,854  
 
Proceeds from initial public offering, net of offering costs
    598,066              
 
Repayment of restructuring notes payable
    (517,692 )            
 
Distributions to prior members of ANR Holdings, LLC subsequent to Internal Restructuring
    (71,135 )            
 
Payment of Sponsor Distributions related to Internal Restructuring
    (3,600 )            
 
Distributions to prior members of ANR Holdings, LLC prior to Internal Restructuring
    (7,732 )     (115,572 )     (3,085 )
 
Debt issuance costs
    (8,201 )     (10,525 )     (5,181 )
 
Advances from affiliates
                20,047  
 
Capital contributions
                3,118  
 
Issuance of common stock
                15,153  
 
Other
    199       (1,655 )      
                   
   
Net cash provided by (used in) financing activities
    221,975       (24,429 )     48,770  
                   
Net increase (decrease) in cash and cash equivalents
    32,231       (3,855 )     2,802  
Cash and cash equivalents at beginning of period
    7,391       11,246       8,444  
                   
Cash and cash equivalents at end of period
  $ 39,622     $ 7,391     $ 11,246  
                   
See accompanying notes to consolidated financial statements.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except percentages and share data)
(1) Business and Basis of Presentation
Organization and Business
      Alpha Natural Resources, Inc. and its operating subsidiaries are engaged in the business of extracting, processing and marketing coal from deep and surface mines, located in the Central and Northern Appalachian regions of the United States, for sale to utility and steel companies in the United States and in international markets.
      On February 11, 2005, Alpha Natural Resources, Inc., a Delaware corporation (Alpha) succeeded to the business of ANR Holdings, LLC, a Delaware limited liability company (ANR Holdings) in a series of internal restructuring transactions, and on February 18, 2005, Alpha completed the initial public offering of its common stock. The internal restructuring and initial public offering are discussed in Note (2). Prior to the internal restructuring transactions, ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. (the FR Affiliates), entities under the common control of First Reserve GP IX, Inc., were the owners of 54.7% of the membership interests in ANR Holdings, and the remaining membership interests in ANR Holdings were held by affiliates of American Metals & Coal International, Inc. (AMCI), Alpha Coal Management, LLC (ACM) and Madison Capital Funding, LLC.
      The FR Affiliates were entities under the common control of First Reserve GP IX, Inc. and were formed in 2002 to acquire coal mining assets in the Appalachian region of the United States. In December 2002, the FR Affiliates formed ANR Holdings, LLC (ANR Holdings). ANR Holdings was the parent of Alpha Natural Resources, LLC and the latter entity and its subsidiaries acquired our predecessor, the majority of the Virginia coal operations of Pittston Coal Company, a subsidiary of The Brink’s Company (formerly known as The Pittston Company), on December 13, 2002.
      The acquisition of Coastal Coal Company, LLC was completed on January 31, 2003 by subsidiaries of ANR Holdings. The acquisition of the majority of the North American operations of American Metals and Coal International, Inc. (U.S. AMCI) was completed on March 11, 2003. Concurrent with the acquisition of U.S. AMCI, ANR Holdings issued additional membership interests in the aggregate amount of 45.3% to the former owners of U.S. AMCI, Madison Capital Funding, LLC and members of management in exchange for the net assets of U.S. AMCI and cash. After completion of this transaction, the FR Affiliates owned 54.7% of ANR Holdings.
      Other major acquisitions include the acquisition of Mears Enterprises, Inc. and affiliated entities on November 17, 2003, and the acquisition of the Nicewonder Coal Group on October 26, 2005. See Note 21 for further discussion concerning these acquisitions.
Basis of Presentation
      The financial statements for the year ended December 31, 2005 include the combined financial results for the FR Affiliates and subsidiaries for the period from January 1, 2005 to February 11, 2005, and the consolidated results for Alpha and subsidiaries from February 12, 2005 to December 31, 2005. The financial statements for the years ended December 31, 2003 and 2004 are presented on a combined basis including the combined financial results for the FR Affiliates and subsidiaries. The entities included in the financial statements are collectively referred to as “the Company”.
      On April 14, 2005, the Company sold the assets of its Colorado mining subsidiary, National King Coal LLC, and related trucking subsidiary, Gallup Transloading Company LLC, to an unrelated third party. The results of these operations for the years ended December 31, 2005, 2004 and 2003 have been reported as discontinued operations. See also Note 25.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(2) Internal Restructuring and Public Offerings
      On February 11, 2005, the Company completed a series of transactions to transition from a structure in which the Company’s top-tier holding company was a limited liability company, ANR Holdings, to one in which the top-tier holding company is a corporation, Alpha Natural Resources, Inc., which was formed on November 29, 2004. These transactions are referred to collectively as the Internal Restructuring, and they included the following:
  •  Alpha Coal Management, LLC (ACM) was dissolved and liquidated, after which (1) the interests in ANR Holdings previously held by ACM were distributed to and held directly by the Company’s officers and employees who were owners of ACM prior to its dissolution and (2) outstanding options to purchase units in ACM were automatically converted into options to purchase up to 596,985 shares of Alpha Natural Resources, Inc. common stock at an exercise price of $12.73 per share, and Alpha Natural Resources, Inc. assumed the obligations of ACM under the Alpha Coal Management, LLC 2004 Long-Term Incentive Plan.
 
  •  Alpha Natural Resources, Inc. assumed the obligations of ANR Holdings to make distributions to (1) affiliates of AMCI in an aggregate amount of $6,000, representing the approximate incremental tax resulting from the recognition of additional tax liability resulting from the Internal Restructuring and (2) First Reserve Fund IX, L.P. in an aggregate amount of approximately $4,500, representing the approximate value of tax attributes conveyed as a result of the Internal Restructuring (collectively, the Sponsor Distributions). The Sponsor Distributions to affiliates of AMCI are payable in five equal installments on the dates for which estimated income tax payments are due in each of April 2005, June 2005, September 2005, January 2006 and April 2006. The Sponsor Distributions to First Reserve Fund IX, L.P. are payable in three installments of approximately $2,100, $2,100 and $300 on December 15, 2007, 2008 and 2009, respectively. The Sponsor Distributions will be payable in cash or, to the extent Alpha Natural Resources, Inc. is not permitted by the terms of the senior credit facility or the indenture governing the senior notes to pay the Sponsor Distributions in cash, in shares of Alpha Natural Resources, Inc. common stock.
 
  •  First Reserve Fund IX, L.P., the direct parent of Alpha NR Holding, Inc., contributed all of the outstanding common stock of Alpha NR Holding, Inc. to Alpha Natural Resources, Inc. in exchange for 12,462,992 shares of Alpha Natural Resources, Inc. common stock and demand promissory notes in an aggregate adjusted principal amount of $206,734.
 
  •  ANR Fund IX Holdings, L.P., Madison Capital Funding, LLC and affiliates of AMCI contributed all of their membership interests in ANR Holdings to Alpha Natural Resources, Inc. in exchange for 13,052,431 shares of Alpha Natural Resources, Inc. common stock and demand promissory notes in an aggregate adjusted principal amount of $310,958.
 
  •  The officers and employees who were the members of ACM contributed all of their interests in ANR Holdings to Alpha Natural Resources, Inc. in exchange for 2,772,157 shares of Alpha Natural Resources, Inc. common stock. Of these shares, 82,297 were for the officers’ and employees’ purchased interest. One half of the remainder, 1,344,930 shares, were immediately vested and resulted in compensation expense being recorded at $19 per share (based upon the initial public offering price for the Company’s stock on February 18, 2005), or $25,554 in total. The remaining 1,344,930 shares vest over the two year period ending December 31, 2006. The $25,554 in compensation expense related to these shares was deferred and is being amortized to expense over the vesting period.
 
  •  The Board of Directors of Alpha Natural Resources, Inc. declared a pro rata distribution to the former members of ANR Holdings in an aggregate amount equal to the net proceeds Alpha Natural Resources, Inc. received upon the exercise by the underwriters of their over-allotment option with respect to the public offering described below.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
  •  The Company, the FR Affiliates and affiliates of AMCI amended certain of the post-closing arrangements previously entered into as part of the Company’s acquisition of U.S. AMCI.
 
  •  Alpha Natural Resources, Inc. contributed the membership interests in ANR Holdings received in the Internal Restructuring to Alpha NR Holding, Inc. and another indirect wholly-owned subsidiary of Alpha Natural Resources, Inc.
      On February 18, 2005, Alpha Natural Resources, Inc. completed the initial public offering of 33,925,000 shares of its common stock, including 4,425,000 shares issued pursuant to the exercise in full of the underwriters’ over-allotment option. Alpha Natural Resources, Inc. received net proceeds (after deducting issuance costs) of $598,066 from the offering. Alpha Natural Resources, Inc. used $517,692 of the net proceeds to repay all outstanding principal and accrued interest on its demand promissory notes issued in the Internal Restructuring to the FR Affiliates, affiliates of AMCI and Madison Capital Funding LLC. In addition, $78,610 of the net proceeds were distributed by Alpha Natural Resources, Inc. on a pro rata basis to its stockholders of record as of the close of business on February 11, 2005 pursuant to the distribution declared by Alpha Natural Resources, Inc.’s Board of Directors in connection with the Internal Restructuring. Included in the pro rata distribution was $7,475 distributed to officers and employees who were the members of ACM, which was recorded as compensation expense.
      On January 24, 2006, a secondary public offering of the common stock of Alpha Natural Resources, Inc. was completed in which an aggregate of 14,163,527 shares of its common stock were sold by First Reserve Fund IX, L.P., ANR Fund IX Holdings, L.P. and Madison Capital Funding, LLC. The Company received no proceeds from the secondary offering.
(3) Summary of Significant Accounting Policies and Practices
     (a) Cash and Cash Equivalents
      Cash and cash equivalents consist of cash and highly liquid, short-term investments. Cash and cash equivalents are stated at cost, which approximates fair market value. The Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.
     (b) Trade Accounts Receivable and Allowance for Doubtful Accounts
      Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company establishes provisions for losses on accounts receivable when it is probable that all or part of the outstanding balance will not be collected. The Company regularly reviews collectibility and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The allowance for doubtful accounts was $25 and $93 at December 31, 2005 and 2004, respectively. Credit losses were insignificant in the three-year period ending December 31, 2005. The Company does not have off-balance-sheet credit exposure related to its customers.
     (c) Inventories
      Coal inventories are stated at the lower of cost or market. The cost of coal inventories is determined based on average cost of production, which includes all costs incurred to extract, transport and process the coal. Coal is classified as inventory at the point in time the coal is extracted from the mine and weighed at a loading facility.
      Material and supplies inventories are valued at average cost, less an allowance for obsolete and surplus items.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
     (d) Property, Plant, and Equipment
      Costs for mineral properties, mineral rights, and mine development incurred to expand capacity of operating mines or to develop new mines are capitalized and charged to operations on the units-of-production method over the estimated proven and probable reserve tons. Mine development costs include costs incurred for site preparation and development of the mines during the development stage. Mobile mining equipment and other fixed assets are stated at cost and depreciated on a straight-line basis over estimated useful lives ranging from 2 to 20 years. Leasehold improvements are amortized, using the straight-line method, over their estimated useful lives or the term of the lease, whichever is shorter. Major repairs and betterments that significantly extend original useful lives or improve productivity are capitalized and depreciated over the period benefited. Maintenance and repairs are expensed as incurred.
     (e) Impairment of Long-Lived Assets
      In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-lived Assets, long-lived assets, such as property, plant, equipment, and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and would no longer be depreciated. The assets and liabilities of a disposal group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.
     (f) Goodwill
      Goodwill represents the excess of costs over fair value of net assets of businesses acquired. Pursuant to SFAS No. 142, Goodwill and Other Intangible Assets, goodwill and intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142. The Company performs its impairment test in August of each year. The impairment review in August 2005 supported the carrying value of goodwill.
     (g) Health Insurance Programs
      The Company is principally self-insured for costs of health and medical claims. The Company utilizes commercial insurance to cover specific claims in excess of $500 ($250 prior to January 1, 2005).
     (h) Income Taxes
      The Company accounts for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which those items are expected to reverse.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
     (i) Asset Retirement Obligation
      Minimum standards for mine reclamation have been established by various regulatory agencies and dictate the reclamation requirements at the Company’s operations. The Company records these reclamation obligations under the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which the legal obligation associated with the retirement of the long-lived asset is incurred. When the liability is initially recorded, the offset is capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. To settle the liability, the obligation is paid, and to the extent there is a difference between the liability and the amount of cash paid, a gain or loss upon settlement is recorded. The Company annually reviews its estimated future cash flows for its asset retirement obligations.
      In connection with the business acquisitions described in Note 21, the Company recorded the fair value of the reclamation liabilities assumed as part of the acquisitions in accordance with SFAS No. 143.
     (j) Royalties
      Lease rights to coal lands are often acquired in exchange for royalty payments. Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable against future production. These advance payments are deferred and charged to operations as the coal reserves are mined. The Company regularly reviews recoverability of advance mining royalties and establishes or adjusts the allowance for advance mining royalties as necessary using the specific identification method. In instances where advance payments are not expected to be offset against future production royalties, the Company establishes a provision for losses on the advance payments that have been paid and the scheduled future minimum payments are expensed and recognized as liabilities. Advance royalty balances are charged off against the allowance when the lease rights are either terminated or expire.
      The changes in the allowance for advance mining royalties were as follows:
         
Balance at December 31, 2002
  $  
Additions associated with acquisitions
    4,694  
       
Balance at December 31, 2003
    4,694  
Provision for non-recoupable advance mining royalties
    758  
Write-offs of advance mining royalties
    (11 )
       
Balance at December 31, 2004
    5,441  
Provision for non-recoupable advance mining royalties
    580  
Write-offs of advance mining royalties
    (1,191 )
       
Balance at December 31, 2005
  $ 4,830  
       
     (k) Revenue Recognition
      The Company recognizes revenue on coal sales when title passes to the customer in accordance with the terms of the sales agreement. Revenue from domestic coal sales is recorded at the time of shipment or delivery to the customer, and the customer takes ownership and assumes risk of loss based on shipping terms. Revenue from international coal sales is recorded at the time coal is loaded onto the shipping vessel, when the customer takes ownership and assumes risk of loss. In the event that new contracts are negotiated with a customer and shipments commence before the old contract is complete, the Company recognizes as revenue the lower of the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
cumulative amount billed or an amount based on the weighted average price of the new and old contracts applied to the tons sold.
      Freight and handling costs paid to third-party carriers and invoiced to coal customers are recorded as freight and handling costs and freight and handling revenues, respectively.
      Other revenues generally consist of equipment and parts sales, equipment rebuild and maintenance services, coal handling and processing, trucking services for unrelated parties, royalties, commissions on coal trades, and rental income. These revenues are recognized in the period earned or when the service is completed. Beginning on October 26, 2005, the Company began earning revenues from the operation of a highway construction business which was acquired as part of the acquisition of the Nicewonder Coal Group (Note 21). Revenues from this business are recognized under the percentage of completion method.
     (l) Deferred Financing Costs
      In connection with obtaining financing, the Company incurred deferred financing costs totaling $8,201, $10,525 and $5,181 during the years ended December 31, 2005, 2004 and 2003, respectively. These deferred financing costs are being amortized to interest expense over the life of the related indebtedness or credit facility. Unamortized deferred financing costs are included in other assets in the accompanying balance sheets. Amortization expense for the years ended December 31, 2005, 2004 and 2003 totaled $3,357, $4,474 and $1,276, respectively. Amortization for the years ended December 31, 2005 and 2004 included $1,503 and $2,819, respectively, for deferred financing costs written off in connection with refinancing transactions. See Note 13.
     (m) Virginia Coalfield Employment Enhancement Tax Credit
      For tax years 1996 through 2007, Virginia companies with an economic interest in coal earn tax credits based upon tons sold, seam thickness, and employment levels. The maximum credit earned equals $0.40 per ton for surface mined coal and $1.00 or $2.00 per ton for deep mined coal depending on seam thickness. Credits allowable are reduced from the maximum amounts if employment levels are not maintained from the previous year, and no credit is allowed for coal sold to Virginia utilities. Currently, the cash benefit of the credit is realized three years after being earned and either offsets taxes imposed by Virginia at 100% or is refundable by the state at 85% of the face value to the extent taxes are not owed. The Company records the present value of the portion of the credit that is refundable as a reduction of operating costs as it is earned. Prior to the Internal Restructuring, the portion of the credits allocated to ANR Fund IX Holdings, L.P. and minority interest owners were recorded as noncash distributions.
     (n) Workers’ Compensation and Pneumoconiosis (Black Lung) Benefits
Workers’ Compensation
      The Company is self-insured for workers’ compensation claims at certain of its operations in West Virginia. Workers’ compensation at all other locations in West Virginia is insured through the West Virginia state insurance program. Workers’ compensation claims at locations in all other states where the Company operates are covered by a third-party insurance provider.
      The liabilities for workers’ compensation claims that are self-insured are estimates of the ultimate losses incurred based on the Company’s experience, and include a provision for incurred but not reported losses. Adjustments to the probable ultimate liabilities are made annually based on an actuarial study and adjustments to the liability are recorded based on the results of this study.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Black Lung Benefits
      The Company is required by federal and state statutes to provide benefits to employees for awards related to black lung disease. These claims are covered by a third-party insurance provider in all locations where the Company operates with the exception of West Virginia. The Company is self-insured for state black lung related claims at certain locations in West Virginia.
      The liabilities for state black lung related claims in West Virginia that are self-insured are estimates of the ultimate losses incurred based on the Company’s experience, and include a provision for incurred but not reported losses. Estimates of the liabilities are made annually based on an actuarial study and adjustments to the liability are recorded based on the results of this study.
      The Company did not assume any responsibility for workers’ compensation or black lung claims incurred by any of its subsidiaries prior to their acquisition.
     (o) Postretirement Benefits Other Than Pensions
      The Company accounts for health care and life insurance benefits provided for current and certain retired employees and their dependents by accruing the cost of such benefits over the service lives of employees. Unrecognized actuarial gains and losses are amortized over the estimated average remaining service period for active employees and over the estimated average remaining life for retirees.
     (p) Equity Investments
      The accompanying financial statements include the accounts of the Company and its majority owned subsidiaries. Investments in unconsolidated subsidiaries representing ownership of at least 20% but less than 50% are accounted for under the equity method. Under the equity method of accounting, the Company’s proportionate share of the investment company’s income is included in the Company’s net income or loss with a corresponding increase or decrease in the carrying value of the investment.
     (q) Equity-Based Compensation
      The Company accounts for equity-based compensation awards granted to employees in accordance with Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Compensation cost for stock option awards is recognized in an amount equal to the difference between the exercise price of the award and the fair value of the Company’s equity on the date of grant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The following table illustrates the effect on net income, as adjusted, and earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123 to equity-based employee compensation using the Black-Scholes option-pricing model for the years ended December 31, 2005 and December 31, 2004:
                 
    Year Ended December 31,
     
    2005   2004
         
Net income, as adjusted (Note 4)
  $ 21,124     $ 19,015  
Add: stock option expense included in net income, as adjusted, net of income taxes and minority interest
    484       50  
Deduct: stock option expense determined under fair-value method, net of income taxes and minority interest
    (1,322 )     (72 )
             
Pro forma net income, adjusted for effect of fair value of stock options
  $ 20,286     $ 18,993  
             
Earnings per share — basic and diluted
               
Net income, as adjusted (Note 4)
  $ 0.38     $ 1.36  
             
Pro forma net income, adjusted for effect of fair value of stock options
  $ 0.36     $ 1.36  
             
      In addition to the stock option expense reflected above, the Company recorded $45,875 in expense in 2005 for stock-based compensation other than stock options, for which the expense under SFAS No. 123 would have been the same. Such amount includes $7,475, representing a cash distribution to certain officers and employees of a portion of the net proceeds from the Company’s initial public offering attributable to the underwriters’ exercise of their over-allotment option. Substantially all of the remainder is non-cash expense attributable to shares issued in connection with the Internal Restructuring to certain officers and employees. See Note 2.
      The Company had not granted equity-based awards prior to November 2004. For purposes of the above, the weighted average fair value of stock options granted in the years ended December 31, 2005 and 2004 was estimated to be $6.42 and $9.04, respectively. The fair values of stock options granted in both years were estimated on the date of each grant using the Black-Scholes option pricing model with the following assumptions:
         
Expected life (years)
    4.0  
Expected volatility
    38.0 %
Risk-free interest rate
    3.38 %
Expected annual dividend
  $ 0.10  
      The effects on pro forma net income of expensing the estimated fair value of equity-based awards are not necessarily representative of the effects on reported net income for future periods due to such factors as the vesting periods of stock options and the potential issuance of additional awards in future years.
     (r) New Accounting Pronouncements
      In December 2004, the Financial Accounting Standards Board issued SFAS No. 123(R), Share-Based Payment, which requires companies to expense the fair value of equity awards over the required service period. This Statement is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123(R) supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, which uses the intrinsic value method to value stock-based compensation. On April 14, 2005, the Securities and Exchange Commission adopted a new rule that amends the effective date of SFAS No. 123(R) to allow registrants to implement SFAS No. 123(R) as of the beginning of the first annual reporting period that begins after June 15, 2005. The Company adopted SFAS No. 123(R) effective January 1, 2006 and used the modified prospective method, in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
which compensation cost is recognized beginning with the effective date based on the requirements of SFAS No. 123(R) for all share-based payments granted after the effective date and based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the effective date. The expected impact of applying the modified prospective method to unvested options as of January 1, 2006 is an increase to pre-tax expense of approximately $1,300 for the year ended December 31, 2006. Such amount could vary depending on the level of forfeitures that occur or other circumstances. The Company currently anticipates that it will utilize restricted stock for equity-based compensation in 2006 instead of stock option grants. Accounting for restricted stock awards is not impacted by SFAS No. 123(R).
      In March 2005, the Emerging Issues Task Force issued EITF Issue No. 04-6, “Accounting for Stripping Costs in the Mining Industry,” which states 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 Issue No. 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006 for the Company). The Company’s existing accounting practices are consistent with EITF Issue No. 04-06, therefore this pronouncement will not effect the Company’s results of operations or financial condition.
     (s) Use of Estimates
      The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant items subject to such estimates and assumptions include the allowance for doubtful accounts; inventories; mineral reserves; allowance for non-recoupable advance mining royalties; asset retirement obligations; employee benefit liabilities; future cash flows associated with assets; useful lives for depreciation, depletion, and amortization; workers’ compensation and black lung claims; postretirement benefits other than pensions; income taxes; and fair value of financial instruments. Due to the subjective nature of these estimates, actual results could differ from those estimates.
     (t) Reclassifications
      Certain prior period amounts have been reclassified to conform to the current year presentation.
(4) Earnings Per Share
      Basic earnings per share is computed by dividing net income or loss by the weighted average number of shares of common stock outstanding during the periods. Diluted earnings per share is computed by dividing net income or loss by the weighted average number of shares of common stock and dilutive common stock equivalents outstanding during the periods. Common stock equivalents include the number of shares issuable on exercise of outstanding options less the number of shares that could have been purchased with the proceeds from the exercise of the options based on the average price of common stock during the period. Due to the Internal Restructuring on February 11, 2005 and initial public offering of common stock completed on February 18, 2005, the calculation of earnings per share reflects certain adjustments, as described below.
      The numerator for purposes of computing basic and diluted net income (loss) per share, as adjusted, includes the reported net income (loss) and a pro forma adjustment for income taxes to reflect the pro forma income taxes for ANR Fund IX Holdings, L.P.’s portion of reported pre-tax income (loss), which would have been recorded if the issuance of the shares of common stock received by the FR Affiliates in exchange for their ownership in ANR Holdings in connection with the Internal Restructuring had occurred as of January 1, 2003. For purposes of the computation of basic and diluted net income (loss) per share, as adjusted, the pro

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
forma adjustment for income taxes only applies to the percentage interest owned by ANR Fund IX Holding, L.P., the non-taxable FR Affiliate. No pro forma adjustment for income taxes is required for the percentage interest owned by Alpha NR Holding, Inc., the taxable FR Affiliate, because income taxes have already been recorded in the historical results of operations. Furthermore, no pro forma adjustment to reported net income (loss) is necessary subsequent to February 11, 2005 because Alpha is subject to income taxes.
      The denominator for purposes of computing basic net income (loss) per share, as adjusted, reflects the retroactive impact of the common shares received by the FR Affiliates in exchange for their ownership in ANR Holdings in connection with the Internal Restructuring on a weighted-average outstanding share basis as being outstanding as of January 1, 2003. The common shares issued to the minority interest owners of ANR Holdings in connection with the Internal Restructuring, including the immediately vested shares granted to management, have been reflected as being outstanding as of February 11, 2005 for purposes of computing the basic net income (loss) per share, as adjusted. The unvested shares granted to management on February 11, 2005 that vest monthly over the two-year period from January 1, 2005 to December 31, 2006 are included in the basic net income (loss) per share, as adjusted, computation as they vest on a weighted-average outstanding share basis starting on February 11, 2005. The 33,925,000 new shares issued in connection with the initial public offering have been reflected as being outstanding since February 14, 2005, the date of the initial public offering, for purposes of computing the basic net income (loss) per share, as adjusted.
      The unvested shares issued to management are considered options for purposes of computing diluted net income (loss) per share, as adjusted. Therefore, for diluted purposes, all remaining unvested shares granted to management are added to the denominator subsequent to February 11, 2005 using the treasury stock method, if the effect is dilutive. In addition, the treasury stock method is used for outstanding stock options, if dilutive, beginning with the November 10, 2004 grant of options to management to purchase units in ACM that were automatically converted into options to purchase up to 596,985 shares of Alpha Natural Resources, Inc. common stock at an exercise price of $12.73 per share.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The computations of basic and diluted net income (loss) per share, as adjusted, are set forth below:
                           
    Year Ended December 31,
     
    2005   2004   2003
             
Numerator:
                       
 
Reported income from continuing operations
  $ 21,426     $ 22,388     $ 2,752  
 
Deduct: Income tax effect of ANR Fund IX Holdings, L.P. income from continuing operations prior to Internal Restructuring
    (91 )     (1,149 )     (138 )
                   
 
Income from continuing operations, as adjusted
    21,335       21,239       2,614  
                   
 
Reported loss from discontinued operations
    (213 )     (2,373 )     (490 )
 
Add: Income tax effect of ANR Fund IX Holdings, L.P. loss from discontinued operations prior to Internal Restructuring
    2       149       27  
                   
 
Loss from discontinued operations, as adjusted
    (211 )     (2,224 )     (463 )
                   
 
Net income, as adjusted
  $ 21,124     $ 19,015     $ 2,151  
                   
Denominator:
                       
 
Weighted average shares — basic
    55,664,081       13,998,911       13,998,911  
 
Dilutive effect of stock options and restricted stock grants
    385,465              
                   
 
Weighted average shares — diluted
    56,049,546       13,998,911       13,998,911  
                   
Net income per share, as adjusted — basic and diluted:
                       
 
Income from continuing operations, as adjusted
  $ 0.38     $ 1.52     $ 0.19  
 
Loss from discontinued operations, as adjusted
          (0.16 )     (0.04 )
                   
 
Net income per share, as adjusted
  $ 0.38     $ 1.36     $ 0.15  
                   
(5) Inventories
      Inventories consisted of the following:
                   
    December 31,
     
    2005   2004
         
Raw coal
  $ 6,401     $ 3,888  
Saleable coal
    65,318       42,899  
Materials and supplies
    13,166       7,782  
             
 
Total inventories
  $ 84,885     $ 54,569  
             

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(6) Prepaid Expenses and Other Current Assets
      Prepaid expenses and other current assets consisted of the following:
                   
    December 31,
     
    2005   2004
         
Prepaid insurance
  $ 20,448     $ 16,577  
Advance mining royalties
    3,435       4,831  
Refundable income taxes
    6,012       2,798  
Other prepaid expenses
    6,222       4,709  
             
 
Total prepaid expenses and other current assets
  $ 36,117     $ 28,915  
             
(7) Property, Plant, and Equipment
      Property, plant, and equipment consisted of the following:
                   
    December 31,
     
    2005   2004
         
Land
  $ 11,986     $ 5,380  
Mineral rights
    297,573       85,245  
Plant and mining equipment
    372,189       188,891  
Vehicles
    3,351       2,058  
Mine development
    39,017       11,205  
Office equipment and software
    8,170       7,264  
Construction in progress
    5,419       1,769  
             
      737,705       301,812  
Less accumulated depreciation, depletion, and amortization
    154,955       83,848  
             
 
Property, plant, and equipment, net
  $ 582,750     $ 217,964  
             
      As of December 31, 2005, the Company had commitments to purchase approximately $64,342 of new equipment, expected to be acquired at various dates in 2006.
      Depreciation and amortization expense associated with property, plant and equipment was $60,502, $50,679 and $28,438, and depletion expense was $11,698, $3,541 and $2,396, for the years ended December 31, 2005, 2004 and 2003, respectively.
(8) Goodwill
      The changes in the carrying amount of goodwill were as follows:
         
Balance as of December 31, 2002
  $  
Acquisition of U.S. AMCI
    17,121  
       
Balance as of December 31, 2003
    17,121  
2004 Adjustments
    1,520  
       
Balance as of December 31, 2004 and 2005
  $ 18,641  
       
      The carrying amount of goodwill was increased by $1,520 during the year ended December 31, 2004 due to the final settlement of the amount of working capital acquired in the U.S. AMCI acquisition. See Note 19.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(9) Other Intangibles
      Other intangible assets consisted of the following:
                                 
    December 31, 2005   December 31, 2004
         
    Gross Carrying   Accumulated   Gross Carrying   Accumulated
    Amount   Amortization   Amount   Amortization
                 
Sales contracts
  $ 7,227     $ 1,757     $ 3,248     $ 2,249  
Customer relationships
    4,762       159              
Noncompete agreements
    1,177       236       250       94  
                         
    $ 13,166     $ 2,152     $ 3,498     $ 2,343  
                         
      Total amortization expense for the above intangible assets was $1,205, $1,792 and $5,220 for the years ended December 31, 2005, 2004 and 2003, respectively, and is expected to be approximately $3,244, $2,264, $2,323, $1,896 and $1,308 for the years ended December 31, 2006, 2007, 2008, 2009 and 2010, respectively.
(10) Other Assets
      Other assets consisted of the following:
                   
    December 31,
     
    2005   2004
         
Advance mining royalties, net
  $ 11,557     $ 8,841  
Deferred loan costs, net
    15,081       10,237  
Deferred common stock offering costs
          3,665  
Notes receivable
    102       3,451  
Investment in terminaling facility
    1,005       1,005  
Investment in Excelven Pty Ltd
    5,735       4,500  
Virginia tax credit receivable
    9,418       4,806  
Other
    473       321  
             
 
Total other assets
  $ 43,371     $ 36,826  
             
(11) Notes Payable
      At December 31, 2005, notes payable included $39,955 in promissory installment notes that were issued in connection with the Nicewonder Acquisition (Note 21). The notes bore interest at 3.82% and were repaid on January 13, 2006. Also at December 31, 2005, notes payable included $19,059 of short-term indebtedness that was incurred to finance various insurance premiums. Interest, which accrues at the rate of 5.5%, and principal are due in monthly installments, with the final payment due in November 2006. At December 31, 2004 notes payable consisted entirely of indebtedness incurred to finance insurance premiums, all of which was repaid in 2005.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(12) Accrued Expenses and Other Current Liabilities
      Accrued expenses and other current liabilities consisted of the following:
                   
    December 31,
     
    2005   2004
         
Wages and employee benefits
  $ 24,874     $ 20,201  
Current portion of asset retirement obligation
    7,190       6,691  
Taxes other than income taxes
    10,697       6,136  
Freight
    9,717       12,376  
Contractor escrow
    771       1,615  
Deferred gains on sales of property interests
    941       808  
Deferred revenues
    4,589       1,086  
Current portion of self-insured workers’ compensation benefits
    1,019       911  
Workers’ compensation insurance premium payable
    4,320       3,567  
Interest payable
    3,944       1,632  
Additional consideration for acquisition
    13,738       5,000  
Accrued initial public offering costs
          2,010  
Other
    11,731       6,250  
             
 
Total accrued expenses and other current liabilities
  $ 93,531     $ 68,283  
             
(13) Long-Term Debt
      Long-term debt consisted of the following:
                     
    December 31,
     
    2005   2004
         
Term loan
  $ 250,000     $  
10% Senior notes due 2012
    175,000       175,000  
Revolving credit facility
          8,000  
Variable rate term notes
    293       1,466  
Capital lease obligation
    1,496       1,995  
Other
          16  
             
   
Total long-term debt
    426,789       186,477  
 
Less current portion
    3,242       1,693  
             
   
Long-term debt, net of current portion
  $ 423,547     $ 184,784  
             
Debt Refinancing
      On October 26, 2005, in connection with the Nicewonder Acquisition, Alpha NR Holding, Inc. (a wholly owned subsidiary of Alpha) and its wholly owned subsidiary, Alpha Natural Resources, LLC, entered into a senior secured credit facility with a group of lending institutions led by Citicorp North America, Inc., as administrative agent (the “New Citicorp Credit Facility”). The New Citicorp Credit Facility consists of a $250,000 term loan facility and a $275,000 revolving credit facility. The revolving credit facility includes borrowing capacity available for letters of credit. Proceeds from the New Citicorp Credit Facility were used to fund the cash portion of the Nicewonder Acquisition, including the payment of the first installment on the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
promissory notes on November 2, 2005, to refinance the existing Citicorp Credit Facility and to pay certain expenses related to the Nicewonder Acquisition and debt refinancing. As of December 31, 2005 there were $250,000 in borrowings under the term loan facility and no borrowings under the revolving credit facility. In addition, there were $65,487 in letters of credit outstanding, $50,000 of which resulted from conversion of funded letters of credit that were outstanding under the existing Citicorp Credit Facility, and $209,513 was available for borrowing.
      Borrowings under the New Citicorp Credit Facility bear interest at variable rates based upon, at the Company’s option, either the prime rate or a London Interbank Offered Rate (LIBOR), in each case plus a spread that is generally dependent on a leverage ratio. The Company is required to pay a commitment fee on the unused portion of the revolving credit facility, as well as customary letter of credit fees. The commitment fee is currently 0.50% per annum but may be reduced in the future subject to the attainment of certain leverage ratios. As of December 31, 2005, the weighted average interest rate applicable to borrowings under the term loan facility was 6.32%.
      Under the term loan facility, quarterly principal payments of $625 are required, commencing on March 31, 2006 and ending on September 30, 2012. The remaining unpaid principal, which is projected to be $233,125, is due and payable on October 26, 2012. Any outstanding principal amounts outstanding under the revolving credit facility are due and payable on October 26, 2010.
      All obligations under the New Citicorp Credit Facility are unconditionally guaranteed by Alpha NR Holding, Inc. and each of its existing and future direct and indirect domestic subsidiaries (other than the borrower, Alpha Natural Resources, LLC), and are secured by substantially all of the assets of Alpha NR Holding, Inc. and its subsidiaries. The New Citicorp Credit Facility contains various affirmative and negative covenants which, among other things, require the Company to maintain certain leverage and interest coverage ratios, and restrict certain payments and transactions, including dividends, payments for the repurchase of capital stock and mergers or consolidations.
10% Senior Notes Due June 2012
      On May 18, 2004, Alpha Natural Resources, LLC and its wholly-owned subsidiary, Alpha Natural Resources Capital Corp., issued $175,000 of 10% senior notes due June 2012 in a private placement offering under Rule 144A of the Securities Act of 1933, as amended, resulting in net proceeds of approximately $171,500 after fees and other offering costs. The senior notes are unsecured but are guaranteed fully and unconditionally on a joint and several basis by all of Alpha’s wholly-owned domestic restricted subsidiaries other than the issuers of the notes. The senior notes are the Company’s senior unsecured obligations and rank equally in right of payment to any existing and future unsecured indebtedness and rank senior in right of payment to any future subordinated or senior subordinated indebtedness. The senior notes are effectively subordinated in right of payment to the Company’s secured indebtedness, including borrowings under the New Citicorp Credit Facility. Interest on the senior notes is payable semi-annually in June and December.
      The senior notes may be redeemed in whole or in part on or after June 1, 2008 at the prices described in the governing indenture. In addition, the indenture provides for the redemption of up to 35% of the aggregate principal amount of senior notes for 110% of the principal amount of the senior notes with the net proceeds of certain underwritten equity offerings. Any of the senior notes may be redeemed at any time before June 1, 2008 in cash at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium.
      The indenture governing the senior notes contains covenants that, amount other things, limit the ability of the Company to incur additional indebtedness, make certain payments, including dividends, make certain investments, and sell certain assets or merge with or into other companies.

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Prior Senior Credit Facilities
      On May 28, 2004, Alpha entered into a new revolving credit facility with a group of lending institutions led by Citicorp North America, Inc., as administrative agent (Citicorp Credit Facility). The Citicorp Credit Facility was terminated on October 26, 2005 in connection with the debt refinancing discussed above. The Citicorp Credit Facility, as amended, provided for a revolving line of credit of up to $125,000 and a funded letter of credit facility of up to $50,000. Amounts drawn under the revolver bore interest at variable rates based upon either the prime rate or LIBOR, in each case plus a spread that was dependent on a leverage ratio. The obligations of Alpha, ANR Holdings and Alpha’s subsidiaries under the Citicorp Credit Facility were collateralized by all of the assets of Alpha, ANR Holdings and Alpha’s subsidiaries. The Company paid an annual commitment fee of up to 1/2 of 1% of the unused portion of the commitment.
      Prior to May 28, 2004, the Company had a term loan and revolving credit facility with a group of lending institutions led by PNC Bank (PNC). The term note had a variable interest rate and was payable in quarterly principal installments of $2,250 plus interest, with a final balloon payment due March 11, 2006. The PNC credit facility provided for a revolving line of credit of up to $75,000. Amounts drawn under the revolver had a variable interest rate and the principal balance of the revolving credit note was due March 11, 2006. ANR Holdings and each of the subsidiaries of the Company had guaranteed Alpha’s obligations under the credit facility. The Company paid an annual commitment fee of 1/2 of 1% of the unused portion of the commitment. The PNC term loan and credit facility were paid in full on May 28, 2004.
Other Indebtedness
      The Company has term notes payable to The CIT Group Equipment Financing, Inc. in the amount of $293 at December 31, 2005 and $1,466 at December 31, 2004. The term notes bear interest at variable rates (7.72% as of December 31, 2005) and are repayable in monthly installments through April 2, 2006.
      The Company entered into a capital lease for equipment in conjunction with the purchase of substantially all of the assets of Moravian Run Reclamation Co., Inc. on April 1, 2004. The lease has a term of sixty months with monthly payments ranging from $20 to $60 with a final balloon payment of $180 in March 2009. The effective interest rate on the capital lease is approximately 12.15%. The capitalized cost of the leased property was $1,874 at December 31, 2005. Accumulated amortization was $881 and $378 at December 31, 2005 and 2004, respectively. Amortization expense on capital leases is included with depreciation expense.
      In conjunction with the purchase of Coastal Coal Company, LLC, the Company issued a note payable to El Paso CGP on January 31, 2003. The balance of the note at December 31, 2003 was $8,000. The note had a fixed interest rate of 14% and was due on March 11, 2009. This note was paid in full in May 2004.
      In conjunction with the purchase of the U.S. coal production and marketing operations of AMCI (U.S. AMCI) on March 11, 2003, the Company assumed term notes payable to Komatsu Financial LP. The balance of the notes at December 31, 2003, was $3,719. The notes had fixed interest rates with a weighted average rate of 8.75% at December 31, 2003, and were payable in monthly installments ranging from $4 to $24, through August 1, 2006. These notes were paid in full in May 2004.
      In conjunction with the purchase of U.S. AMCI, the Company assumed term notes payable to the Caterpillar Financial Services Corporation. The balance of the notes at December 31, 2003, was $945. The notes had a fixed interest rate of 8.75% and were payable in monthly installments ranging from $9 to $25, through October 5, 2004. These notes were paid in full in May 2004.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Future maturities of long-term debt, including capital lease obligations, are as follows as of December 31, 2005:
             
Year ending December 31:
       
 
2006
  $ 3,242  
 
2007
    3,000  
 
2008
    2,816  
 
2009
    2,731  
 
2010
    2,500  
 
Thereafter
    412,500  
       
   
Total long-term debt
  $ 426,789  
       
      Following is a schedule of future minimum lease payments under capital lease obligations together with the present value of the net minimum lease payments as of December 31, 2005:
             
Year ending December 31:
       
 
2006
  $ 600  
 
2007
    600  
 
2008
    360  
 
2009
    240  
       
   
Total future minimum lease payments
    1,800  
Less amount representing interest
    (304 )
       
   
Present value of future minimum lease payments
    1,496  
Less current portion
    (449 )
       
   
Long-term capital lease obligation
  $ 1,047