SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Commission File No. 1-32423

ALPHA NATURAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code:

(276) 619-4410

Securities registered pursuant to Section 12(b) of the Act:

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.

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:

      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

PART I

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

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

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.

      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

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

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.

      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

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:

      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:

      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.

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.

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

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-

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

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:

      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:

        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.

        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.

      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

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.

      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:

      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 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:

      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.

      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

for it could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

      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.

      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:

      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.

      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.”

      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

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.

      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.

      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.

      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.

      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.

      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.

      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,

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 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.

      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

assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:

      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.

      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.

      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.

      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.

      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 coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to matters such as:

      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.

      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,

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 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.

      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

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.

      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.

      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).

      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

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.

      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:

      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

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.

      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.

      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.

      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:

                  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

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.

      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.

      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.

      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.

      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. 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

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.

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.

      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.

      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.

      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:

      See Item 1. Business, of this report for additional information regarding our coal operations and properties.

      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.

      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

      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.

      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

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

      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.

      EBITDA, as adjusted, is calculated as follows (unaudited, in thousands):

      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

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.

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.

      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.

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):

      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.

      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.

      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.

      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 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 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.

      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.