ALPHA NATURAL RESOURCES, INC.
 

 
 
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
     
(Mark One)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
    For the fiscal year ended December 31, 2004
 
OR
 
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
    For the transition period from           to
Commission File No. 1-32423
ALPHA NATURAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
     
Delaware
  02-0733940
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification Number)
 
406 West Main Street, Abingdon, Virginia
(Address of principal executive offices)
  24210
(Zip Code)
Registrant’s telephone number, including area code:
(276) 619-4410
Securities registered pursuant to Section 12(b) of the Act:
     
Title of Each Class   Name of Each Exchange on Which Registered
     
Common stock, $0.01 par value
  New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
      Indicate by check mark whether the registrant (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 o          No þ
      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.     þ
      Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).     Yes o          No þ
      The initial public offering of Alpha Natural Resources, Inc. common stock, $0.01 par value per share, commenced on February 15, 2005. There was no public market in the company’s common stock prior to that date.
      Common Stock, $0.01 par value, outstanding as of February 28, 2005 — 62,212,580 shares.
DOCUMENTS INCORPORATED BY REFERENCE
      Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2005 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, 2004.
 
 


 

CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS
      This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements, which involve risks and uncertainties, relate to analyses and other information that are based on forecasts of future results and estimates of amounts not yet determinable and may also relate to our future prospects, developments and business strategies. We have used the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project” and similar terms and phrases, including references to assumptions, in this report to identify forward-looking statements. These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those matters expressed in or implied by these forward-looking statements.
      The following factors are among those that may cause actual results to differ materially from our forward-looking statements:
  •  market demand for coal, electricity and steel;
 
  •  future economic or capital market conditions;
 
  •  weather conditions or catastrophic weather-related damage;
 
  •  our production capabilities;
 
  •  the consummation of financing, acquisition or disposition transactions and the effect thereof on our business;
 
  •  our plans and objectives for future operations and expansion or consolidation;
 
  •  our relationships with, and other conditions affecting, our customers;
 
  •  timing of reductions in customer coal inventories;
 
  •  long-term coal supply arrangements;
 
  •  inherent risks of coal mining beyond our control;
 
  •  environmental laws, including those directly affecting our coal mining and production, and those affecting our customers’ coal usage;
 
  •  competition in coal markets;
 
  •  railroad and other transportation performance and costs;
 
  •  our assumptions concerning economically recoverable coal reserve estimates;
 
  •  employee workforce factors;
 
  •  regulatory and court decisions;
 
  •  future legislation and changes in regulations, governmental policies or taxes;
 
  •  changes in postretirement benefit obligations;
 
  •  our liquidity, results of operations and financial condition; and
 
  •  other factors, including the other factors discussed in the “Risks Related to our Company” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” set forth in item 7 of this report.
      When considering these forward-looking statements, you should keep in mind the cautionary statements in this report and the documents incorporated by reference. We do not undertake any responsibility to release publicly any revisions to these forward-looking statements to take into account events or circumstances that occur after the date of this report. Additionally, we do not undertake any responsibility to update you on the occurrence of any unanticipated events which may cause actual results to differ from those expressed or implied by the forward-looking statements contained in this report.


 

2004 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
             
        Page
         
PART I
Item 1.
  Business     2  
Item 2.
  Properties     17  
Item 3.
  Legal Proceedings     21  
Item 4.
  Submission of Matters to a Vote of Security Holders     21  
Item 4A.
  Executive Officers of the Registrant     21  
PART II
Item 5.
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     23  
Item 6.
  Selected Financial Data     24  
Item 7.
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     28  
Item 7A.
  Quantitative and Qualitative Disclosures about Market Risk     63  
Item 8.
  Financial Statements and Supplementary Data     64  
Item 9.
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     112  
Item 9A.
  Controls and Procedures     112  
Item 9B.
  Other Information     112  
PART III
Item 10.
  Directors and Executive Officers of the Registrant     113  
Item 11.
  Executive Compensation     113  
Item 12.
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     113  
Item 13.
  Certain Relationships and Related Transactions     113  
Item 14.
  Principal Accounting Fees and Services     113  
PART IV
Item 15.
  Exhibits, Financial Statement Schedules     114  

1


 

PART I
Item 1. Business
Overview
      We are a leading Appalachian coal producer. Our reserves primarily consist of high Btu, low sulfur steam coal that is currently in high demand in U.S. coal markets and metallurgical coal that is currently in high demand in both U.S. and international coal markets. We produce, process and sell steam and metallurgical coal from eight regional business units, which, as of February 1, 2005, are supported by 44 active underground mines, 21 active surface mines and 11 preparation plants located throughout Virginia, West Virginia, Kentucky, Pennsylvania and Colorado. 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 2004 coal sales volume. The majority of our steam coal sales volume in 2004 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 2004 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 2004, we sold a total of 25.8 million tons of steam and metallurgical coal and generated revenues of $1,269.7 million, EBITDA, as adjusted, of $119.3 million and net income of $20.0 million. We define and reconcile EBITDA, as adjusted, and explain its importance, in note (2) under “Selected Financial Data.” Our coal sales during 2004 consisted of 19.4 million tons of produced and processed coal, including 0.9 million tons purchased from third parties and processed at our processing plants or loading facilities prior to resale, and 6.4 million tons of purchased coal that we resold without processing. We sold a total of 7.3 million tons of purchased coal in 2004, of which approximately 81% was blended with coal produced from our mines prior to resale. Approximately 47% 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.
      As of December 31, 2004, we owned or leased 511.1 million tons of proven and probable coal reserves. Of our total proven and probable reserves, approximately 89% are low sulfur reserves, with approximately 58% having sulfur content below 1.0%. Approximately 94% 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 25 years.
      As discussed in note 22 to our combined 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. Our equipment and part sales and equipment repairs operations, terminal services, coal analysis services and leasing of mineral rights 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

2


 

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, we acquired the majority of the Virginia coal operations of Pittston Coal Company, a subsidiary of The Brink’s Company (our “Predecessor”) for $62.9 million. On January 31, 2003, we acquired Coastal Coal Company, LLC (“Coastal Coal Company”) for $67.8 million, and on March 11, 2003, we acquired American Metals & Coal International, Inc.’s (“AMCI”) U.S. coal production and marketing operations for $121.3 million. Of the consideration for our acquisition of the U.S. coal production and marketing operations of AMCI (“U.S. AMCI”), $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 issuances of an approximate 1% membership interest to Madison Capital Funding LLC and Alpha Coal Management, LLC 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. and affiliated entities (collectively, “Mears”) for $38.0 million.
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 2004, approximately 82% of our produced coal volume 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.
      Surface Mining. Surface mining is used when coal is found close to the surface. In 2004, approximately 18% of our produced coal volume came from surface mines. This method involves the removal of overburden (earth and rock covering the coal) with heavy earth moving 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.

3


 

Coal Characteristics
      In general, coal of all geological compositions is characterized by end use as either steam coal or metallurgical coal. Heat value, sulfur, ash and moisture content, and coking characteristics such as fluidity, Audibert-Arnu dilatometer (ARNU) scores 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 511.1 million tons of proven and probable reserves, approximately 94% 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 and 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 and the region where it is mined. 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, three in West Virginia, one in Pennsylvania, one in Kentucky and one in Colorado. As of February 1, 2005, 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 65 active mines (some of which are operated by third parties under contracts with us), using two mining

4


 

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 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 2004, 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, with the exception of the National King Coal mine in Colorado, which does not have access to a preparation plant due to water restrictions, and therefore ships products raw. 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, 2005:
Regional Business Units
                                                 
            Number and Type of        
            Mines as of        
            February 1, 2005       2004
                    Production of
        Preparation plant(s) as of   Under-           Saleable Tons
Regional Business Unit   Location   February 1, 2005   ground   Surface   Total   Railroad   (in 000’s)(1)
                             
Paramont
  Virginia   Toms Creek     9       5       14       NS       5,876  
Dickenson-Russell
  Virginia   McClure River and Moss #3     7       1       8       CSX, NS       1,951  
Kingwood
  West Virginia   Whitetail     1       0       1       CSX       1,862  
Brooks Run
  West Virginia   Erbacon     3       0       3       CSX       1,987  
Welch
  West Virginia   Litwar, Kepler and Herndon     14       0       14       NS       2,401  
AMFIRE
  Pennsylvania   Clymer and Portage     6       14       20       NS       3,514  
Enterprise
  Kentucky   Roxana     3       1       4       CSX       1,477  
National King Coal
  Colorado   N/A     1       0       1       BN,UP       457  
                                       
        Total     44       21       65               19,525  
 
(1)  Includes coal purchased from third-party producers that was processed at our subsidiaries’ preparation plants in 2004.
CSX Railroad = CSX
Norfolk Southern Railroad = NS
Burlington Northern Santa Fe Railroad = BN
Union Pacific Railroad = UP
      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 to be operated by our Paramont business unit, Madison deep mine in Pennsylvania to be operated by our AMFIRE business unit, and Seven Pines surface mine and Cucumber deep mine in West Virginia to be operated by our Brooks Run business unit. We anticipate spending approximately $60.0 million developing these mines during 2005. We expect these mines to begin production at various times during 2005 and 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, 2005.
      Paramont. Our Paramont business unit produces coal from nine underground mines using continuous miners and the room and pillar mining method. Three of the underground mines are operated by independent

5


 

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 2004, Paramont purchased approximately 98,000 tons of coal from third parties that was blended with Paramont’s coal and shipped to our customers. As of February 1, 2005, 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 seven underground mines using continuous miners and the room and pillar mining method. Four 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 2004, Dickenson-Russell purchased approximately 3,000 tons of coal from third parties that was blended with Dickenson-Russell’s coal and shipped to our customers. As of February 1, 2005, 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 2004, Kingwood purchased approximately 44,000 tons of coal from third parties that was blended with Kingwood’s coal and shipped to our customers. As of February 1, 2005, 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 no surface mining operations and purchased no coal from third parties in 2004. As of February 1, 2005, 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 fourteen underground mines using continuous miners and the room and pillar mining method. Two 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, 2005. During 2004, the Welch business unit purchased approximately 503,000 tons of coal from third parties that was blended with other coals and shipped to our customers. As of February 1, 2005, the Welch business unit was operating at a capacity to ship approximately two and three-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 for shipment to customers. AMFIRE also operates fourteen truck/loader surface mines. Six of the surface mines 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 2004,

6


 

AMFIRE purchased approximately 175,000 tons of coal from third parties that was blended with AMFIRE’s coal and shipped to our customers. As of February 1, 2005, 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 three 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 one truck/loader surface mine which is operated by an independent contractor. The coal produced by the surface mine is transported to the Roxana preparation plant where it is blended and loaded onto rail for shipment to customers. During 2004, Enterprise purchased approximately 52,000 tons of coal from third parties that was blended with Enterprise’s coal and shipped to our customers. As of February 1, 2005, the Enterprise business was operating at a capacity to ship approximately one and one-half million tons per year.
      National King Coal. Our National King Coal business unit produces coal from one underground mine utilizing a continuous miner and the room and pillar mining method. All of the underground mining operations at National King Coal are staffed and operated by National King Coal employees. The coal is transported to a rail head by truck where it is loaded on rail and sold on a raw basis. The National King Coal business unit has no surface mining operations. As of February 1, 2005, the National King Coal business unit was operating at a capacity to ship approximately 450,000 tons per year.
Marketing, Sales and Customer Contracts
      Our marketing and sales force, which is principally based in Latrobe, Pennsylvania, included 30 employees as of February 1, 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 25.8 million tons of coal in 2004, consisting of 19.4 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, 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 0.9 million tons of our 2004 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 21.9 million tons of coal in 2003, consisting of 18.0 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

7


 

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 2004 and 2003 is set forth in the table below:
                                 
    Steam Coal Sales(1)   Metallurgical Coal Sales
         
Year   Tons   % of Total Sales   Tons   % of Total Sales
                 
    (In millions, except percentages)
2004
    16.3       63%       9.5       37%  
2003
    15.6       71%       6.3       29%  
 
(1)  Steam coal sales include sales to utility and industrial customers. In 2004, sales of steam coal to industrial customers, who we define as consumers of steam coal who do not generate electricity for sale to third parties, accounted for approximately 4% of total sales.
      We sold coal to over 130 different customers in 2004. Our top ten customers in 2004 accounted for approximately 39% of 2004 revenues and our largest customer during 2004 accounted for approximately 8% of 2004 revenues. The following table provides information regarding our exports (including to Canada and Mexico) in 2004 and 2003 by revenues and tons sold:
                                 
        Export Tons       Export Sales
        Sold as a       Revenues as a
    Export Tons   Percentage of   Export Sales   Percentage of
Year   Sold   Total Coal Sales   Revenues(1)   Total Revenues
                 
    (In millions, except percentages)
2004
    8.3       32%     $ 602.6       47%  
2003
    4.9       22%     $ 220.8       28%  
 
(1)  Export sales revenues in 2004 include approximately $4.0 million in equipment export sales. All other export sales revenues are coal sales revenues and freight and handling revenues.
      Our export shipments during 2004 and 2003 serviced customers in 19 and 12 countries, respectively, across North America, Europe, South America, Asia and Africa. Japan was our largest export market in 2004 with sales to Japan accounting for approximately 23% of export revenues and approximately 11% of total revenues in 2004, 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 in 2003. 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 were long-term contracts. Approximately 83% and 55% of our steam and metallurgical coal sales volume in 2004, respectively, was delivered pursuant to long-term contracts.
      As of February 1, 2005, we had contracts to sell 97% of planned 2005 production, including sales commitments for approximately 20.7 million tons, of which 12.3 million tons are steam coal and 8.4 million tons are metallurgical coal and contracts to sell 51% of planned 2006 production, including sales commitments for approximately 11.5 million tons, of which 6.7 million tons are steam coal and 4.8 million tons are metallurgical coal. At February 1, 2005, we had commitments to purchase 5.7 million tons of coal during 2005 and 1.6 million tons in 2006.
      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

8


 

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 25.8 million tons during 2004 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 79% of total shipments of captive produced and processed coal volume from the preparation plant to the customer in 2004. The balance was shipped from our preparation plants, loadout facilities or mines via truck. In 2004, approximately 11% of our coal sales were ultimately delivered to customers through transport on the Great Lakes, approximately 14% 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, and 5% was moved through the export terminal at Baltimore, Maryland. We own a 32.5% interest in the coal export terminal at Newport News, Virginia operated by Dominion Terminal Associates. See “— Other Operations.”
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 2003, only two percent 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 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.

9


 

Other Operations
      We have other operations and activities in addition to our normal coal production, processing and sales business, including:
      Maxxim Rebuild Company. We own Maxxim Rebuild Company, 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 $20.8 million for 2004, of which approximately 22% was generated by services provided to our other subsidiaries and approximately 19% 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 2004, we shipped a total of 1.4 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 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 2004 were $3.3 million, partially offset by payments received in 2004 of $1.8 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%).
      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 2004 came from mines operated by union-free employees, and as of February 1, 2005, over 91% of our subsidiaries’ approximately 2,600 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 have 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.

10


 

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, 2004, we had accrued $39.6 million for reclamation liabilities and mine closures, including $6.7 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 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 the applicable state agency. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the regulatory authority. States in which we have active mining operations have achieved primary control of enforcement through federal authorization.
      SMCRA permit provisions include a complex set of requirements which include: coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; 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 surveys of cultural and historical resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology, and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mining and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mining and reclamation plan incorporates the provisions of SMCRA, the state programs, and the complementary environmental programs that affect coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land, and documents required of the 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 a completeness review and technical review. Public notice of the proposed permit is given that also provides for a comment period before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and may take six months to two years or even longer to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public

11


 

and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.
      Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed or abandoned prior to SMCRA’s adoption in 1977. 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.
      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. Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations including mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other miscellaneous obligations. Many of these bonds are renewable on a yearly basis. Surety bond costs have increased in recent years while the market terms of surety bonds have generally become more unfavorable. In addition, the number of companies willing to issue surety bonds has decreased. We have a committed bonding facility with Travelers Casualty and Surety Company of America, pursuant to which it has agreed, subject to certain conditions, to issue surety bonds on our behalf in a maximum amount of $125.0 million. As of February 1, 2005, we have posted an aggregate of $92.0 million in reclamation bonds and $8.0 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 may occur through Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 2.5 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired electricity generating plants. The general effect of this extensive regulation of emissions from coal-fired power plants could be to reduce demand for coal.
      Clean Air Act requirements that may directly or indirectly affect our operations include the following:
  •  Acid Rain. Title IV of the Clean Air Act required a two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and applies to all coal-fired power plants generating greater than 25 Megawatts. The affected electricity generators have sought to meet these requirements by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years. At this time, we believe that implementation of Phase II has resulted in an upward pressure on the price of lower sulfur coals, as coal-fired power plants continue to comply with the more stringent restrictions of Title IV.
 
  •  Fine Particulate Matter and Ozone. The Clean Air Act requires the U.S. Environmental Protection Agency (the “EPA”) to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for certain pollutants. Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels. In 1997, the EPA revised the NAAQS for particulate matter and ozone. Although previously subject to legal challenge, these revisions were subsequently upheld but implementation was delayed for several years. For ozone, these changes include replacement of the existing one-hour average standard with a more stringent eight-hour average standard. On April 15, 2004, the EPA announced that counties in 32 states fail to meet the new eight-hour standard for ozone. States that fail to meet the new standard will have until June 2007 to develop plans for pollution control measures that allow them to come into compliance with the standards. For particulates, the changes include retaining the existing standard for particulate matter with an aerodynamic diameter less than or equal to 10 microns (“PM10”), and adding a new standard

12


 

  for fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns (“PM2.5”). State fine particulate non-attainment designations were due on February 15, 2004, and 18 states and the District of Columbia recommended counties to be classified as non-attainment areas. The EPA has indicated it will propose the implementation rule in early 2005 and finalize it in early 2006. Following identification of non-attainment areas, each individual state will identify the sources of emissions and develop emission reduction plans. These plans may be state-specific or regional in scope. Under the Clean Air Act, individual states have up to twelve years from the date of designation to secure emissions reductions from sources contributing to the problem. Meeting the new PM2.5 standard may require reductions of nitrogen oxide and sulfur dioxide emissions. Future regulation and enforcement of these new ozone and PM2.5 standards will affect many power plants, especially coal-fired plants and all plants in “non-attainment” areas.
 
  •  Ozone. Significant additional emissions control expenditures will be required at coal-fired power plants to meet the current NAAQS for ozone. Nitrogen oxides, which are a by-product of coal combustion, can lead to the creation of ozone. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding in the years ahead.
 
  •  NOx SIP Call. The NOx SIP Call program was established by the EPA in October of 1998 to reduce the transport of ozone on prevailing winds from the Midwest and South to states in the Northeast, which said they could not meet federal air quality standards because of migrating pollution. Under Phase I of the program, the EPA is requiring 90,000 tons of nitrogen oxides reductions from power plants in 22 states east of the Mississippi River and the District of Columbia beginning in May 2004. Phase II of the program, which became effective June 21, 2004, requires a further reduction of about 100,000 tons of nitrogen oxides per year by May 1, 2007. Installation of additional control measures, such as selective catalytic reduction devices, required under the final rules will make it more costly to operate coal-fired electricity generating plants, thereby making coal a less attractive fuel.
 
  •  Clear Skies Initiative. The Bush Administration has proposed legislation, commonly referred to as the Clear Skies Initiative, that could require dramatic reductions in nitrous oxide, sulfur dioxide, and mercury emissions by power plants through “cap-and-trade” programs similar to the existing Acid Rain regulations and current NOx budget programs. The Senate Environment and Public Works Committee considered this proposed legislation and failed to recommend it for a vote by the full Senate on March 10, 2005. A similar bill is pending before the House of Representatives. It is currently not possible to predict what, if any, new regulatory requirements will ultimately evolve out of this initiative.
 
  •  Clean Air Interstate Rule. The EPA finalized the Clean Air Interstate Rule (CAIR) on March 10, 2005. The new CAIR calls for power plants in 29 eastern states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrous oxide. The rule requires states to regulate power plants under a cap and trade program similar to the system now in effect for acid deposition control and to that proposed by the Clear Skies Initiative. When fully implemented, this rule is expected to reduce regional sulfur dioxide emissions by over 70% and nitrogen oxides emissions by over 60% from 2003 levels. The stringency of the cap may require many coal-fired electricity generation plants to install additional pollution control equipment, such as wet scrubbers, to comply, which could decrease the demand for low sulfur coal at these plants and thereby potentially reduce market prices for low sulfur coal. Emissions are permanently capped and cannot increase.
 
  •  Utility Mercury Reductions Rule. On March 15, 2005, the EPA issued the Clean Air Mercury Rule, originally proposed as the Utility Mercury Reduction Rule, to permanently cap and reduce mercury emissions from coal-fired power plants. The Clean Air Mercury Rule establishes mercury emissions limits from new and existing coal-fired power plants and creates a market-based cap-and-trade program that is expected to reduce nationwide utility emissions of mercury in two phases. The cap on mercury emissions during the first phase is 38 tons. To the extent mercury emissions are required to be reduced during the first phase, emissions may reduced by taking advantage of “co-benefit” reductions — that is, mercury reductions achieved by reducing sulfur dioxide and nitrogen oxides emissions

13


 

  under CAIR. In the second phase, due in 2018, coal-fired power plants will be subject to a second cap, which will reduce emissions to 15 tons.
 
  •  Carbon Dioxide. In February 2003, a number of states notified the EPA that they planned to sue the agency to force it to set new source performance standards for utility emissions of carbon dioxide and to tighten existing standards for sulfur dioxide and particulate matter for utility emissions. In June 2003, three of these states sued the EPA seeking a court order requiring the EPA to designate carbon dioxide as a criteria pollutant and to issue a new NAAQS for carbon dioxide. If these lawsuits result in the issuance of a court order requiring the EPA to set emission limitations for carbon dioxide and/or lower emission limitations for sulfur dioxide and particulate matter, it could reduce the amount of coal our customers would purchase from us. To date, no decision has been rendered in this case.
 
  •  Regional Emissions Trading: Eleven Northeast and Mid-Atlantic states are working cooperatively to develop a regional cap and trade program that would initially cover carbon dioxide emissions from power plants in the region. The states intend to develop a model rule by April 2005. There are a number of uncertainties regarding this initiative, including the applicable baseline of emissions to be permitted, initial allocations, required emissions reductions, availability of offsets, the extent to which states will adopt the program, whether it will be linked with programs in other states or in Canadian provinces, and the timing for implementation of the program. There can be no assurance at this time that a carbon dioxide cap and trade program, if implemented by the states where our customers operate, will not affect the future market for coal in this region.
 
  •  Regional Haze. The EPA has initiated a regional haze program designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could affect the future market for coal.
      Clean Water Act. The Clean Water Act of 1972 (the “CWA”) and corresponding state laws affect coal mining operations by imposing restrictions on the discharge of certain pollutants into water and on dredging and filling wetlands. The CWA establishes in-stream water quality standards and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water.
      Permits under Section 404 of the CWA are required for coal companies to conduct dredging or filling activities in jurisdictional waters for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. Jurisdictional waters typically include ephemeral, intermittent, and perennial streams and may in certain instances include man-made conveyances that have a hydrologic connection to a stream or wetland. Presently, under the Stream Buffer Zone Rule, mining disturbances are prohibited within 100 feet of streams if negative effects on water quality are expected. OSM has proposed changes to this rule, which would make exemptions available if mine operators take steps to reduce the amount of waste and its effect on nearby waters.
      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. The plaintiffs sought to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators from additional use of existing nationwide permit approvals until they obtain more detailed “individual” permits. On July 8, 2004, the court issued an order enjoining the further issuance of

14


 

Nationwide 21 permits and rescinded certain listed permits where construction of valley fills and surface impoundments had not commenced. On August 13, 2004, the court extended the ruling to all Nationwide 21 permits within the Southern District of West Virginia. Although Alpha had no operations that were interrupted, this decision may require 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 other lawsuits may be filed in other states where Alpha operates.
      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 aversely affect our coal production.
      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. All of the states in which we operate 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. While this regulation has 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 2004, we recorded $12.6 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

15


 

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 affects coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. 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 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, 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%

16


 

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
      Following our initial public offering, we are required to 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., 406 West Main Street, Abingdon, Virginia 24210, 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 upon request.
Item 2. Properties
Coal Reserves
      We estimate that, as of December 31, 2004, we had total proven and probable reserves of approximately 511.1 million tons. We believe that our total proven and probable reserves will support current production levels for more than 25 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, completed in November 2004, 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 this report, 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.

17


 

      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 $2.37 per ton in 2004, representing approximately 4% of our 2004 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, 2004.
                                                         
        Recoverable   Sulfur Content   Average Btu
        Reserves Proven &        
Regional Business Unit   State   Probable(1)   <1%   1.0%-1.5%   >1.5%   >12,500   <12,500
                             
        (In millions of        
        tons)   (In millions of tons)   (In millions of
                tons)
Paramont/Alpha Land and Reserves(2)
    Virginia       154.9       110.8       32.1       12.0       153.3       1.6  
Dickenson-Russell
    Virginia       32.9       32.9       0       0       32.9       0  
Kingwood
    West Virginia       31.5       0       18.9       12.6       31.5       0  
Brooks Run
    West Virginia       25.9       7.8       18.1       0       10.6       15.3  
Welch
    West Virginia       95.7       95.7       0       0       95.7       0  
AMFIRE
    Pennsylvania       93.7       14.1       49.4       30.2       84.3       9.4  
Enterprise
    Kentucky       66.3       26.3       38.4       1.6       64.2       2.1  
National King Coal
    Colorado       10.2       9.1       1.1       0       10.2       0  
                                           
Totals
            511.1       296.7       158.0       56.4       482.7       28.4  
Percentages
                    58 %     31 %     11 %     94 %     6 %
 
(1)  Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law. The reserve numbers set forth in the table exclude reserves for which we have leased our mining rights to third parties. Reserve information reflects a moisture factor of 6.5%. This moisture factor represents the average moisture present on our delivered coal.
 
(2)  Includes proven and probable reserves in Virginia controlled by our subsidiary Alpha Land and Reserves, LLC as of December 31, 2004. Alpha Land and Reserves, LLC subleases a portion of the mining rights to its proven and probable reserves in Virginia to our subsidiary Paramont Coal Company Virginia, LLC.

18


 

      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, 2004.
                                                     
        Recoverable   Total Tons   Total Tons    
        Reserves Proven &           Coal
Regional Business Unit   State   Probable(1)   Assigned(2)   Unassigned(2)   Owned   Leased   Type(3)
                             
        (In millions of            
        tons)   (In millions of tons)   (In millions of    
                tons)    
Paramont/ Alpha Land and Reserves(4)
    Virginia       154.9       75.9       79.0       0       154.9     Steam and Metallurgical
Dickenson-Russell
    Virginia       32.9       30.7       2.2       0       32.9     Steam and Metallurgical
Kingwood
    West Virginia       31.5       23.1       8.4       0       31.5     Steam and Metallurgical
Brooks Run
    West Virginia       25.9       3.4       22.5       3.3       22.6     Steam and Metallurgical
Welch
    West Virginia       95.7       54.3       41.4       1.3       94.4     Steam and Metallurgical
AMFIRE
    Pennsylvania       93.7       43.6       50.1       3.5       90.2     Steam and Metallurgical
Enterprise
    Kentucky       66.3       10.9       55.4       7.2       59.1     Steam
National King Coal
    Colorado       10.2       1.4       8.8       0       10.2     Steam
                                         
Totals
            511.1       243.3       267.8       15.3       495.8      
Percentages
                    48 %     52 %     3 %     97 %    
 
(1)  Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law. The reserve numbers set forth in the table exclude reserves for which we have leased our mining rights to third parties. Reserve information reflects a moisture factor of 6.5%. This moisture factor represents the average moisture present on our delivered coal.
 
(2)  Assigned reserves represent recoverable coal reserves that can be mined without a significant capital expenditure for mine development, whereas unassigned reserves will require significant capital expenditures to mine the reserves.
 
(3)  Almost all of our reserves that we currently market as metallurgical coal also possess quality characteristics that would enable us to market them as steam coal.
 
(4)  Includes proven and probable reserves in Virginia controlled by our subsidiary Alpha Land and Reserves, LLC as of December 31, 2004. Alpha Land and Reserves, LLC subleases a portion of the mining rights to its proven and probable reserves in Virginia to our subsidiary Paramont Coal Company Virginia, LLC.

19


 

      The following map shows the locations of Alpha’s properties, including the number of mines and preparation plants as of February 1, 2005 and 2004 production of saleable tons for each of our eight regional business units:
LOGO
      See Item 1. Business, of this report for additional information regarding our coal operations and properties.

20


 

Item 3. Legal Proceedings
      The Company is a party to a number of legal proceedings incident to its 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.
Item 4. Submission of Matters to a Vote of Security Holders
      There were no matters submitted to a vote of security holders of Alpha Natural Resources, Inc. through a solicitation of proxies or otherwise during the fourth quarter of the Company’s fiscal year ended December 31, 2004.
Item 4A. Executive Officers of the Registrant
      The following table sets forth the names, ages and titles of our executive officers as of February 1, 2005.
             
Name   Age   Position
         
Michael J. Quillen
    56     President, Chief Executive Officer and Director
Kevin S. Crutchfield
    43     Executive Vice President
D. Scott Kroh
    54     Executive Vice President
David C. Stuebe
    64     Vice President and Chief Financial Officer
Michael D. Brown
    43     Vice President
Vaughn R. Groves
    48     Vice President and General Counsel
Eddie W. Neely
    53     Vice President and Controller
      Each officer serves at the discretion of our board of directors and holds office until his or her successor is elected and qualified or until his or her earlier resignation or removal.
      Set forth below is a description of the background of the persons named above.
      Michael J. Quillen has served as our President and Chief Executive Officer and a member of our board of directors since our formation in November 2004. Mr. Quillen joined the Alpha management team as President and the sole manager of Alpha Natural Resources, LLC, our top-tier operating subsidiary, in August 2002, and has served as Chief Executive Officer of Alpha Natural Resources, LLC since January 2003. He has also served as the President and a member of the board of directors of ANR Holdings since December 2002, and as the Chief Executive Officer of ANR Holdings since March 2003. From September 1998 to December 2002, Mr. Quillen was Executive Vice President — Operations of AMCI. While at AMCI, he was also responsible for the development of AMCI’s Australian properties. Mr. Quillen has over 30 years of experience in the coal industry starting as an engineer. He has held senior executive positions in the coal industry throughout his career, including as Vice President — Operations of Pittston Coal Company, President of Pittston Coal Sales Company, Vice President of AMVEST Corporation, Vice President — Operations of NERCO Coal Corporation, President and Chief Executive Officer of Addington, Inc. and Manager of Mid-Vol Leasing, Inc.
      Kevin S. Crutchfield has served as our Executive Vice President since our formation in November 2004. Mr. Crutchfield joined the Alpha management team as the Executive Vice President of Alpha Natural Resources, LLC and Vice President of ANR Holdings in March 2003, and has served as the Executive Vice President of ANR Holdings since November 2003. From June 2001 through January 2003, he was President of Coastal Coal Company and Vice President of El Paso Corporation. Prior to joining El Paso, he served as President of AMVEST Corporation, a coal and gas producer and provider of related products and services, and held executive positions at AEI Resources, Inc., most recently as President and Chief Executive Officer.

21


 

Before joining AEI Resources, Inc., he served as the Chairman, President and Chief Executive Officer of Cyprus Australia Coal Company and held executive operating management positions with Cyprus in the U.S. before being relocated to Sydney, Australia in 1997. He worked for Pittston Coal Company in various operating and executive management positions from 1986 to 1995 serving most recently as Vice President Operations prior to joining Cyprus Amax Coal Company.
      D. Scott Kroh has served as our Executive Vice President since our formation in November 2004. Mr. Kroh joined the Alpha management team as the Executive Vice President of Alpha Natural Resources, LLC in March 2003, and has also served as the Executive Vice President of ANR Holdings since November 2003. From June 1989 through February 2003 he served as President of Tanoma Energy’s sales and mining company, an AMCI affiliate located in Latrobe, Pennsylvania. Mr. Kroh also served as Vice President of AMCI Export from January 1992 until February 2003. Prior to founding Tanoma Energy he served as Vice President of Sales for Amerikohl Mining Company of Butler, Pennsylvania from 1980 until May 1989. Mr. Kroh began his career in the coal business in 1978 as a salesman for Ringgold Mining Company of Kittanning, Pennsylvania.
      David C. Stuebe has served as our Vice President and Chief Financial Officer since our formation in November 2004. Mr. Stuebe joined the Alpha management team as the Vice President and Chief Financial Officer of Alpha Natural Resources, LLC in October 2003, and has also served as the Vice President and Chief Financial Officer of ANR Holdings since November 2003. Mr. Stuebe served from March 2000 to July 2003 as Senior Vice President-Finance and Administration of Hearth and Home Technologies, Inc., a wholly-owned subsidiary of HON INDUSTRIES Inc., a leading manufacturer of office systems and hearth products, and from October 1994 to March 2000 as Vice President and Chief Financial Officer of the parent, HON INDUSTRIES Inc. Prior to joining HON, he served as President, Chief Executive Officer and Director of United Recycling Industries, Inc., a metals broker, precious metals recycler and non-ferrous metals producer from 1990 to 1994, as President, Chief Executive Officer and Director of Auto Specialties Manufacturing, Inc., a manufacturer of O.E.M. truck and construction equipment components from 1988 to 1990, and as Chairman, President and Chief Executive and Chief Financial Officer of MSL Industries, Inc., a manufacturer and distributor of fasteners, tubing, roll-form shapes, electric motors, components for electric utilities and missile components from 1981 to 1987. Mr. Stuebe’s business background also includes significant general and financial management positions with Carpetland U.S.A. and the Scholl Products Group of Schering-Plough, as well as 13 years of audit experience with an international public accounting firm.
      Michael D. Brown has served as our Vice President since our formation in November 2004. Mr. Brown joined the Alpha management team as Vice President of Alpha Natural Resources, LLC in March 2003, and has also served as Vice President of ANR Holdings since November 2003. From 2000 through March 2003, he served as Vice President — Development and Technical Resources for Pittston Coal Company. Prior to this he served as Pittston’s Group Vice President of Metallurgical Operations, which included all Pittston properties acquired by Alpha. Mr. Brown served in numerous other executive and financial positions within Pittston Coal Company including a two year period as the chief operating officer for Pittston’s affiliated gas and timber companies. Mr. Brown was affiliated with Pittston Coal from June 1984 until his employment at Alpha.
      Vaughn R. Groves has served as our Vice President and General Counsel since our formation in November 2004. Mr. Groves joined the Alpha management team as the Vice President and General Counsel of Alpha Natural Resources, LLC in October 2003, and has also served as the Vice President and General Counsel of ANR Holdings since November 2003. Prior to that time, he served as Vice President and General Counsel of Pittston Coal Company from 1996 until joining Alpha, and as Associate General Counsel of Pittston Coal Company from 1991 until 1996. Before joining Pittston Coal, he was associated with the law firm of Jackson Kelly PLLC, one of the leading mineral law firms in the Appalachian region. He is also a mining engineer and before obtaining his law degree, he worked as an underground section foreman, construction foreman and mining engineer for Monterey Coal Company.
      Eddie W. Neely has served as our Vice President and Controller since our formation in November 2004. Mr. Neely joined the Alpha management team as the Secretary of Alpha Natural Resources, LLC in August

22


 

2002, and has also served as Vice President and Controller of Alpha Natural Resources, LLC since March 2003. From August 1999 to August 2002, he served as Chief Financial Officer of White’s Fresh Foods, Inc., a family-owned supermarket chain. In August 2001, White’s Fresh Foods, Inc. filed for reorganization under Chapter 11 of the United States Bankruptcy Code. Prior to joining White’s Fresh Foods, from October 1997 to August 1999, Mr. Neely was Controller for Hunt Assisted Living, LLC, a company that developed, constructed, managed and operated assisted living facilities for the elderly. Mr. Neely served as Director of Accounting for The Brinks Company (formerly known as The Pittston Company) from January 1996 until October 1997 and held various accounting and finance positions with Pittston Coal Company and subsidiaries prior to January 1996. Mr. Neely is a certified public accountant.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
      The initial public offering of our common stock commenced on February 15, 2005. The Company’s common stock has been listed on the New York Stock Exchange since that time under the symbol “ANR.” There was no public market for our common stock prior to this date.
      As of March 15, 2005, there were 30 registered holders of record of our common stock. The transfer agent and registrar for our common stock is Equiserve Trust Company, N.A.
      We expect to commence a policy of paying quarterly dividends, initially of between $.02 and $.03 per share, to the holders of our common stock. We would expect our board to 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 and (5) other factors that our board of directors may deem relevant. Currently, the terms of our credit facility and our senior notes restrict our ability to pay dividends to our stockholders. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for more information regarding these restrictions.
Recent Sales of Unregistered Securities
      As part of our Internal Restructuring on February 11, 2005, (1) Alpha Natural Resources, Inc. issued an aggregate of 28,287,580 shares of its common stock in exchange for the contribution of shares of common stock of Alpha NR Holding, Inc. and interests in ANR Holdings, and (2) outstanding options held by members of our management to purchase units of Alpha Coal Management were converted into options to purchase up to 596,985 shares of our common stock (the “ACM converted options”). These issuances were made in reliance upon Section 4(2) of the Securities Act or under Rules 506 or Rule 701 promulgated by the SEC.
Use of Proceeds From the Registrant’s Initial Public Offering
      On February 15, 2005, the Company commenced the initial public offering of its common stock, par value $.01 per share, pursuant to its registration statement on Form S-1 (File No. 333-121002), which was declared effective by the SEC on February 14, 2005. The Company registered 33,925,000 shares of common stock at an aggregate maximum offering price of $610.7 million pursuant to the registration statement. Pursuant to the offering, 33,925,000 shares were sold for an aggregate offering price of $644.6 million. The managing underwriters for the offering were Morgan Stanley & Co. Incorporated and Citigroup Global Markets Inc.

23


 

      The net proceeds received by the Company in the offering were $596.6 million as follows:
         
Aggregate offering proceeds to the Company
  $ 644.6  
Underwriting discounts and commissions
    41.9  
Finders fee
     
Expenses paid to or for underwriters
    0.2  
Other fees and expenses
    5.9  
       
Total Expenses
    48.0  
       
Net proceeds to the Company
  $ 596.6  
       
      Alpha Natural Resources, Inc. used $518.0 million of the net proceeds to repay in full indebtedness incurred to the First Reserve Stockholders, entities affiliated with AMCI and Madison Capital Funding LLC in connection with our Internal Restructuring and the remaining $78.6 million of the net proceeds were distributed by Alpha Natural Resources, Inc. on a pro rata basis to our stockholders of record as of the close of business on February 11, 2005 pursuant to a distribution declared by our Board of Directors on February 8, 2005. As a result of these payments, the First Reserve Stockholders received an aggregate of $323.1 million, entities affiliated with AMCI received an aggregate of $262.0 million, and our directors and officers not affiliated with the First Reserve Stockholders or entities affiliated with AMCI received an aggregate of $7.7 million. As of March 1, 2005, 22.5% and 18.25% of the outstanding shares of our common stock are held by the First Reserve Stockholders and entities affiliated with AMCI, respectively.
Equity Compensation Plan Information
                         
            (c) Number of securities
        (b) Weighted-   remaining available for
    (a) Number of   average exercise   future issuance under
    securities to be issued   price of   equity compensation
    upon exercise of   outstanding   plans (excluding
    outstanding options,   options, warrants   securities reflected in
Plan Category   warrants and rights   and rights   column (a))
             
Equity compensation plans approved by security holders
    1,289,890     $ 16.10       2,645,936 (1)
Equity compensation plans not approved by security holders
                 
                   
Total
    1,289,890     $ 16.10       2,645,936  
 
(1)  The Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan has 2,645,936 shares of common stock available for future issuance to qualified participants (refer to column (c)).
Item 6. Selected Financial Data
      The following table presents selected financial and other data about us and our Predecessor for the most recent five fiscal periods. The selected historical financial data as of December 31, 2003 and 2004, for the period from December 14, 2002 to December 31, 2002 and for the years ended December 31, 2003 and 2004, 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 included elsewhere in this annual report, which have been audited by KPMG. The selected historical financial data as of December 2000 and 2001, and for the years ended December 31, 2000 and 2001 have been derived from our

24


 

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, the “Risks Relating To Our Company” section of Item 7 of this report includes a discussion of risk factors that could impact our future results of operations.
                                                       
          ANR Fund IX Holdings, L.P. and Alpha
    Predecessor     NR Holding, Inc. and Subsidiaries
           
    Year Ended   January 1,     December 14,   Year Ended
    December 31,   2002 to     2002 to   December 31,
        December 13,     December 31,    
    2000   2001   2002     2002   2003   2004
                           
    (In thousands, except per ton data)
Statement of Operations Data:
                                                 
Revenues:
                                                 
 
Coal revenues
  $ 226,653     $ 227,237     $ 154,715       $ 6,260     $ 701,262     $ 1,089,992  
 
Freight and handling revenues
    25,470       25,808       17,001         1,009       73,800       146,166  
 
Other revenues
    5,601       8,472       6,031         101       17,504       33,560  
                                       
   
Total revenues
    257,724       261,517       177,747         7,370       792,566       1,269,718  
                                       
Costs and expenses:
                                                 
 
Cost of coal sales (exclusive of items shown separately below)
    224,230       219,545       158,924         6,268       632,979       931,585  
 
Freight and handling costs
    25,470       25,808       17,001         1,009       73,800       146,166  
 
Cost of other revenues
    4,721       8,156       7,973         120       16,750       25,064  
 
Depreciation, depletion and amortization
    7,890       7,866       6,814         274       36,054       56,012  
 
Asset impairment charge
                                    5,100  
 
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)
    8,543       9,370       8,797         471       21,949       43,881  
 
Costs to exit business
    26,937       3,500       25,274                      
                                       
   
Total costs and expenses
    297,791       274,245       224,783         8,142       781,532       1,207,808  
                                       
Refund of federal black lung excise tax
          16,213       2,049                      
Gain on sale of fixed assets, net
                                    671  
Other operating income, net
    57       94       1,430                      
                                       
   
Income (loss) from operations
    (40,010 )     3,579       (43,557 )       (772 )     11,034       62,581  
                                       
Other income (expense):
                                                 
 
Interest expense
                (35 )       (203 )     (7,848 )     (20,041 )
 
Interest income
    2,263       1,993       2,072         6       103       531  
 
Miscellaneous income
    4,215       1,250                     575       734  
                                       
   
Total other income (expense), net
    6,478       3,243       2,037         (197 )     (7,170 )     (18,776 )
                                       
   
Income (loss) before income taxes and minority interest
    (33,532 )     6,822       (41,520 )       (969 )     3,864       43,805  
Income tax expense (benefit)
    (13,545 )     (1,497 )     (17,198 )       (334 )     668       3,960  
Minority interest
                              934       19,830  
                                       
   
Net income (loss)
  $ (19,987 )   $ 8,319     $ (24,322 )     $ (635 )   $ 2,262     $ 20,015  
                                       

25


 

                                                   
        ANR Fund IX Holdings, L.P. and Alpha
    Predecessor   NR Holding, Inc. and Subsidiaries
         
    Year Ended   January 1,   December 14,   Year Ended
    December 31,   2002 to   2002 to   December 31,
        December 13,   December 31,    
    2000   2001   2002   2002   2003   2004
                         
    (In thousands, except per ton data)
Balance sheet data (at period end):
                                               
Cash and cash equivalents
  $ 185     $ 175             $ 8,444     $ 11,246     $ 7,391 (1)
Working capital (deficit)
    (26,634 )     (22,958 )             (12,223 )     32,714       56,257 (1)
Total assets
    130,608       139,467               108,442       379,336       477,121 (1)
Notes payable and long-term debt, including current portion
                        25,743       84,964       201,705 (1)
Stockholder’s equity and partners’ capital (deficit)
    (142,067 )     (136,593 )             23,384       86,367       45,933 (1)
Statement of cash flows data:
                                               
Net cash provided by (used in):
                                               
 
Operating activities
  $ 20,659     $ 10,655     $ (13,816 )   $ (295 )   $ 54,104     $ 106,776  
 
Investing activities
    (8,564 )     (9,203 )     (22,054 )     (38,893 )     (100,072 )     (86,202 )
 
Financing activities
    (12,106 )     (1,462 )     35,783       47,632       48,770       (24,429 )
Capital expenditures
    9,127       10,218       21,866       960       27,719       72,046  
Other financial data:
                                               
 
EBITDA, as adjusted(2)
                          $ (498 )   $ 47,663     $ 119,327  
Other data:
                                               
 
Tons sold
    7,947       6,975       4,283       186       21,930       25,808  
 
Tons produced and processed
    6,281       6,248       4,508       87       17,532       19,525  
 
Average coal sales realization (per ton)
  $ 28.52     $ 32.58     $ 36.12     $ 33.66     $ 31.98     $ 42.23  
 
(1)  The following unaudited summary pro forma balance sheet data for Alpha Natural Resources, Inc. as of December 31, 2004 are presented (1) on a pro forma basis giving effect to the completion of our Internal Restructuring on February 11, 2005 as if it had occurred on December 31, 2004, and (2) on a pro forma, as adjusted basis, as adjusted further to give effect to our initial public offering of 33,925,000 shares of our common stock completed on February 18, 2005 and the application of the net proceeds from that offering:
                 
        Pro Forma, As
    Pro Forma   Adjusted
    December 31, 2004   December 31, 2004
         
    (Unaudited)   (Unaudited)
    (In thousands)
Cash and cash equivalents
  $ 7,391     $ 7,391  
Working capital (deficit)
    (466,109 )     51,583  
Total assets
    472,447       472,447  
Notes payable, including notes payable to affiliates, and long-term debt, including current portion
    719,397       201,705  
Stockholders’ equity (deficit)
    (450,437 )     67,255  

26


 

(2)  EBITDA, as adjusted, is defined as net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, less interest income, and adjusted for minority interest. EBITDA, as adjusted, is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because EBITDA, as adjusted, is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.
      EBITDA, as adjusted, is calculated as follows (unaudited):
                         
    ANR Fund IX Holdings, L.P. and Alpha
    NR Holding, Inc. and Subsidiaries
     
    December 14,   Year Ended
    2002 to   December 31,
    December 31,    
    2002   2003   2004
             
Net income (loss)
  $ (635 )   $ 2,262     $ 20,015  
Interest expense
    203       7,848       20,041  
Interest income
    (6 )     (103 )     (531 )
Income tax expense (benefit)
    (334 )     668       3,960  
Depreciation, depletion and amortization
    274       36,054       56,012  
                   
EBITDA
    (498 )     46,729       99,497  
Minority interest
          934       19,830  
                   
EBITDA, as adjusted
  $ (498 )   $ 47,663     $ 119,327  
                   

27


 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
      You should read the following discussion and analysis in conjunction with our combined financial statements and related notes and our “Selected Financial Data” included elsewhere in this annual report. The historical financial information discussed below 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 prior to our Internal Restructuring.
Overview
      We produce, process and sell steam and metallurgical coal from eight regional business units, which, as of February 1, 2005, are supported by 44 active underground mines, 21 active surface mines and 11 preparation plants located throughout Virginia, West Virginia, Kentucky, Pennsylvania and Colorado. 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. For the year ended December 31, 2004, sales of steam coal were 16.3 million tons which accounted for approximately 63% of our coal sales volume. Sales of metallurgical coal, which generally sells at a premium over steam coal, were 9.5 million tons and accounted for approximately 37% of our 2004 coal sales volume. Our sales of steam coal were made primarily to large utilities and industrial customers in the Eastern region of the United States, and our sales of metallurgical coal 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 47% 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 income, rentals, royalties, commissions, coal handling, terminal and processing fees, and coal and environmental analysis fees. We also generate revenue when we are reimbursed by our customers for freight and handling charges. 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 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 are 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 and coal handling and processing operations. We report the revenues and costs from rentals, commissions and coal handling and processing operations 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 U.S. 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, U.S. AMCI and Mears, collectively, as the “2003 Acquisitions.”

28


 

      2004 Financings. On May 18, 2004, our subsidiaries, Alpha Natural Resources, LLC and Alpha Natural Resources Capital Corp., issued $175.0 million principal amount of 10% senior notes due 2012, and on May 28, 2004, Alpha Natural Resources, LLC entered into a new $175.0 million credit facility (together referred to as the “2004 Financings”).
      Internal Restructuring and Initial Public Offering. On February 11, 2005, we completed a series of transactions in connection with our 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 33,925,000 shares of our common stock. As a result of our Internal Restructuring and initial public offering, we will incur additional expenses that we have not incurred in the past, including expenses associated with compliance with corporate governance and periodic financial reporting requirements for public companies. Moreover, all of our income will be subject to income tax and therefore the effective tax rates reflected in our historical financial statements will not be indicative of our effective tax rates after our Internal Restructuring. Further information regarding our Internal Restructuring and initial public offering can be found in note 1 to our combined financial statements included in this annual report.
      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 received by us from the underwriters as a result of the underwriters’ exercise of their over-allotment option in connection with our initial public offering. As a result, we expect to record stock-based compensation expense and deferred stock-based compensation equal to the fair value of the shares issued and distributions paid of $59.1 million. Of this amount, we expect to record $36.2 million as compensation expense for the quarter ending March 31, 2005, equal to the distributions paid and the vested portion of the shares issued. We expect to record the remaining $22.9 million as deferred stock-based compensation for the quarter ending March 31, 2005, equal to the unvested portion of the shares issued, which will be amortized over the two-year vesting period of the unvested shares. In addition, as a result of the issuance of the ACM converted options, we expect to record deferred stock-based compensation of $3.7 million in the first quarter of 2005, which we will amortize over the five-year vesting period of the options beginning January 1, 2005, including $0.2 million of compensation expense that we expect to record for the quarter ending March 31, 2005. The aggregate amount of stock-based compensation expense that we expect to record in the first quarter of 2005 will be $36.4 million ($28.7 million of which we expect will be non-cash), equal to the $36.2 million of expense associated with distributions paid and the vested portions of shares issued in the Internal Restructuring, and $0.2 million of amortized expense from the ACM converted options. As a result, we expect that we may record a net loss for this quarter. 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.
      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 “Sponsor Distributions”). The Sponsor Distributions to affiliates of AMCI will be paid in five equal installments on the dates for which estimated income tax payments are due in each of April 2005, June 2005, September 2005, January 2006 and April 2006. The Sponsor Distributions to First Reserve Fund IX, L.P. 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. The Sponsor Distributions will be payable in cash or, to the extent we are not permitted by the terms of our credit facility or the indenture governing our senior notes to pay the Sponsor Distributions in cash, in shares of our common stock.
      Coal Pricing Trends and Uncertainties. During the year ended December 31, 2004, prices for our coal increased significantly 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

29


 

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 and net income during the year ended December 31, 2004. While as noted under “— Outlook,” 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 1, 2005, 3% of our planned 2005 production and 49% of our planned 2006 production was uncommitted and was not yet priced.
      In 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 also experienced disruptions in railroad service during the second half of 2004, which caused delays in delivering products to customers and increased our internal coal handling costs. While as noted under “— Outlook,” we anticipate gradual improvement in railroad service beginning in the second half of 2005, conditions affecting railroad service are subject to factors beyond our control and we cannot predict whether and for how long these costs will continue to increase in the future.
      We experienced a tight market for supplies of mining and processing equipment and parts during 2004, 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.
      In January 2005, the state of West Virginia passed legislation to increase the severance tax on coal by $0.56 per ton effective December 1, 2005. The estimated impact for this increased severance tax in 2005 is approximately $0.3 million and we estimate an annual impact beginning in 2006 of approximately $4.0 million based on current operating levels. A portion of this increase may be recoupable from customers based on allowances in some sales contracts for changes in law.
      The U.S. dollar has weakened over the last two years, which has made U.S. coal relatively less expensive and, therefore, more competitive in foreign markets. We believe that the weakening of the U.S. dollar has enabled us to export more metallurgical coal at higher prices than would otherwise have been the case during 2003 and 2004, and this trend has contributed to our growth in revenues and income during those periods. Changes in currency conversion rates are subject to factors beyond our control and we cannot predict whether and for how long the dollar will continue to weaken against foreign currencies. We believe that a strengthening of the U.S. dollar would adversely affect our exports.
      For additional information regarding some of the risks and uncertainties that affect our business, see “— Risks Relating to Our Company.”
Unaudited Pro Forma Financial Information
      The unaudited pro forma balance sheet data as of December 31, 2004 presented in the combined financial statements included in this annual report give effect to our Internal Restructuring described above as if it had occurred on December 31, 2004. The following unaudited pro forma statement of operations data for the years ended December 31, 2003 and 2004 give effect to the Internal Restructuring, the 2004 Financings and the 2003 Acquisitions described above, as if they had occurred on January 1, 2003. This pro forma data is for informational purposes only, and should not be considered indicative of results that would have been achieved had the transactions listed above actually been consummated on January 1, 2003.
                 
    Year Ended December 31,
     
    2003   2004
         
Pro forma revenues
  $ 902,766     $ 1,269,718  
Pro forma net income
    536       29,637  

30


 

      The following unaudited table reconciles reported net income to pro forma net income for the years ended December 31, 2003 and 2004 as if the Internal Restructuring, 2004 Financings, and 2003 Acquisitions had occurred on January 1, 2003:
                 
    Year Ended
    December 31,
     
    2003   2004
         
Reported net income
  $ 2,262     $ 20,015  
Add: Pro forma results of operations related to the 2003 Acquisitions, net of income taxes
    3,507        
Deduct: Pro forma effects of the 2004 Financings, net of income taxes
    (7,728 )     (1,672 )
Add: Elimination of minority interest, net of income tax effects of the Internal Restructuring
    2,495       11,294  
             
Pro forma net income
  $ 536     $ 29,637  
             
      The following unaudited pro forma earnings per share data for the years ended December 31, 2003 and 2004 give effect to the Internal Restructuring, the 2004 Financings and the 2003 Acquisitions described above, as if they had occurred on January 1, 2003.
                 
    Year Ended December 31,
     
    2003   2004
         
Pro forma earnings per share data:
               
Basic earnings per share
  $ 0.02     $ 1.10  
Shares outstanding — basic
    26,942,650       26,942,650  
Diluted earnings per share
  $ 0.02     $ 1.04  
Shares outstanding — diluted
    28,484,586       28,484,586  
      The following unaudited pro forma, as adjusted, earnings per share data for the years ended December 31, 2003 and 2004 give effect to the Internal Restructuring, the 2004 Financings and the 2003 Acquisitions as if these transactions had occurred on January 1, 2003, as further adjusted to give effect to our initial public offering of common stock completed on February 18, 2005:
                 
    Year Ended December 31,
     
    2003   2004
         
Pro forma, as adjusted, earnings per share data:
               
Basic earnings per share
  $ 0.01     $ 0.49  
Shares outstanding — basic
    60,867,650       60,867,650  
Diluted earnings per share
  $ 0.01     $ 0.47  
Shares outstanding — diluted
    62,409,586       62,409,586  
Results of Operations
      For purposes of the following discussion and analysis of our operating results, the revenues and costs and expenses of ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. and subsidiaries for the period from December 14, 2002 to December 31, 2002 have been combined with the revenues and costs and expenses of our Predecessor for the period from January 1, 2002 to December 13, 2002, as reflected in the table below. We believe this presentation facilitates the ability of the reader to more meaningfully compare our revenues, costs and expenses in 2002 with other periods. Our operating results from and after December 14, 2002, including our recorded depreciation, depletion and amortization expense, are not comparable to the Predecessor Periods as a result of the application of purchase accounting. The combining of the Predecessor and successor accounting periods in the year ended December 31, 2002 is not permitted by U.S. generally accepted accounting principles.

31


 

Combined Statement of Operations Data
For the Year Ended December 31, 2002
                             
        ANR Fund IX    
        Holdings, L.P. and    
        Alpha NR   (Non-
        Holding, Inc. and   GAAP)
    Predecessor   Subsidiaries   Combined
             
    January 1,   December 14,   January 1,
    2002 to   2002 to   2002 to
    December 13,   December 31,   December 31,
    2002   2002   2002
             
    (In thousands, except per ton data)
Statement of Operations Data:
                       
Revenues:
                       
 
Coal revenues
  $ 154,715     $ 6,260     $ 160,975  
 
Freight and handling revenues
    17,001       1,009       18,010  
 
Other revenues
    6,031       101       6,132  
                   
   
Total revenues
    177,747       7,370       185,117  
                   
Costs and expenses:
                       
 
Cost of coal sales (exclusive of items shown separately below)
    158,924       6,268       165,192  
 
Freight and handling costs
    17,001       1,009       18,010  
 
Cost of other revenues
    7,973       120       8,093  
 
Depreciation, depletion and amortization
    6,814       274       7,088  
 
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)
    8,797       471       9,268  
 
Costs to exit business
    25,274             25,274  
                   
   
Total costs and expenses
    224,783       8,142       232,925  
                   
Refund of federal black lung excise tax
    2,049             2,049  
Other operating income, net
    1,430             1,430  
                   
   
Income (loss) from operations
  $ (43,557 )   $ (772 )   $ (44,329 )
                   
Other Data:
                       
Tons sold
    4,283       186       4,469  
Coal sales realization per ton sold
  $ 36.12     $ 33.66     $ 36.02  
Cost of coal sales per ton sold
  $ 37.11     $ 33.70     $ 36.96  
      The 2003 Acquisitions also affect comparability with the Predecessor Periods and, therefore, the results of operations for the Predecessor Periods are not comparable to the results of operations for the periods from and after December 14, 2002. In addition, the results of operations for the year ended December 31, 2004 are not directly comparable to the same period in 2003 due to the 2003 Acquisitions.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Summary
      For the year ended December 31, 2004, we recorded revenues of $1,269.7 million compared to $792.6 million for the year ended December 31, 2003 ($902.8 million on a pro forma basis), an increase of $477.2 million ($366.9 million on a pro forma basis) over the previous year. Net income increased from $2.3 million in 2003 ($0.5 million on a pro forma basis) to $20.0 million for 2004 ($29.6 million on a pro forma basis) and operating income increased $51.6 million to $62.6 million. Tons sold increased from

32


 

21.9 million tons in 2003 to 25.8 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 9.7% in 2003 to 14.5% in 2004.
Revenues
                                 
        Increase
    Year Ended December 31,   (Decrease)
         
    2003   2004   $ or Tons   %
                 
    (In thousands, except per ton data)
Coal revenues
  $ 701,262     $ 1,089,992     $ 388,730       55 %
Freight and handling revenues
    73,800       146,166       72,366       98 %
Other revenues
    17,504       33,560       16,056       92 %
                         
Total revenues
  $ 792,566     $ 1,269,718     $ 477,152       60 %
                         
Tons sold
    21,930       25,808       3,878       18 %
Coal sales realization per ton sold
  $ 31.98     $ 42.23     $ 10.25       32 %
      Coal Revenues. Coal revenues increased for the year ended December 31, 2004 by $388.7 million or 55%, to $1,090.0 million, as compared to the year ended December 31, 2003. This increase was due to a $10.25 per ton increase in the average sales price of our coal and the sale of 3.9 million additional tons over the comparable period last year. The increase in the average sales price of our coal was due to the general increase in coal prices during the period and to our ability to take advantage of the exceptionally high metallurgical coal sale prices by processing and marketing as metallurgical coal some coal qualities that would traditionally have been marketed as steam coal. Approximately 63% and 37% of our tons sold during 2004 were steam coal and metallurgical coal, respectively, as compared to 71% and 29% during the same period in 2003. Our tons sold in 2004 increased by 3.9 million, or 18%, to 25.8 million, primarily due to the effect of our 2003 Acquisitions, which provided approximately 3.4 million additional tons.
      Freight and Handling Revenues. Freight and handling revenues increased to $146.2 million for the year ended December 31, 2004, an increase of $72.4 million compared to the year ended December 31, 2003 due to an increase of 3.4 million tons of export shipments. However, these revenues are offset by equivalent costs and do not contribute to our profitability.
      Other Revenues. Other revenues increased for the year ended December 31, 2004 by $16.1 million, or 92%, to $33.6 million, as compared to the same period for 2003 primarily due to higher equipment and parts sales and equipment repairs in the amount of $8.4 million, an increase in coal handling and processing fees of $6.1 million, and higher sales commissions of $3.4 million, partially offset by reduced trucking revenue of $1.8 million. Other revenues for 2004 include a gain of $1.5 million on the partial satisfaction of an obligation to reclaim certain properties retained by the seller in the Pittston acquisition. Other revenues attributable to our Coal Operations segment were $13.8 million in 2004 and $3.4 million in 2003.

33


 

Costs and Expenses
                                 
    Year Ended December 31.   Increase (Decrease)
         
    2003   2004   $   %
                 
    (In thousands, except per ton data)
Cost of coal sales (exclusive of items shown separately below)
  $ 632,979     $ 931,585     $ 298,606       47%  
Freight and handling costs
    73,800       146,166       72,366       98%  
Cost of other revenues
    16,750       25,064       8,314       50%  
Depreciation, depletion and amortization
    36,054       56,012       19,958       55%  
Asset impairment charge
          5,100       5,100          
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)
    21,949       43,881       21,932       100%  
                         
Total costs and expenses
  $ 781,532     $ 1,207,808     $ 426,276       55%  
                         
Cost of coal sales per ton sold
  $ 28.86     $ 36.10     $ 7.24       25%  
      Cost of Coal Sales. For the year ended December 31, 2004, our cost of coal sales, which excludes charges for depreciation, depletion and amortization, increased $298.6 million, or 47%, to $931.6 million compared to the year ended December 31, 2003. Our cost of coal sales increased as a result of added costs involved in increasing the proportion of our sales made to the metallurgical markets, such as higher preparation and trucking costs, increased prices for steel-related mine supplies, contract mining services, higher prices for purchased coal, and increased variable sales-related costs, such as royalties and severance taxes. Approximately $80.0 million of the increase in the cost of coal sales was due to the 2003 Acquisitions which provided approximately 87% of our increase in tons sold. The average cost per ton sold increased 25% from $28.86 per ton in 2003 to $36.10 per ton in 2004. Our cost of coal sales as a percentage of coal revenues decreased from 90% in 2003 to 85% in 2004. For the years ended December 31, 2004 and 2003 our average cost per ton for our produced and processed coal sales was $33.07 and $28.21, respectively, and our average cost per ton for coal that we purchased from third parties and resold without processing was $45.21 and $31.91, respectively. Cost of coal sales in 2004 included $2.0 million of incentive bonus payments and accruals.
      Freight and Handling Costs. Freight and handling costs increased $72.4 million to $146.2 million during 2004 as compared to 2003, mainly due to a 3.4 million ton increase in export shipments where we initially pay the freight and handling costs and are then reimbursed by the customer. These costs are offset by an equivalent amount of revenue.
      Cost of Other Revenues. Cost of other revenues increased $8.3 million, or 50%, to $25.1 million for the year ended December 31, 2004 as compared to the prior year due to higher volumes of equipment and part sales, equipment repairs, and processing and handling fees. Cost of equipment sales and repairs increased $7.3 million and processing and handling costs increased $2.6 million for the year ended December 31, 2004 as compared to the prior year. The cost of trucking revenues decreased by $1.7 million for 2004 as compared to the prior year. Cost of other revenues attributable to our Coal Operations segment were $7.4 million in 2004 and $2.3 million in 2003.
      Depreciation, Depletion and Amortization. Depreciation, depletion, and amortization increased $20.0 million, or 55%, to $56.0 million for the year ended December 31, 2004 as compared to the same period of 2003 due to capital additions during 2004, resulting in additional depreciation of approximately $9.2 million. The remaining increase is attributable to the impact of the 2003 Acquisitions and 2003 capital additions of $27.7 million. Depreciation, depletion and amortization attributable to our Coal Operations segment were $52.4 million in 2004 and $33.1 million 2003. Depreciation, depletion and amortization per ton increased from $1.64 per ton for the year ended December 31, 2003 to $2.17 per ton in the same period of 2004.

34


 

      Asset Impairment Charge. We own National King Coal, LLC (a mining company) and Gallup Transportation and Transloading Company, LLC (a trucking company) (collectively “NKC”). From our acquisition of NKC through August 31, 2004, it incurred cumulative losses of $2.8 million. While NKC has not experienced sales revenue growth comparable to our other operations, it has been affected by many of the same cost increases. As a result, we were required to assess the recovery of the carrying value of the NKC assets. Based upon that analysis it was determined that the assets of NKC were impaired. An impairment charge of $5.1 million was recorded in September 2004 to reduce the carrying value of the assets of NKC to their estimated fair value. A discounted present value cash flow model was used to determine fair value.
      Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $21.9 million, or 100%, to $43.9 million for the year ended December 31, 2004 compared to the same period in 2003. The increase is attributed to higher staffing levels and resulting salaries, wages and benefits of approximately $4.7 million, increased incentive bonus payments and accruals in the amount of $6.0 million, coal contract buyouts of $3.3 million, increased professional fees of approximately $3.2 million including $1.7 million incurred in documenting, assessing, and improving our controls and procedures due to the requirements of the Sarbanes-Oxley Act of 2002, and a net increase in all other sales, general and administrative expenses of approximately $4.7 million. Our selling, general and administrative expenses as a percentage of total revenues increased from 2.8% in 2003 to 3.5% in 2004.
Interest Expense
      Interest expense increased $12.2 million to $20.0 million during 2004 compared to 2003. The increase was mainly due to the additional interest expense of $10.8 million related to our 10% senior notes issued in May 2004 and the write-off of deferred financing costs of $2.8 million related to our previous credit facility.
Interest Income
      Interest income increased from $0.1 million to $0.5 million as a result of interest received on notes receivable issued in 2004.
Income Tax Expense
      Income tax expense increased $3.3 million to $4.0 million for the year ended December 31, 2004 as compared to the year ended December 31, 2003. Our effective tax rates for the year ended December 31, 2004 and 2003 were 9.0% and 17.3%, respectively. The effective tax rates are lower than the statutory tax rate since we are not subject to tax with respect to the portion of our income before taxes which is attributable to ANR Fund IX Holdings, L.P.’s portion of our earnings and the minority interest’s share in the earnings of ANR Holdings. In addition, our taxable income is reduced by percentage depletion allowances (computed as a percentage of coal revenue, subject to certain income limitations) and the extraterritorial income exclusion (ETI) deduction (computed as a percentage of exported coal revenue, subject to certain income limitations) which reduces our effective tax rates. These reductions in our effective tax rates are offset by the effect of increases in our valuation allowance for deferred tax assets of $0.6 million and $0.8 million recorded in the year ended December 31, 2004 and 2003, respectively. The reduction in our effective tax rate in 2004 compared to 2003 is due primarily to the ETI deduction in 2004 generated from significant export coal revenue, a lower valuation allowance as a percentage of pre-tax income in 2004, and a larger percentage of minority interest in 2004 which has no income tax provision.
Year Ended December 31, 2003 Compared to Year Ended December 31, 2002
Summary
      For the year ended December 31, 2003, revenues increased $607.4 million to $792.6 million over the combined revenues for our Predecessor and successor accounting periods in the year ended December 31, 2002. Net income and operating income for the year ended December 31, 2003 were $2.3 million and $11.0 million, respectively. Net income and operating income on a combined basis for 2002 are not comparable. Tons sold increased from 4.5 million tons for the year ended December 31, 2002 to 21.9 million

35


 

tons in 2003 mainly due to the impact of our 2003 Acquisitions. Coal margin increased from (2.6)% in 2002 to 9.7% in 2003, mainly due to the lower unit cost of coal sold provided by our 2003 Acquisitions.
Revenues
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2002*   2003   $ or Tons   %
                 
    (In thousands, except per ton data)
Coal revenues
  $ 160,975     $ 701,262     $ 540,287       336%  
Freight and handling revenues
    18,010       73,800       55,790       310%  
Other revenues
    6,132       17,504       11,372       185%  
                         
Total revenues
  $ 185,117     $ 792,566     $ 607,449       328%  
                         
Tons sold
    4,469       21,930       17,461       391%  
Coal sales realization per ton sold
  $ 36.02     $ 31.98     $ (4.04 )     (11)%  
 
Reflects the combination of the Predecessor and successor accounting periods in the year ended December 31, 2002.
      Coal Revenues. Coal revenues increased $540.3 million, or 336%, to $701.3 million for the year ended December 31, 2003, from $161.0 million for the year ended December 31, 2002. The increase was primarily due to the 2003 Acquisitions, which contributed an additional 16.0 million tons sold and approximately $512.0 million in revenues, partially offset by a reduction in the average sales price per ton of $4.04 or $18.0 million in revenues. Tons sold increased from 4.5 million tons in 2002 to 21.9 million tons in 2003. The 2003 Acquisitions accounted for 16.0 million of the 17.5 million ton increase in tons sold from 2002 to 2003. Our average sales price per ton decreased 11% from $36.02 per ton in 2002 to $31.98 per ton in 2003, mainly due to our lower percentage of metallurgical coal sales in 2003 as compared to sales of our Predecessor in 2002. Approximately 71% and 29% of our tons sold in the 2003 were steam coal and metallurgical coal, respectively, as compared to 45% and 55% during 2002.
      Freight and Handling Revenues. Freight and handling revenues increased $55.8 million from $18.0 million in 2002 due to increased volumes resulting from the 2003 Acquisitions, which contributed approximately $33.5 million of the increase. An increase in overseas export tons of approximately 1.1 million tons was responsible for most of the remaining increase in freight and handling revenues. These revenues are offset by equivalent costs and do not contribute to our profitability.
      Other Revenues. Other revenues, principally equipment repair and sales, and coal handling, terminalling and processing fees, rents and royalties increased $11.4 million to $17.5 for 2003, mainly due to the 2003 Acquisitions, which provided trucking revenues of $4.0 million, coal handling, terminalling and processing fees in the amount of $2.8 million and royalty income of $1.3 million. Other revenues for 2002 consisted of equipment repair and sales income, which increased $1.7 million in 2003. Other revenues attributable to our Coal Operations segment were $3.4 million for the year ended December 31, 2003, and we had no other revenues attributable to our Coal Operations segment for the year ended December 31, 2002.

36


 

Costs and Expenses
                                 
    Year Ended   Increase
    December 31,   (Decrease)
         
    2002*   2003   $   %
                 
    (In thousands, except per ton data)
Cost of coal sales (exclusive of items shown separately below)
  $ 165,192     $ 632,979     $ 467,787       283%  
Freight and handling costs
    18,010       73,800       55,790       310%  
Cost of other revenues
    8,093       16,750       8,657       107%  
Depreciation, depletion and amortization
    7,088       36,054       28,966       409%  
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)
    9,268       21,949       12,681       137%  
Costs to exit business
    25,274             (25,274 )        
                         
Total costs and expenses
  $ 232,925     $ 781,532     $ 548,607       236%  
                         
Cost of coal sales per ton sold
  $ 36.96     $ 28.86     $ (8.10 )     (22)%  
 
Reflects the combination of the Predecessor and successor accounting periods in the year ended December 31, 2002.
      Cost of Coal Sales. Our cost of coal sales increased $467.8 million, or 283%, to $633.0 million for the year ended December 31, 2003, from $165.2 million for the year ended December 31, 2002. The 2003 Acquisitions accounted for $461.8 million of the increase in our cost of coal sales and for 93% of the 12.9 million ton increase in our produced and processed coal sales for 2003. The average cost per ton sold decreased 22% from $36.96 per ton in 2002 to $28.86 per ton in 2003 as a result of increased production, which reduced our fixed costs per ton, as well as lower costs of coal produced from mines acquired in the 2003 Acquisitions. Our cost of coal sales as a percentage of coal revenues decreased from 103% in 2002 to 90% in 2003.
      Freight and Handling Costs. Freight and handling costs increased $55.8 million to $73.8 million for the year ended December 31, 2003 as compared to the prior period, primarily due to increased sales volumes resulting from the 2003 Acquisitions, which contributed approximately $33.5 million of the increase. An increase in overseas export tons of approximately 1.1 million tons was responsible for most of the remaining increase in freight and handling costs. These costs are offset by an equivalent amount of revenue.
      Cost of Other Revenues. Cost of other revenues increased $8.7 million, or 107%, to $16.8 million for 2003 as compared to 2002 as a result of the 2003 Acquisitions, in which we acquired trucking and coal processing operations, and their related costs of $8.7 million, as the cost for 2002 includes only those related to equipment repair and sales income, which remained relatively unchanged. Cost of equipment repair and sales for 2002 included a litigation settlement, therefore cost for 2003 did not increase over 2002 with the increased sales volumes. Cost of other revenues attributable to our Coal Operations segment were $2.3 million for the year ended December 31, 2003 and we had no cost of other revenues attributable to our Coal Operations segment for the year ended December 31, 2002.
      Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense for the year ended December 31, 2003 was $36.1 million, an increase of $29.0 million from the prior year. The increase in expense is attributable to the 2003 Acquisitions, and the 2003 capital additions of $27.7 million, as depreciation, depletion and amortization expense per ton showed only a slight increase from $1.59 per ton in 2002 to $1.64 per ton in 2003. Depreciation, depletion and amortization attributable to our Coal Operations segment were $33.1 million for the year ended December 31, 2003 and $7.0 million for the year ended December 31, 2002.
      Selling, General and Administrative Expenses. Selling, general and administrative expenses increased by $12.7 million to $21.9 million, but decreased from $2.07 per ton sold to $1.00 per ton sold from 2002 to

37


 

2003, primarily due to a significant increase in tons sold, partially offset by additional expenses of $2.0 million associated with transition services provided by the selling companies. Our selling, general and administrative expenses as a percentage of total revenues decreased from 5.0% in 2002 to 2.8% in 2003.
      Costs to Exit Business. For the year ended December 31, 2002, our Predecessor recorded a charge of $25.3 million for a pension plan early withdrawal penalty. The early withdrawal penalty was incurred when our Predecessor withdrew from a multi-employer pension plan when we purchased their operations.
Interest Expense
      Interest expense increased to $7.8 million for the year ended December 31, 2003 from less than $0.1 million for the period from January 1, 2002 to December 13, 2002. The increase is due to interest on loans to finance the 2003 Acquisitions.
Interest Income
      Interest income decreased from $2.1 million for the period from January 1 to December 13, 2002 to $0.1 million in 2003. Interest income for the period from January 1, 2002 to December 13, 2002 was attributable to interest earned on Virginia tax credits and an employee benefit trust. We did not acquire the assets of the employee benefit trust or the receivable for the Virginia tax credits.
Income Tax Expense (Benefit)
      Income taxes increased $17.9 million from a benefit of $17.2 million for the period from January 1, 2002 to December 13, 2002 to an expense of $0.7 million for the year ended December 31, 2003. This increase in income taxes was attributable primarily to the increase in pre-tax income. The effective tax rate for the period from January 1, 2002 to December 13, 2002 and for the year ended December 31, 2003 was 41.4% and 17.3%, respectively. In 2003, tax was not provided on ANR Fund IX Holdings, L.P.’s portion of our earnings and the minority interest owners’ share in the earnings of ANR Holdings. In addition, in periods when a pre-tax loss is reported, percentage depletion increases the effective tax rate (increases the tax benefit) whereas in periods when pre-tax income is reported, percentage depletion decreases the effective tax rate (decreases the tax expense).
Liquidity and Capital Resources
      Our primary liquidity and capital resource requirements are to finance the cost of our coal production and purchases, to make capital expenditures, and to service our debt and reclamation obligations. Historically we have made significant distributions to our equity holders, and in connection with our Internal Restructuring we have agreed to pay the Sponsor Distributions totaling $10.5 million in cash or, to the extent we are not permitted by the terms of our credit facility or the indenture governing our senior notes to pay the Sponsor Distributions in cash, in shares of our common stock. Our primary sources of liquidity are cash flow from sales of our produced and purchased coal, other income and borrowings under our senior credit facility.
      At December 31, 2004, our available liquidity was $121.4 million, including cash of $7.4 million and $114.0 million available under our credit facility. Total debt represented 81% of our total capitalization at December 31, 2004.
      We currently project cash capital spending for 2005 of $90 million to $120 million. These forecasted expenditures are to be used to develop new mines and replace or add equipment. We believe that cash generated from our operations and borrowings under our credit facility will be sufficient to meet our working capital requirements, anticipated capital expenditures and debt service requirements for at least the next twelve months.
Cash Flows
      Cash provided by operating activities was $106.8 million for the year ended December 31, 2004, an increase of $52.7 million from the same period in 2003. Cash provided by operations for 2004 benefited from

38


 

the effects of our 2003 Acquisitions and the strength of the coal markets during the period. This increase is attributable to an increase in net income of $17.7 million for 2004 over 2003, an increase in non-cash charges included in net income of $49.9 million and partially offset by the effects of a $15.0 million increase in net operating assets and liabilities.
      Net cash used in investing activities was $86.2 million during the year ended December 31, 2004, $13.9 million less than the same period of 2003. Capital expenditures increased $44.3 million, to $72.0 million during 2004. The increase in capital expenditures was primarily due to the replacement of equipment, new mine development and upgrades to a preparation plant. In the second quarter of 2003, we sold our interest in certain coal properties acquired in the purchase of our Predecessor, and a royalty interest acquired in our Coastal Coal Company acquisition for cash of $65.2 million. We also paid $133.8 million for the Coastal Coal Company, U.S. AMCI and Mears acquisitions in 2003. As part of a coal supply agreement, we loaned an unrelated coal supplier $10.0 million in June 2004 at a variable rate to be repaid in installments over a two-year period beginning in August 2004. The loan is secured by the assets of the debtor and personally guaranteed by the debtor’s owner. The related coal supply agreement with the debtor should provide us with approximately 40,000 tons of coal per month through March of 2006. In September 2004, we also acquired an equity interest for a subscription price of $6.5 million in a company which is developing a mining property in Venezuela. Payments totaling $4.5 million were made during the year ended December 31, 2004.
      Net cash used in financing activities during the year ended December 31, 2004 was $24.4 million compared with net cash provided by financing activities of $48.8 million in the prior year. Net cash used by financing activities included the net proceeds of $171.5 million received as a result of the issuance of our $175 million 10% senior notes in May 2004 offset by distributions made to our equity owners of $115.6 million, the repayment of bank and other debt in the amount of $75.8 million, $10.5 million paid for debt issuance costs and $1.7 for deferred stock offering costs during the year ended December 31, 2004. We received $18.3 million in capital contributions and $20.0 million in advances from affiliates during the year ended December 31, 2003. In addition, we incurred bank and other debt in the net amount of $12.9 million during the year ended December 31, 2003.
      Our operations provided us cash of $54.1 million for the year ended December 31, 2003, while the operations of our Predecessor used cash of $13.8 million. Our net income increased $26.6 million to $2.3 million when compared to our Predecessor’s net loss of $24.3 million. Our non-cash charges increased by $36.8 million in 2003 mainly due to increased depreciation, depletion and amortization charges associated with the 2003 Acquisitions. Net changes in operating assets and liabilities increased our operating cash flow by $15.1 million in 2003 while net changes in operating assets and liabilities increased cash flow from operations by $11.3 million for the period from January 1, 2002 to December 13, 2002.
      Net cash used in investing activities was $100.1 million for the year ended December 31, 2003. Cash used in investing activities includes $133.8 million for the acquisitions of Coastal Coal Company, U.S. AMCI, and Mears and capital expenditures of $27.7 million. The 2003 period includes proceeds of $65.2 million received from the sales of coal reserves and mineral interests acquired in the Pittston Coal Company and Coastal Coal Company acquisitions. The investing activities of our Predecessor in 2002 consisted primarily of capital expenditures.
      Net cash provided by financing activities was $48.8 million and $35.8 million for the year ended December 31, 2003 and the period from January 1, 2002 to December 13, 2002, respectively. In 2003, we entered into a credit facility which provided for a $45.0 million term loan and a $75.0 million revolving credit line.
      Proceeds from borrowings under this credit facility were $58.5 million in 2003. Repayments of notes payable and long-term debt totaled $45.7 million. We received $15.2 million for common stock issued and we received advances from affiliates of $20.0 million during the year ended December 31, 2003. Cash provided by financing activities of our Predecessor in the period from January 1, 2002 to December 13, 2002 consisted of advances from affiliates.

39


 

Credit Facility and Long-term Debt
      As of December 31, 2004, our total long-term indebtedness, including capital lease obligations, consisted of the following (in thousands):
           
    December 31,
    2004
     
10% Senior notes due 2012
  $ 175,000  
Revolving credit facility
    8,000  
Variable rate term notes(1)
    1,466  
Capital lease obligation
    1,995  
Other
    16  
       
 
Total long-term debt
    186,477  
Less current portion
    (1,693 )
       
 
Long-term debt, net of current portion
  $ 184,784  
       
 
(1)  The term notes, which were issued in connection with equipment financing provided by The CIT Group Equipment Financing, Inc., bear interest at a variable rate of 5.71% at December 30, 2004, are payable in monthly installments ranging from $34,000 to $64,000 through April 2006 and are secured by a lien on the equipment purchased with the proceeds of the notes.
      On May 18, 2004, our subsidiaries Alpha Natural Resources, LLC and Alpha Natural Resources Capital Corp. issued $175.0 million of 10% senior notes due June 2012 in a private placement offering under Rule 144A of the Securities Act of 1933, resulting in net proceeds of approximately $171.5 million after fees and other offering costs. The senior notes are unsecured but are guaranteed fully and unconditionally on a joint and several basis by all of Alpha Natural Resources, LLC’s wholly-owned domestic restricted subsidiaries and, beginning on March 30, 2005, by certain of its parent entities. Interest is payable semi-annually in June and December. Interest of $9.4 million was paid in 2004 and $1.5 million of interest had accrued as of December 31, 2004. Additional interest on the senior notes is payable in certain circumstances if a registration statement with respect to an offer to exchange the notes for a new issue of equivalent notes registered under the Securities Act has not been declared effective on or prior to February 14, 2005 (270 days after the notes were issued), or if the offer to exchange the notes is not consummated within 30 business days after February 14, 2005. The amount of this additional interest is equal to 0.25% of the principal amount of the notes per annum during the first 90-day period after a failure to have the registration statement declared effective or consummate the exchange offer, and it will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until the registration statement has been declared effective and the exchange offer has been consummated, up to a maximum amount of additional interest of 1.0% per annum. We expect to incur $0.1 million in additional interest with respect to the period from February 15, 2005 to March 31, 2005 as a result of our failure to comply with these obligations regarding our senior notes. We expect to file a registration statement with respect to the exchange offer for our senior notes as soon as commercially practicable following the date of this annual report, and to seek to have the registration statement declared effective by the SEC and to consummate the exchange offer as soon as commercially practicable thereafter.
      On May 28, 2004, Alpha Natural Resources, LLC entered into a credit facility with a group of lending institutions. The credit facility, as amended, provides for a revolving line of credit of up to $125.0 million and a funded letter of credit facility of up to $50.0 million. As of December 31, 2004, $8.0 million principal amount in borrowings and letters of credit totaling $3.0 million were outstanding under the revolving line of credit, leaving $114.0 million available for borrowing on the line of credit. As of December 31, 2004, the funded letter of credit facility was fully utilized at $50.0 million at an annual fee of 3.1% of the outstanding amount. Amounts drawn under the revolver bear interest at a variable rate based upon either the prime rate or a London Interbank Offered Rate (LIBOR), in each case plus a spread that is dependent on our leverage ratio. The interest rate applicable to our borrowings under the revolver was 7.0% as of December 31, 2004. The

40


 

principal balance of the revolving credit note is due in May 2009. Alpha NR Holding, Inc., Alpha NR Ventures, Inc., ANR Holdings and each of the subsidiaries of Alpha Natural Resources, LLC have guaranteed Alpha Natural Resources LLC’s obligations under the revolving credit facility, as amended. The obligations of Alpha NR Holding, Alpha NR Ventures, ANR Holdings, Alpha Natural Resources, LLC and its subsidiaries under the credit facility are collateralized by the assets of those entities, including the equity of the subsidiaries of those entities. We must pay an annual commitment fee up to a maximum of 1/2 of 1% of the unused portion of the commitment. We were in compliance with our debt covenants under the credit facility as of December 31, 2004.
      The credit facility, as amended, and the indenture governing the senior notes each impose certain restrictions on our subsidiaries, including restrictions on our subsidiaries’ ability to: incur debt; grant liens; enter into agreements with negative pledge clauses; provide guarantees in respect of obligations of any other person; pay dividends and make other distributions; make loans, investments, advances and acquisitions; sell assets; make redemptions and repurchases of capital stock; make capital expenditures; prepay, redeem or repurchase debt; liquidate or dissolve; engage in mergers or consolidations; engage in affiliate transactions; change businesses; change our fiscal year; amend certain debt and other material agreements; issue and sell capital stock of subsidiaries; engage in sale and leaseback transactions; and restrict distributions from subsidiaries. In addition, the credit facility provides that we must meet or exceed certain interest coverage ratios and must not exceed certain leverage ratios.
      Borrowings under our credit facility will be subject to mandatory prepayment (1) with 100% of the net cash proceeds received from asset sales or other dispositions of property by ANR Holdings and its subsidiaries (including insurance and other condemnation proceedings), subject to certain exceptions and reinvestment provisions, (2) with 100% of the net cash proceeds received by ANR Holdings and its subsidiaries from the issuance of debt securities or other incurrence of debt, excluding certain indebtedness, and (3) 50% (or 25%, if our leverage ratio is less than or equal to 2.00 to 1.00 but greater than 1.00, or 0% if our leverage ratio is less than or equal to 1.00) of the net cash proceeds of equity issuances of ANR Holdings and its subsidiaries.
Other
      As a regular part of our business, we review opportunities for, and engage in discussions and negotiations concerning, the acquisition of coal mining assets and interests in coal mining companies, and acquisitions of, or combinations with, coal mining companies. When we believe that these opportunities are consistent with our growth plans and our acquisition criteria, we will make bids or proposals and/or enter into letters of intent and other similar agreements, which may be binding or nonbinding, that are customarily subject to a variety of conditions and usually permit us to terminate the discussions and any related agreement if, among other things, we are not satisfied with the results of our due diligence investigation. Any acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. There can be no assurance that additional financing will be available on terms acceptable to us, or at all.
Analysis of Material Debt Covenants
      We were in compliance with all covenants under our credit facility and the indenture governing our senior notes as of December 31, 2004.
      The financial covenants in our credit facility require, among other things, that:
  •  Alpha Natural Resources, LLC must maintain a leverage ratio, defined as the ratio of total debt to adjusted EBITDA (as defined in the credit agreement), of less than 3.75 at December 31, 2004, 3.50 at March 31 and June 30, 2005, 3.25 at September 30 and December 31, 2005, 3.15 at March 31, June 30, September 30 and December 31, 2006 and 3.00 at March 31, 2007 (and thereafter), respectively, with adjusted EBITDA being computed using the most recent four quarters; and
 
  •  Alpha Natural Resources, LLC must maintain an interest coverage ratio, defined as the ratio of adjusted EBITDA (as defined in the credit agreement), to cash interest expense (defined as the sum

41


 

  of cash interest expense plus cash letter of credit fees and commissions), of greater than 2.50 at September 30, 2004 and at each quarter end thereafter.
      Based upon adjusted EBITDA (as defined in the credit agreement), Alpha Natural Resources, LLC’s leverage ratio and interest coverage ratio for the twelve months ended December 31, 2004 were 1.62 (maximum of 3.75) and 6.02 (minimum of 2.50), respectively. Alpha Natural Resources, LLC maintained the leverage and interest coverage ratios specified in, and were in compliance with, the credit facility as of December 31, 2004.
      Adjusted EBITDA, as defined in the credit agreement, is used to determine compliance with many of the covenants under the credit facility. The breach of covenants in the credit facility that are tied to ratios based on adjusted EBITDA could result in a default under the credit facility and the lenders could elect to declare all amounts borrowed due and payable. Any acceleration would also result in a default under our indenture.
      Because the covenants in our credit facility relate to Alpha Natural Resources, LLC, EBITDA as presented in the table below reflects adjustments for minority interest necessary to reconcile our net income to Alpha Natural Resources, LLC’s EBITDA. Adjusted EBITDA is defined as EBITDA further adjusted to exclude non-recurring items, non-cash items and other adjustments permitted in calculating covenant compliance under our credit facility, as shown in the table below. We believe that the inclusion of supplementary adjustments to EBITDA applied in presenting adjusted EBITDA is appropriate to provide additional information to investors to demonstrate compliance with our financial covenants. Our credit facility deems adjusted EBITDA to be equal to $16.8 million for the three months ended March 31, 2004.
                                 
    Three Months   Three Months   Three Months   Twelve Months
    Ended   Ended   Ended   Ended
    June 30,   September 30,   December 31,   December 31,
    2004   2004   2004   2004(5)
                 
    (In thousands)    
Net income
  $ 12,088     $ 5,342     $ 1,115          
Interest expense, net
    6,711       5,449       5,344          
Income tax expense (benefit)
    3,022       1,335       (772 )        
Depreciation, depletion and amortization expenses
    13,111       14,312       16,660          
                         
EBITDA
    34,932       26,438       22,347          
Minority interest(1)
    12,872       5,688       268          
Asset impairment charge(2)
          5,100                
                         
Adjusted EBITDA
  $ 47,804     $ 37,226     $ 22,615     $ 124.445 (5)
                         
Leverage ratio(3)
                            1.62 x
Interest coverage ratio(4)
                            6.02 x
 
(1)  Because our credit facility and our senior notes are issued by our subsidiaries, we are required to adjust our EBITDA for our minority interest which does not exist at the subsidiary level.
 
(2)  We are required to adjust EBITDA under our credit facility for the asset impairment charge related to our NKC operations.
 
(3)  Leverage ratio is defined in our credit facility as total debt divided by adjusted EBITDA.
 
(4)  Interest coverage ratio is defined in our credit facility as adjusted EBITDA divided by cash interest expense.
 
(5)  We are unable to show the individual components of adjusted EBITDA for the twelve months ended December 31, 2004, because our credit facility deems adjusted EBITDA to be equal to $16.8 million for the three months ended March 31, 2004.

42


 

Contractual Obligations
      The following is a summary of our significant contractual obligations as of December 31, 2004 (in thousands):
                                         
    2005   2006-2007   2008-2009   After 2009   Total
                     
Long-term debt and capital leases(1)
  $ 1,693     $ 1,236     $ 8,548     $ 175,000     $ 186,477  
Equipment purchases
    43,271                         43,271  
Operating leases
    4,307       6,463       769       261       11,800  
Minimum royalties
    9,212       17,368       15,509       30,031       72,120  
Coal purchases
    342,422       110,463                   452,885  
Coal contract buyout
    680       1,360       1,360       567       3,967  
                               
Total
  $ 401,585     $ 136,890     $ 26,186     $ 205,859     $ 770,520  
                               
 
(1)  Long-term debt and capital leases include principal amounts due in the years shown. Interest payable on these obligations, assuming a rate of 7.0% on our variable rate loan, would be approximately $18.3 million in 2005, $36.4 million in 2006 to 2007, $35.8 million in 2008 to 2009, and $42.3 million after 2009.
      Additionally, we have long-term liabilities relating to mine reclamation and end-of-mine closure costs, workers’ compensation benefits and all of our operating and management-services subsidiaries have long-term liabilities relating to retiree health care (postretirement benefits). The table below reflects the estimated undiscounted payments of these obligations as of December 31, 2004 (in thousands):
                                         
    2005   2006-2007   2008-2009   After 2009   Total
                     
Reclamation
  $ 6,691     $ 11,062     $ 8,473     $ 34,209     $ 60,435  
Postretirement
    39       193       1,078       155,365       156,675  
Workers’ compensation benefits
    1,612       2,235       324       2,119       6,290  
                               
Total
  $ 8,342     $ 13,490     $ 9,875     $ 191,693     $ 223,400  
                               
Off-Balance Sheet Arrangements
      In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. No liabilities related to these arrangements are reflected in our combined balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.
      From time to time, we provide guarantees to financial institutions to facilitate the acquisition of mining equipment by third parties who mine coal for us. This arrangement is beneficial to us because it helps insure a continuing source of coal production.
      Federal and state laws require us to secure payment of certain long-term obligations such as mine closure and reclamation costs, federal and state workers’ compensation, coal leases and other obligations. We typically secure these payment obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond or a bank letter of credit, either of which would require a greater use of our credit facility. We then use bank letters of credit to secure our surety bonding obligations as a lower cost alternative than securing those bonds with cash. Under our $125.0 million committed bonding facility, we are required to provide bank letters of credit in an amount up to 50% of the aggregate bond liability. Recently, surety bond costs have increased, while the market terms of surety bonds have generally become less favorable to us. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.

43


 

      As of December 31, 2004, we had outstanding surety bonds with third parties for post-mining reclamation totaling $91.4 million plus $8.0 million for miscellaneous purposes. We maintained letters of credit as of December 31, 2004 totaling $53.0 million to secure reclamation and other obligations.
      In connection with our acquisition of Coastal Coal Company, the seller, El Paso CGP Company, has agreed to retain and indemnify us for all workers’ compensation and black lung claims incurred prior to the acquisition date of January 31, 2003. The majority of this liability relates to claims in the state of West Virginia. If El Paso CGP Company fails to honor its agreement with us, then we would be liable for the payment of those claims, which were estimated in April 2004 to be approximately $5.4 million on an undiscounted basis using claims data through June 2003. El Paso CGP Company has posted a bond with the state of West Virginia for the required discounted amount of $3.7 million for claims incurred prior to the acquisition.
Outlook
      While our business is subject to the general risks of the coal industry and specific individual risks, we believe that the outlook for coal markets remains positive worldwide, assuming continued growth in the U.S., China, Pacific Rim, Europe and other industrialized economies that are increasing coal demand for electricity generation and steelmaking. Published indices show improved year-over-year coal prices in most U.S. and global coal markets, and worldwide coal supply/demand fundamentals remain tight due to high market demand, transportation constraints and production difficulties in most countries. Metallurgical coal is generally selling at a significant premium to steam coal, and we expect that pricing relationship to continue based on the same assumptions made above.
      For 2005, we are targeting annual production of 20 million to 22 million tons and total sales volume of 25 million to 26 million tons. Approximately 97% and 51% of our planned production in 2005 and 2006, respectively, has been priced as of February 1, 2005.
      We anticipate continued challenges with railroad service, hopefully with gradual improvement in rail service beginning in the second half of 2005. We are working with our customers and the railroads in an effort to address these issues in a timely manner.
      Based on current market conditions in the steam and metallurgical coal markets, we anticipate increasing the proportion of our metallurgical coal sales that are committed under long-term contracts as compared to prior years and continuing to market portions of our high quality steam coal production as metallurgical coal. We plan to focus on organic growth by continuing to develop our existing reserves. In addition, we also plan to evaluate attractively priced acquisitions that create potential synergies with our existing operations.
      We anticipate that we may record a net loss for the fiscal quarter ending March 31, 2005, as the result of stock-based compensation charges that we expect to record during the quarter. See “— Overview — Internal Restructuring and Initial Public Offering.” See “— Risks Relating to Our Company” for a discussion of other factors that could affect us in the future.
Critical Accounting Estimates and Assumptions
      Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our combined financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). GAAP requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.
      Reclamation. Our asset retirement obligations arise from the federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities

44


 

include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. We account for the costs of our reclamation activities in accordance with the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based upon third-party costs. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. In accordance with the provisions of SFAS No. 143, we determine the fair value of our asset retirement obligations. In order to determine fair value, we must also estimate a discount rate and third-party margin. Each is discussed further below:
  •  Discount Rate. SFAS No. 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of SFAS No. 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.
 
  •  Third-Party Margin. SFAS No. 143 requires the measurement of an obligation to be based upon the amount a third party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin was added to the estimated costs of these activities. This margin was estimated based upon our historical experience with contractors performing certain types of reclamation activities. The inclusion of this margin will result in a recorded obligation that is greater than our estimates of our cost to perform the reclamation activities. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is completed.
      On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revisions to cost estimates and productivity assumptions, to reflect current experience. At December 31, 2004, we had recorded asset retirement obligation liabilities of $39.6 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2004, we estimate that the aggregate undiscounted cost of final mine closure is approximately $58.9 million.
      Coal Reserves. There are numerous uncertainties inherent in estimating quantities of economically recoverable coal reserves. Many of these uncertainties are beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled by our internal engineers and geologists and reviewed by a third-party consultant. Some of the factors and assumptions that impact economically recoverable reserve estimates include:
  •  geological conditions;
 
  •  historical production from the area compared with production from other producing areas;
 
  •  the assumed effects of regulations and taxes by governmental agencies;
 
  •  assumptions governing future prices; and
 
  •  future operating costs.
      Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and these variances may be material.
      Postretirement Medical Benefits. Three of our subsidiaries have long-term liabilities for postretirement benefit cost obligations. Detailed information related to these liabilities is included in the notes to our

45


 

combined financial statements included elsewhere in this annual report. Liabilities for postretirement benefit costs are not funded. The liability is actuarially determined, and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for postretirement benefit costs. The discount rate assumption reflects the rates available on high quality fixed income debt instruments. The discount rate used to determine the net periodic benefit cost for postretirement benefits other than pensions was 6.25% for the year ended December 31, 2004 and 6.75% for the year ended December 31, 2003. We make assumptions related to future trends for medical care costs in the estimates of retiree health care and work-related injury and illness obligations. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our requirement to satisfy these or additional obligations.
      Effective July 1, 2004, we began offering postretirement medical benefits to active, union-free employees that will provide a credit equal to $20 per month per year of service for pre-65 year-old retirees, and $9 per month per year of service for post-65-year old retirees toward the purchase of medical benefits (as defined) from the Company. This new plan resulted in prior service cost of $27.1 million which will be amortized over the remaining service lives of the union-free employees. This amortization of prior service cost is expected to be approximately $2.8 million per year. We recorded $3.7 million in costs with respect to this new plan in 2004, consisting of service cost, amortization of prior service cost and interest cost.
      Workers’ Compensation. Workers’ compensation is a system by which individuals who sustain personal injuries due to job-related accidents are compensated for their disabilities, medical costs, and on some occasions, for the costs of their rehabilitation, and by which the survivors of workers who suffer fatal injuries receive compensation for lost financial support. The workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee who is injured in the course of employment. Our operations are covered through a combination of a self-insurance program, participation in a state run program, and an insurance policy. We accrue for any self-insured liability by recognizing costs when it is probable that a covered liability has been incurred and the cost can be reasonably estimated. Our estimates of these costs are adjusted based upon actuarial studies. Actual losses may differ from these estimates, which could increase or decrease our costs.
      Coal Workers’ Pneumoconiosis. We are responsible under various federal statutes, including the Coal Mine Health and Safety Act of 1969, and various states’ statutes, for the payment of medical and disability benefits to eligible employees resulting from occurrences of coal workers’ pneumoconiosis disease (black lung). Our operations are covered through a combination of a self-insurance program, in which we are a participant in a state run program, and an insurance policy. We accrue for any self-insured liability by recognizing costs when it is probable that a covered liability has been incurred and the cost can be reasonably estimated. Our estimates of these costs are adjusted based upon actuarial studies. Actual losses may differ from these estimates, which could increase or decrease our costs.
      Income Taxes. We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes”, which requires the recognition of deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, we take into account various factors including the expected level of future taxable income and available tax planning strategies. If future taxable income is lower than expected or if expected tax planning strategies are not available as anticipated, we may record a change to the valuation allowance through income tax expense in the period the determination is made.
New Accounting Pronouncements
      In November 2004, the Financial Accounting Standards Board (the FASB) issued SFAS No. 151, Inventory Costs, which amends the guidance in Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). SFAS No. 151 clarifies that abnormal amounts of idle facility expense,

46


 

freight, handling costs, and wasted materials (spoilage) should be recognized as current-period charges instead of inventory costs. The provisions of this pronouncement will be effective for inventory costs incurred during fiscal years ending after June 15, 2005. The Company is currently evaluating whether the adoption of SFAS No. 151 will have any material financial statement impact.
      In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which requires companies to expense the fair value of equity awards over the required service period. This Statement is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123(R) supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, which uses the intrinsic value method to value stock-based compensation. The effective date of SFAS No. 123(R) will be as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. There are various methods of adopting SFAS 123(R), and the Company has not yet determined what method we will use. The Company will adopt SFAS No. 123(R) effective July 1, 2005.
      In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions. This Statement’s amendments are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, SFAS No. 153 eliminates the narrow exception for nonmonetary exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. The provisions of this pronouncement will be effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. We do not expect the adoption of SFAS No. 153 to have any material impact on our financial statements.
Discussion of Seasonality Impacts on Operations
      Our business is seasonal, with operating results varying from quarter to quarter. We have historically experienced lower sales during winter months primarily due to the freezing of lakes that we use to transport coal to some of our customers. As a result, our first quarter cash flow and profits have been, and may continue to be, negatively impacted. Lower than expected sales by us during this period could have a material adverse effect on the timing of our cash flows and therefore our ability to service our obligations with respect to our existing and future indebtedness.
Risks Relating to Our Company
A substantial or extended decline in coal prices could reduce our revenues and the value of our coal reserves.
      Our results of operations are substantially dependent upon the prices we receive for our coal. The prices we receive for coal depend upon factors beyond our control, including:
  •  the supply of and demand for domestic and foreign coal;
 
  •  the demand for electricity;
 
  •  domestic and foreign demand for steel and the continued financial viability of the domestic and/or foreign steel industry;
 
  •  the proximity to, capacity of, and cost of transportation facilities;
 
  •  domestic and foreign governmental regulations and taxes;
 
  •  air emission standards for coal-fired power plants;
 
  •  regulatory, administrative, and judicial decisions;
 
  •  the price and availability of alternative fuels, including the effects of technological developments; and
 
  •  the effect of worldwide energy conservation measures.

47


 

      Declines in the prices we receive for our coal could adversely affect our operating results and our ability to generate the cash flows we require to improve our productivity and invest in our operations.
Our coal mining production is subject to conditions and events beyond our control, which could result in higher operating expenses and/or decreased production and adversely affect our operating results.
      Our coal mining operations are conducted, in large part, in underground mines and, to a lesser extent, at surface mines. The level of our production at these mines is subject to operating conditions and events beyond our control that could disrupt operations, affect production and the cost of mining at particular mines for varying lengths of time and have a significant impact on our operating results. Adverse operating conditions and events that we or our Predecessor have experienced in the past include:
  •  delays and difficulties in acquiring, maintaining or renewing necessary permits or mining or surface rights;
 
  •  changes or variations in geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;
 
  •  mining and processing equipment failures and unexpected maintenance problems;
 
  •  limited availability of mining and processing equipment and parts from suppliers;
 
  •  interruptions due to transportation delays;
 
  •  adverse weather and natural disasters, such as heavy rains and flooding;
 
  •  accidental mine water discharges;
 
  •  the unavailability of qualified labor;
 
  •  strikes and other labor-related interruptions; and
 
  •  unexpected mine safety accidents, including fires and explosions from methane and other sources.
      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). If any of these conditions or events occur in the future at any of our mines, they may increase our cost of mining and delay or halt production at the particular mines either permanently or for varying lengths of time, which could adversely affect our operating results.
Any change in coal consumption patterns by steel producers or North American electric power generators resulting in a decrease in the use of coal by those consumers could result in lower prices for our coal, which would reduce our revenues and adversely impact our earnings and the value of our coal reserves.
      Steam coal accounted for approximately 63% of our 2004 coal sales volume. The majority of our sales of steam coal in 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 2003, 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

48


 

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 represented approximately 37% of our 2004 coal sales volume. 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. Any deterioration in conditions in the U.S. steel industry would reduce the demand for our metallurgical coal and 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.
A decline in demand for metallurgical coal would limit our ability to sell our high quality steam coal as higher-priced metallurgical coal and could affect the economic viability of certain of our mines that have higher operating costs.
      Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on the prevailing conditions in the metallurgical and steam coal markets. We decide whether to mine, process and market these coals as metallurgical or steam coal based on management’s assessment as to which market is likely to provide us with a higher margin. We consider a number of factors when making this assessment, including the difference between the current and anticipated future market prices of steam coal and metallurgical coal, the lower volume of saleable tons that results from producing a given quantity of reserves for sale in the metallurgical market instead of the steam market, the increased costs incurred in producing coal for sale in the metallurgical market instead of the steam market, the likelihood of being able to secure a longer-term sales commitment by selling coal into the steam market and our contractual commitments to deliver different types of coals to our customers. During 2004, we believe that we sold approximately 8% of our produced and processed coal as metallurgical coal that we would have sold as steam coal in the market conditions prevalent during 2003. We believe that we generated approximately $65.0 million in additional revenues by selling this production as metallurgical coal rather than steam coal during 2004, based on a comparison of the actual sales price and volume versus the then-prevailing market price for steam coal and the volume of coal that we would have sold if the coal had been mined, processed and marketed as steam coal. A decline in the metallurgical market relative to the steam market could cause us to shift coal from the metallurgical market to the steam market, thereby reducing our revenues and profitability.
      Most of our metallurgical coal reserves possess quality characteristics that enable us to mine, process and market them as high quality steam coal. However, some of our mines operate profitably only if all or a portion of their production is sold as metallurgical coal to the steel market. If demand for metallurgical coal declined to the point where we could earn a more attractive return marketing the coal as steam coal, these mines may not be economically viable and may be subject to closure. Such closures would lead to accelerated reclamation costs, as well as reduced revenue and profitability.
Our business will be adversely affected if we are unable to develop or acquire additional coal reserves that are economically recoverable.
      Our profitability depends substantially on our ability to mine coal reserves possessing quality characteristics desired by our customers in a cost-effective manner. As of December 31, 2004, we owned or leased 511.1 million tons of proven and probable coal reserves that will support current production levels for more than 25 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

49


 

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 decline 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.
Defects in title of any leasehold interests in our properties could limit our ability to mine these properties or result in significant unanticipated costs.
      We conduct a significant part of our mining operations on properties that we lease. Title to most of our leased properties and mineral rights is not thoroughly verified until a permit to mine the property is obtained, and in some cases title with respect to leased properties is not verified at all. Our right to mine some of our reserves may be materially adversely affected by defects in title or boundaries. In order to obtain leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs, which could adversely affect our profitability.
Acquisitions that we have completed since our formation, as well as acquisitions that we may undertake in the future, involve a number of risks, any of which could cause us not to realize the anticipated benefits.
      Since our formation and the acquisition of our Predecessor in December 2002, we have completed three significant acquisitions and several smaller acquisitions and investments. We continually seek to expand our operations and coal reserves through acquisitions. If we are unable to successfully integrate the companies, businesses or properties we are able to acquire, our profitability may decline and we could experience a material adverse effect on our business, financial condition, or results of operations. Acquisition transactions involve various inherent risks, including:
  •  uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental or mine safety liabilities) of, acquisition candidates;
 
  •  the potential loss of key customers, management and employees of an acquired business;
 
  •  the ability to achieve identified operating and financial synergies anticipated to result from an acquisition;
 
  •  problems that could arise from the integration of the acquired business; and
 
  •  unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the acquisition.
      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 have been unable to profitably operate National King Coal, LLC and Gallup Transportation and Transloading Company, LLC, Colorado mining and trucking companies, respectively, that we acquired in connection with our acquisition of US AMCI. In September 2004, we recorded an impairment charge of $5.1 million to reduce the carrying value of the assets of these companies to their estimated fair value. 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. In addition, future acquisitions could result in our assuming more

50


 

long-term liabilities relative to the value of the acquired assets than we have assumed in our previous acquisitions.
The inability of the sellers of our Predecessor and acquired companies to fulfill their indemnification obligations to us under our acquisition agreements could increase our liabilities and adversely affect our results of operations and financial position.
      In the acquisition agreements we entered into with the sellers of our Predecessor and acquired companies, 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 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.”
The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues and profitability.
      Our largest customer during 2004 accounted for approximately 8% of our total revenues. We derived approximately 39% of our 2004 total revenues from sales to our ten largest customers. These customers may not continue to purchase coal from us under our current coal supply agreements, or at all. If these customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our revenues and profitability could suffer materially.
Changes in purchasing patterns in the coal industry may make it difficult for us to extend existing supply contracts or enter into new long-term supply contracts with customers, which could adversely affect the capability and profitability of our operations.
      We sell a significant portion of our coal under long-term coal supply agreements, which are contracts with a term greater than 12 months. The execution of a satisfactory long-term coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract. We believe that approximately 73% of our 2004 sales volume was sold under long-term coal supply agreements. At February 1, 2005, our long-term coal supply agreements had remaining terms of up to twelve 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. In addition, at February 1, 2005, 3% of our planned 2005 production, 49% of our planned 2006 production and 76% of our planned 2007 production 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 these contracts, see “Business — Marketing, Sales and Customer Contracts.”

51


 

      As electric utilities continue to adjust to frequently changing regulations, including the Acid Rain regulations of the Clean Air Act, the proposed Utility Mercury Reductions Rule, the proposed 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.
Certain provisions in our long-term supply contracts may reduce the protection these contracts provide us during adverse economic conditions or may result in economic penalties upon our failure to meet specifications.
      Price adjustment, “price reopener” and other similar provisions in long-term supply contracts may reduce the protection from short-term coal price volatility traditionally provided by these contracts. Price reopener provisions are particularly common in international metallurgical coal sales contracts. Some of our coal supply contracts contain provisions that allow for the price to be renegotiated at periodic intervals. Price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to agree on a new price, sometimes between a pre-set “floor” and “ceiling.” In some circumstances, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Any adjustment or renegotiation leading to a significantly lower contract price could result in decreased revenues. Accordingly, supply contracts with terms of one year or more may provide only limited protection during adverse market conditions.
      Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of our agreements where the customer bears transportation costs permit the customer to terminate the contract if the transportation costs borne by them increase substantially. In addition, some of these contracts allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that increase the price of coal beyond specified limits.
      Due to the risks mentioned above with respect to long-term supply contracts, we may not achieve the revenue or profit we expect to achieve from these sales commitments.
Disruption in supplies of coal produced by contractors and other third parties could temporarily impair our ability to fill customers’ orders or increase our costs.
      In addition to marketing coal that is produced by our subsidiaries’ employees, we utilize contractors to operate some of our mines. Operational difficulties at contractor-operated mines, changes in demand for contract miners from other coal producers, and other factors beyond our control could affect the availability, pricing, and quality of coal produced for us by contractors. 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 7.3 million tons of coal purchased from third parties during 2004, representing 28% of our total sales during 2004. We believe that approximately 81% of our purchased coal sales in 2004 was blended with coal produced from our mines prior to resale, and approximately 3% of our total sales in 2004 consisted of coal purchased from third parties that we processed before resale. The availability of specified qualities of this

52


 

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.
Competition within the coal industry may adversely affect our ability to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.
      We compete with numerous other coal producers in various regions of the United States for domestic and international sales. During the mid-1970s and early 1980s, increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in additional production capacity throughout the industry, all of which led to increased competition and lower coal prices. Recent increases in coal prices could encourage the development of expanded capacity by new or existing coal producers. Any resulting overcapacity could reduce coal prices and therefore reduce our revenues.
      Coal with lower production costs shipped east from western coal mines and from offshore sources has resulted in increased competition for coal sales in the Appalachian region. In addition, coal companies with larger mines that utilize the long-wall mining method typically have lower mine operating costs than we do and may be able to compete more effectively on price, particularly if the current favorable market weakens. This competition could result in a decrease in our market share in this region and a decrease in our revenues.
      Demand for our low sulfur coal and the prices that we can obtain for it are also affected by, among other things, the price of emissions allowances. Decreases in the prices of these emissions allowances could make low sulfur coal less attractive to our customers. In addition, more widespread installation by electric utilities of technology that reduces sulfur emissions (which could be accelerated by increases in the prices of emissions allowances), may make high sulfur coal more competitive with our low sulfur coal. This competition could adversely affect our business and results of operations.
      We also compete in international markets against coal produced in other countries. Measured by tons sold, exports accounted for approximately 32% of our sales in 2004. The demand for U.S. coal exports is dependent upon a number of factors outside of our control, including the overall demand for electricity in foreign markets, currency exchange rates, the demand for foreign-produced steel both in foreign markets and in the U.S. market (which is dependent in part on tariff rates on steel), general economic conditions in foreign countries, technological developments, and environmental and other governmental regulations. For example, if the value of the U.S. dollar were to rise against other currencies in the future, our coal would become relatively more expensive and less competitive in international markets, which could reduce our foreign sales and negatively impact our revenues and net income. In addition, if the amount of coal exported from the United States were to decline, this decline could cause competition among coal producers in the United States to intensify, potentially resulting in additional downward pressure on domestic coal prices.
Fluctuations in transportation costs and the availability or reliability of transportation could affect the demand for our coal or temporarily impair our ability to supply coal to our customers.
      Transportation costs represent a significant portion of the total cost of coal for our customers. Increases in transportation costs 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

53


 

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. 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 2004, 79% of our produced and processed coal volume was transported from the preparation plant to the customer by rail. In the third and fourth quarters of 2004, we 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.
We face numerous uncertainties in estimating our recoverable coal reserves, and inaccuracies in our estimates could result in decreased profitability from lower than expected revenues or higher than expected costs.
      Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our estimates of reserve information on engineering, economic and geological data assembled and analyzed by our internal engineers and which is periodically reviewed by third party consultants. There are numerous uncertainties inherent in estimating the quantities and qualities of, and costs to mine, recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:
  •  future coal prices, operating costs, capital expenditures, severance and excise taxes, royalties and development and reclamation costs;
 
  •  future mining technology improvements;
 
  •  the effects of regulation by governmental agencies; and
 
  •  geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experiences in areas we currently mine.
      As a result, actual coal tonnage recovered from identified reserve areas or properties, and costs associated with our mining operations, may vary from estimates. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

54


 

Mining in Central and Northern Appalachia is more complex and involves more regulatory constraints than mining in other areas of the United States, which could affect the mining operations and cost structures of these areas.
      The geological characteristics of Central and Northern Appalachian coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. In addition, as compared to mines in other regions, permitting, licensing and other environmental and regulatory requirements are more costly and time-consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to use coal produced by, our mines in Central and Northern Appalachia.
Our work force could become increasingly unionized in the future, which could adversely affect the stability of our production and reduce our profitability.
      Approximately 95% of our 2004 coal production came from mines operated by union-free employees. As of February 1, 2005, over 91% of our subsidiaries’ approximately 2600 employees are union-free. However, our subsidiaries’ employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. Any further unionization of our subsidiaries’ employees, or the employees of third-party contractors who mine coal for us, could adversely affect the stability of our production and reduce our profitability.
Our unionized work force could strike in the future, which could disrupt production and shipments of our coal and increase costs.
      Two negotiated wage agreements between one of our subsidiaries and the United Mine Workers of America (“UMWA”) have expired, covering an aggregate of 200 employees as of December 31, 2004, and successor agreements are currently being renegotiated for these affected employees. Two of our other subsidiaries have negotiated wage agreements with the UMWA covering an aggregate of 30 employees as of December 31, 2004 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 collect payments from our customers could be impaired if their creditworthiness deteriorates.
      Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. During 2004, we had $152,000 of bad debt expense. Our customer base is changing with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear on payment default. These new power plant owners may have credit ratings that are below investment grade. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default.
      We have contracts to supply coal to energy trading and brokering companies under which those companies sell coal to end users. If the creditworthiness of the energy trading and brokering companies declines, this would increase the risk that we may not be able to collect payment for all coal sold and delivered to or on behalf of these energy trading and brokering companies.
The government extensively regulates our mining operations, which imposes significant costs on us, and future regulations could increase those costs or limit our ability to produce and sell coal.
      The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to matters such as:
  •  employee health and safety;
 
  •  mandated benefits for retired coal miners;

55


 

  •  mine permitting and licensing requirements;
 
  •  reclamation and restoration of mining properties after mining is completed;
 
  •  air quality standards;
 
  •  water pollution;
 
  •  plant and wildlife protection;
 
  •  the discharge of materials into the environment;
 
  •  surface subsidence from underground mining; and
 
  •  the effects of mining on groundwater quality and availability.
      The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Failure to comply with these regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we are pursued for these sanctions, costs and liabilities, our mining operations and, as a result, our profitability could be adversely affected.
      The possibility exists that new legislation and/or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. 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.
Extensive environmental regulations affect our customers and could reduce the demand for coal as a fuel source and cause our sales to decline.
      The Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. Such regulations will require significant emissions control expenditures for many coal-fired power plants to comply with applicable ambient air quality standards. As a result, these generators may switch to other fuels that generate less of these emissions, 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 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. 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

56


 

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.
      There have been several proposals in Congress, including the Clear Skies Initiative, 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.
      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 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 6% of our 2004 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.
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.
      Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Our Predecessor and acquired companies also utilized certain hazardous materials and generated similar wastes. We may be subject to claims under federal and state statutes and/or common law doctrines for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of current or former conditions at sites that we own or operate currently, as well as at sites that we or our Predecessor and acquired companies owned or operated in the past, and at contaminated sites that have always been owned or operated by third parties. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share. We have not been subject to claims arising out of contamination at our facilities, 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

57


 

extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.
      These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect us.
We may be unable to obtain and renew permits necessary for our operations, which would reduce our production, cash flow and profitability.
      Mining companies must obtain numerous permits that impose strict regulations on various environmental and safety matters in connection with coal mining. These include permits issued by various federal and state agencies and regulatory bodies. The permitting rules are complex and may change over time, making our ability to comply with the applicable requirements more difficult or even impossible, thereby precluding continuing or future mining operations. Private individuals and the public have certain rights to comment upon 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 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. The plaintiffs sought to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators from additional use of existing nationwide permit approvals until they obtain more detailed “individual” permits. On July 8, 2004, the court issued an order enjoining the further issuance of Nationwide 21 permits within the Southern District of West Virginia. Although we had no operations that were immediately impacted or interrupted, this decision may require 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 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 effect our Kentucky operations.
We may not be able to implement required public-company internal controls over financial reporting in the required time frame or with adequate compliance, and implementation of the controls will increase our costs.
      Our current operations consist primarily of the assets of our Predecessor and the other operations we have acquired, each of which had different historical operating, financial, accounting and other systems. Due to our rapid growth and limited history operating our acquired operations as an integrated business, our internal control over financial reporting does not currently meet all the standards contemplated by Section 404 of the Sarbanes-Oxley Act that we will eventually be required to meet. Areas of deficiency in our internal control over financial reporting requiring improvement include: documentation of controls and procedures; segregation of duties; timely reconciliation of accounts; methods of accounting for fixed assets; the structure of our general ledger; security systems and testing of our disaster recovery plan for our information technology systems; and the level of experience in public company accounting and periodic reporting matters among our financial and

58


 

accounting staff. If we are not able to implement the requirements of Section 404 in a timely manner or with adequate compliance, our independent auditors may not be able to certify 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 report a material weakness in our internal controls. We will incur incremental costs in order to comply with Section 404, including increased auditing and legal fees and costs associated with hiring additional accounting and administrative staff with experience managing public companies.
Our ability to operate our company effectively could be impaired if we fail to attract and retain key personnel.
      Our ability to operate our business and implement our strategies depends, in part, on the efforts of our executive officers and other key employees. In addition, our future success will depend on, among other factors, our ability to attract and retain other qualified personnel. The 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.
      We have entered into employment agreements with two of our executive officers — Michael J. Quillen, our Chief Executive Officer, and D. Scott Kroh, one of our Executive Vice Presidents. Each of our other executive officers are employed on an at-will basis. Unless extended, our employment agreements with Messrs. Quillen and Kroh terminate on March 11, 2006. When the terms of these agreements expire, we may not be able to renew or extend these employment agreements on terms acceptable to us.
Our significant indebtedness could harm our business by limiting our available cash and our access to additional capital and could force us to sell material assets or take other actions to attempt to reduce our indebtedness.
      We are a highly leveraged company. Our financial performance could be affected by our significant indebtedness. At December 31, 2004, we had approximately $201.7 million of indebtedness outstanding, representing 81% of our total capitalization. This indebtedness consisted of $175.0 million principal of our 10% senior notes due 2012, $8.0 million of borrowings under our revolving credit facility that will mature in May 2009 and $18.7 million of other indebtedness, including $2.0 million of capital lease obligations extending through March 2009, $1.5 million principal amount in variable rate term notes maturing in April 2006 that we incurred in connection with equipment financing and $15.2 million payable to an insurance premium finance company. In addition, under our credit facility we had $53.0 million of letters of credit outstanding and additional borrowings available under the revolving portion of our credit facility of $114.0 million. We may also incur additional indebtedness in the future.
      This level of indebtedness could have important consequences to our business. For example, it could:
  •  increase our vulnerability to general adverse economic and industry conditions;
 
  •  make it more difficult to self-insure and obtain surety bonds or letters of credit;
 
  •  limit our ability to enter into new long-term sales contracts;
 
  •  make it more difficult for us to pay interest and satisfy our debt obligations;
 
  •  require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions and other general corporate activities;
 
  •  limit our ability to obtain additional financing to fund future working capital, capital expenditures, research and development, debt service requirements or other general corporate requirements;
 
  •  limit our flexibility in planning for, or reacting to, changes in our business and in the coal industry;

59


 

  •  place us at a competitive disadvantage compared to less leveraged competitors; and
 
  •  limit our ability to borrow additional funds.
      If our cash flows and capital resources are insufficient to fund our debt service obligations or our requirements under our other long term liabilities, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations 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 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 credit facility.
Despite our current leverage, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our significant indebtedness.
      We may be able to incur substantial additional indebtedness in the future. The terms of our credit facility and the indenture governing our senior notes do not prohibit us from doing so. Our credit facility provides for a revolving line of credit of up to $125.0 million, of which $114.0 million was available as of December 31, 2004. If new debt is added to our current debt levels, the related risks that we now face could increase. For example, the spread over the variable interest rate applicable to loans under our credit facility is dependent on our leverage ratio, and it would increase if our leverage ratio increases. Additional drawings under our revolving line of credit could also limit the amount available for letters of credit in support of our bonding obligations, which we will require as we develop and acquire new mines.
The covenants in our credit facility and the indenture governing our senior notes impose restrictions that may limit our operating and financial flexibility.
      Our credit facility, as amended and the indenture governing our senior notes contain a number of significant restrictions and covenants that limit our ability and our subsidiaries’ ability to, among other things, incur additional indebtedness or enter into sale and leaseback transactions, pay dividends, make redemptions and repurchases of certain capital stock, make loans and investments, create liens, engage in transactions with affiliates and merge or consolidate with other companies or sell substantially all of our assets.
      These covenants could adversely affect our ability to finance our future operations or capital needs or to execute preferred business strategies. In addition, if we violate these covenants and are unable to obtain waivers from our lenders, our debt under these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able repay our debt or borrow sufficient funds to refinance it. Even if we were able to obtain new financing, it may not be on commercially reasonable terms, on terms that are acceptable to us, or at all. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected.
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal.
      Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations. These bonds are typically renewable annually. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral or other less favorable terms upon those renewals. The ability of surety bond issuers and holders to demand additional collateral or other less favorable terms has increased as the number of companies willing to issue these bonds has decreased over time. Our failure to maintain, or our inability to acquire, surety bonds that are required by state and federal

60


 

law would affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal. That failure could result from a variety of factors including, without limitation:
  •  lack of availability, higher expense or unfavorable market terms of new bonds;
 
  •  restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our credit facility or the indenture governing our senior notes; and
 
  •  the exercise by third-party surety bond issuers of their right to refuse to renew the surety.
Failure to maintain capacity for required letters of credit could limit our available borrowing capacity under our credit facility, limit our ability to obtain or renew surety bonds and negatively impact our ability to obtain additional financing to fund future working capital, capital expenditure or other general corporate requirements.
      At December 31, 2004, we had $53.0 million of letters of credit in place, of which $50.0 million serve as collateral for reclamation surety bonds and $3.0 million secure miscellaneous obligations. Our credit facility provides for commitments of up to $175.0 million, consisting of a funded letter of credit facility of up to $50.0 million and a $125.0 million revolving credit facility, of which $50.0 million can be used to issue additional letters of credit. As of December 31, 2004, our entire $50.0 million funded letter of credit facility has been committed and we have an additional $3.0 million of letters of credit outstanding under the revolving credit facility. Obligations secured by letters of credit may increase in the future. Any such increase would limit our available borrowing capacity under the revolving credit facility and could negatively impact our ability to obtain additional financing to fund future working capital, capital expenditure or other general corporate requirements. Moreover, if we do not maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our mining operations.
If our assumptions regarding our likely future expenses related to benefits for non-active employees are incorrect, then expenditures for these benefits could be materially higher than we have predicted.
      At the times that we acquired the assets of our Predecessor and acquired companies, the Predecessor and acquired operations were subject to long-term liabilities under a variety of benefit plans and other arrangements with active and inactive employees. We assumed a portion of these long-term obligations. The current and non-current accrued portions of these long-term obligations, as reflected in our combined financial statements as of December 31, 2004, included $15.6 million of postretirement obligations and $6.3 million of self-insured workers’ compensation obligations, and our accumulated postretirement benefit obligation at December 31, 2004 is $43.8 million. These obligations have been estimated based on assumptions that are described in the notes to our combined 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.

61


 

A shortage of skilled labor in the Appalachian region could pose a risk to achieving improved labor productivity and competitive costs and could adversely affect our profitability.
      Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least a year of experience and proficiency in multiple mining tasks. In recent years, a shortage of trained coal miners in the Appalachian region has caused us to operate certain units without full staff, which decreases our productivity and increases our costs. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our profitability.
Our Sponsors have significant influence on our company and may have conflicts of interest with us or you in the future.
      The First Reserve Stockholders and persons affiliated with AMCI beneficially own approximately 41% of our common stock. We refer to First Reserve and to AMCI and its affiliates, collectively, as our “Sponsors.” Our Sponsors 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, our Sponsors hold a combined 25.8% ownership interest in Foundation Coal Holdings, Inc. as of January 10, 2005. These other investments may create competing financial demands on our Sponsors, potential conflicts of interest and require efforts consistent with applicable law to keep the other businesses separate from our operations. Our Sponsors 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 our Sponsors may compete with us. Their designees 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 our Sponsors 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, our Sponsors could cause us to make acquisitions that increase our amount of indebtedness or sell revenue-generating assets.
Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations.
      Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition, and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may materially adversely affect our operations and those of our customers. As a result, there could be delays or losses in transportation and 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.
Provisions in our certificate of incorporation and bylaws may discourage a takeover attempt even if doing so might be beneficial to our stockholders.
      Provisions contained in our certificate of incorporation and bylaws could impose impediments to the ability of a third party to acquire us even if a change of control would be beneficial to our existing stockholders. Provisions of our certificate of incorporation and bylaws impose various procedural and other requirements, which could make it more difficult for stockholders to effect certain corporate actions. For example, our certificate of incorporation authorizes our board of directors to determine the rights, preferences, privileges and restrictions of unissued series of preferred stock, without any vote or action by our stockholders. Thus, our

62


 

board of directors can authorize and issue shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of our common stock. These rights may have the effect of delaying or deterring a change of control of our company, and could limit the price that certain investors might be willing to pay in the future for shares of our common stock.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
      In addition to risks inherent in operations, we are exposed to market risks. The following discussion provides additional detail regarding our exposure to the risks of changing coal prices, interest rates and customer credit.
      We are exposed to market price risk in the normal course of selling coal. As of February 1, 2005, approximately 3% and 49% of our estimated 2005 and 2006 tonnage, respectively, was uncommitted. We have increased the proportion of our planned future production in 2005 and 2006 for which we have contracts to sell coal, which has the effect of lessening our market price risk.
      All of our borrowings under the revolving credit facility are at a variable rate, so we are exposed to rising interest rates in the United States. A one percentage point increase in interest rates would result in an annualized increase to interest expense of less than $0.1 million based on our variable rate borrowings as of December 31, 2004.
      Our concentration of credit risk is substantially with electric utilities, producers of steel and foreign customers. Our policy is to independently evaluate a customer’s creditworthiness prior to entering into transactions and to periodically monitor the credit extended.

63


 

Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
Alpha Natural Resources, Inc.:
      We have audited the accompanying combined balance sheets of ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. and subsidiaries (the Company or Successor) as of December 31, 2004 and 2003, and the related combined statements of operations, stockholder’s equity and partners’ capital, and cash flows for the years ended December 31, 2004 and 2003, and the period from December 14, 2002 to December 31, 2002 (Successor Periods), and the combined statements of operations, shareholder’s equity, and cash flows for the period from January 1, 2002 to December 13, 2002 (Predecessor Period). These combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these combined financial statements based on our audits.
      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis of our opinion.
      In our opinion, the aforementioned Successor combined financial statements present fairly, in all material respects, the financial position of ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for the Successor Periods, in conformity with U.S. generally accepted accounting principles. Further, in our opinion, the aforementioned Predecessor combined financial statements present fairly, in all material respects, the results of their operations and their cash flows for the Predecessor Period, in conformity with U.S. generally accepted accounting principles.
      As discussed in note 1 to the combined financial statements, effective December 13, 2002, the Company acquired the majority of the Virginia coal operations of Pittston Coal Company, a subsidiary of The Brink’s Company (formerly known as The Pittston Company), in a business combination accounted for as a purchase. As a result of the acquisition, the combined financial information for the periods after the acquisition is presented on a different cost basis than that for the periods before the acquisition and, therefore, is not comparable.
/s/ KPMG LLP
Roanoke, Virginia
March 30, 2005

64


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
COMBINED BALANCE SHEETS
                             
    Pro Forma   December 31,
    December 31,    
    2004   2004   2003
             
    (Unaudited)        
    (In thousands)
ASSETS
Current assets:
                       
 
Cash and cash equivalents
  $ 7,391     $ 7,391     $ 11,246  
 
Trade accounts receivable, net
    95,828       95,828       70,205  
 
Notes and other receivables
    10,835       10,835       4,742  
 
Inventories
    54,569       54,569       33,113  
 
Due from affiliate
    323       323       3,770  
 
Deferred income taxes
          4,674       489  
 
Prepaid expenses and other current assets
    28,915       28,915       19,256  
                   
   
Total current assets
    197,861       202,535       142,821  
Property, plant, and equipment, net
    217,964       217,964       198,147  
Goodwill
    18,641       18,641       17,121  
Other intangibles, net
    1,155       1,155       2,896  
Other assets
    36,826       36,826       18,351  
                   
   
Total assets
  $ 472,447     $ 477,121     $ 379,336  
                   
 
LIABILITIES AND STOCKHOLDER’S EQUITY (DEFICIT) AND PARTNERS’ CAPITAL
Current liabilities:
                       
 
Current portion of long-term debt
  $ 1,693     $ 1,693     $ 13,329  
 
Note payable
    15,228       15,228       14,425  
 
Notes payable to affiliates
    517,692              
 
Bank overdraft
    10,024       10,024       5,854  
 
Trade accounts payable
    51,050       51,050       41,357  
 
Accrued expenses and other current liabilities
    68,283       68,283       35,142  
                   
   
Total current liabilities
    663,970       146,278       110,107  
Long-term debt, net of current portion
    184,784       184,784       57,210  
Workers’ compensation benefits
    4,678       4,678       1,660  
Postretirement medical benefits
    15,637       15,637       10,662  
Asset retirement obligation
    32,888       32,888       32,607  
Deferred gains on sale of property interests
    5,516       5,516       6,934  
Deferred income taxes
          7,718       823  
Other liabilities
    15,411       4,911       6,486  
                   
   
Total liabilities
    922,884       402,410       226,489  
                   
Minority interest
          28,778       66,480  
                   
Stockholder’s equity (deficit) and partners’ capital:
                       
Alpha Natural Resources, Inc.:
                       
 
Preferred stock — par value $0.01, 10,000,000 shares authorized, none issued
                 
 
Common stock — par value $0.01, 100,000,000 shares authorized, 28,287,580 shares issued and outstanding
    283              
 
Deficit capital
    (450,720 )            
 
Retained earnings
                 
                   
   
Total Alpha Natural Resources, Inc. stockholders’ (deficit)
    (450,437 )            
Alpha NR Holding, Inc.:
                       
 
Preferred stock — par value $0.01, 1,000 shares authorized, none issued
                 
 
Common stock — par value $0.01, 1,000 shares authorized, 100 shares issued and outstanding
                 
 
Additional paid-in capital
          22,153       75,710  
 
Retained earnings
          18,828       1,442  
                   
   
Total Alpha NR Holding, Inc. stockholder’s equity
          40,981       77,152  
Alpha Fund IX Holdings, L.P.:
                       
 
Partners’ capital
          4,952       9,215  
                   
   
Total stockholder’s equity (deficit) and partners’ capital
    (450,437 )     45,933       86,367  
                   
   
Total liabilities and stockholder’s equity (deficit) and partners’ capital
  $ 472,447     $ 477,121     $ 379,336  
                   
See accompanying notes to combined financial statements.

65


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
COMBINED STATEMENTS OF OPERATIONS
                                       
    Company     Predecessor
           
        Period from     Period from
        December 14,     January 1,
    Year Ended December 31,   2002 to     2002 to
        December 31,     December 13,
    2004   2003   2002     2002
                   
    (In thousands)
Revenues:
                                 
 
Coal revenues
  $ 1,089,992     $ 701,262     $ 6,260       $ 154,715  
 
Freight and handling revenues
    146,166       73,800       1,009         17,001  
 
Other revenues
    33,560       17,504       101         6,031  
                           
   
Total revenues
    1,269,718       792,566       7,370         177,747  
                           
Costs and expenses:
                                 
 
Cost of coal sales (exclusive of items shown separately below)
    931,585       632,979       6,268         158,924  
 
Freight and handling costs
    146,166       73,800       1,009         17,001  
 
Cost of other revenues
    25,064       16,750       120         7,973  
 
Depreciation, depletion and amortization
    56,012       36,054       274         6,814  
 
Asset impairment charge
    5,100                      
 
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)
    43,881       21,949       471         8,797  
 
Costs to exit business
                        25,274  
                           
   
Total costs and expenses
    1,207,808       781,532       8,142         224,783  
                           
Refund of federal black lung excise tax
                        2,049  
Gain on sale of fixed assets, net
    671                      
Other operating income, net
                        1,430  
                           
   
Income (loss) from operations
    62,581       11,034       (772 )       (43,557 )
                           
Other income (expense):
                                 
 
Interest expense
    (20,041 )     (7,848 )     (203 )       (35 )
 
Interest income
    531       103       6         2,072  
 
Miscellaneous income
    734       575                
                           
   
Total other income (expense), net
    (18,776 )     (7,170 )     (197 )       2,037  
                           
   
Income (loss) before income taxes and minority interest
    43,805       3,864       (969 )       (41,520 )
Income tax expense (benefit)
    3,960       668       (334 )       (17,198 )
                           
   
Income (loss) before minority interest
    39,845       3,196       (635 )       (24,322 )
Minority interest
    19,830       934                
                           
   
Net income (loss)
  $ 20,015     $ 2,262     $ (635 )     $ (24,322 )
                           
See accompanying notes to combined financial statements.

66


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
COMBINED STATEMENTS OF STOCKHOLDER’S EQUITY AND PARTNERS’ CAPITAL
                                                   
        Retained       Net   Deferred    
        Earnings       Receivables   Taxes    
    Capital   (Accumulated   Company   from   Receivable    
Predecessor   Contributions   Deficit)   Equity   Affiliates   from Parent   Total
                         
    (In thousands)
Balances, December 31, 2001
  $     $     $ 211,313     $ (279,374 )   $ (68,532 )   $ (136,593 )
 
Net loss
                (24,322 )                 (24,322 )
 
Capital contribution
                329,964       (329,964 )            
 
Affiliate transactions, net
                      35,937             35,937  
 
Deferred taxes receivable from parent
                            (8,023 )     (8,023 )
 
Other
                            4       4  
                                     
Balances, December 13, 2002
  $     $     $ 516,955     $ (573,401 )   $ (76,551 )   $ (132,997 )
                                     
 
                                                   
                Total       Total
            Retained   Alpha NR       Stockholder’s
        Additional   Earnings   Holding, Inc.       Equity and
    Common   Paid-In   (Accumulated   Stockholder’s   Partners’   Partners’
Company   Stock   Capital   Deficit)   Equity   Capital   Capital
                         
Balances, December 14, 2002
  $     $     $     $     $     $  
 
Net loss
                (529 )     (529 )     (106 )     (635 )
 
Contributed capital
                            2,635       2,635  
 
Issuance of common stock
          21,384             21,384             21,384  
                                     
Balances, December 31, 2002
          21,384       (529 )     20,855       2,529       23,384  
 
Net income
                1,971       1,971       291       2,262  
 
Contributed capital
          15,153             15,153       1,868       17,021  
 
Notes payable to affiliate contributed to capital
          39,173             39,173       4,827       44,000  
 
Noncash distribution of Virginia Tax Credit
                            (300 )     (300 )
                                     
Balances, December 31, 2003
          75,710       1,442       77,152       9,215       86,367  
 
Net income
                17,386       17,386       2,629       20,015  
 
Noncash distribution of Virginia Tax Credit
                            (292 )     (292 )
 
Distributions
          (53,557 )           (53,557 )     (6,600 )     (60,157 )
                                     
Balances, December 31, 2004
  $     $ 22,153     $ 18,828     $ 40,981     $ 4,952     $ 45,933  
                                     
See accompanying notes to combined financial statements.

67


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
COMBINED STATEMENTS OF CASH FLOWS
                                         
    Company   Predecessor
         
        Period from   Period from
        December 14,   January 1,
    Year Ended December 31,   2002 to   2002 to
        December 31,   December 13,
    2004   2003   2002   2002
                 
    (In thousands)
Operating activities:
                               
 
Net income (loss)
  $ 20,015     $ 2,262     $ (635 )   $ (24,322 )
 
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
                               
   
Depreciation, depletion and amortization
    56,012       36,054       274       6,814  
   
Amortization and write-off of debt issuance costs
    4,474       1,276       59        
   
Minority interest
    19,830       934              
   
Accretion of asset retirement obligation
    3,301       2,699       57        
   
Virginia tax credit
    (4,872 )     (4,313 )            
   
Stock-based compensation
    91                    
   
Bad debt provision
    152       68       5       1,296  
   
Net pension credit
                      (928 )
   
Loss on settlement of asset retirement obligation
    762                    
   
Asset impairment charge
    5,100                    
   
Provision for non-recoupable advance mining royalties
    758                    
   
Amortization of deferred gains on sales
                               
     
of property interests
    (959 )     (618 )            
   
Gain on sale of fixed assets, net
    (671 )                  
   
Deferred income taxes
    2,711       668       (334 )     (8,023 )
   
Other, net
                      11  
   
Changes in operating assets and liabilities:
                               
     
Trade accounts receivable
    (25,775 )     (21,056 )     (7,472 )     5,244  
     
Notes and other receivables
    (1,062 )     (2,358 )            
     
Inventories
    (21,040 )     13,014       549        
     
Prepaid expenses and other current assets
    5,568       793       (138 )     (5,418 )
     
Other assets
    805       (3,051 )           (1,850 )
     
Trade accounts payable
    9,742       12,234       4,057       (3,925 )
     
Accrued expenses and other current liabilities
    27,243       16,392       4,706       (15,115 )
     
Workers’ compensation benefits
    3,018       1,660             1,879  
     
Postretirement medical benefits
    4,975       1,236       36       6,710  
     
Asset retirement obligation expenditures
    (3,306 )     (2,252 )           (1,270 )
     
Other liabilities
    (96 )     (1,538 )     (1,459 )     25,081  
                         
       
Net cash provided by (used in) operating activities
  $ 106,776     $ 54,104     $ (295 )   $ (13,816 )
                         

68


 

                                     
    Company   Predecessor
         
        Period from   Period from
        December 14,   January 1,
    Year Ended December 31,   2002 to   2002 to
        December 31,   December 13,
    2004   2003   2002   2002
                 
    (In thousands)
Investing activities:
                               
 
Capital expenditures
  $ (72,046 )     (27,719 )     (960 )     (21,866 )
 
Proceeds from disposition of property, plant, and equipment
    1,096       65,174             76  
 
Purchase of net assets of acquired companies
    (2,891 )     (133,757 )     (37,202 )      
 
Purchase of equity investment
    (4,500 )                  
 
Issuance of note receivable to coal supplier, net of collections of $1,519
    (8,481 )                  
 
Deferred acquisition costs
                (731 )      
 
Decrease (increase) in due from affiliate
    620       (3,770 )            
 
Other, net
                      (264 )
                         
   
Net cash used in investing activities
    (86,202 )     (100,072 )     (38,893 )     (22,054 )
                         
Financing activities:
                               
 
Repayments of notes payable
    (14,425 )     (15,600 )            
 
Proceeds from issuance of long-term debt
    175,000       58,518              
 
Repayments on long-term debt
    (61,422 )     (30,054 )            
 
Increase in bank overdraft
    4,170       5,854              
 
Debt issuance costs
    (10,525 )     (5,181 )     (340 )      
 
Deferred common stock offering costs
    (1,655 )                  
 
Advances from affiliates
          20,047       23,953       35,783  
 
Capital contributions
          3,118       2,635        
 
Issuance of common stock
          15,153       21,384        
 
Distributions to owners
    (60,156 )                  
 
Distributions to minority interest
    (55,416 )     (3,085 )            
                         
   
Net cash provided by (used in) financing activities
    (24,429 )     48,770       47,632       35,783  
                         
   
Net increase (decrease) in cash and cash equivalents
    (3,855 )     2,802       8,444       (87 )
Cash and cash equivalents at beginning of period
    11,246       8,444             175  
                         
Cash and cash equivalents at end of period
  $ 7,391     $ 11,246     $ 8,444     $ 88  
                         
See accompanying notes to combined financial statements.

69


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(In thousands, except percentages and share data)
(1) Business and Basis of Presentation
Organization and Business
      ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc., formerly named Alpha Natural Resources, Inc., (together, the FR Affiliates) are entities under the common control of First Reserve GP IX, Inc. and were formed in 2002 to acquire coal mining assets in the Appalachian region of the United States. In December 2002, ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. formed ANR Holdings, LLC (ANR Holdings) and acquired membership interests of approximately 11% and 89%, respectively. ANR Holdings is the parent of Alpha Natural Resources, LLC (Alpha) and the latter entity and its subsidiaries acquired our Predecessor, the majority of the Virginia coal operations of Pittston Coal Company, a subsidiary of The Brink’s Company (formerly known as The Pittston Company), on December 13, 2002 (described in note 20).
      The acquisition of Coastal Coal Company (described in note 20) was completed on January 31, 2003 by subsidiaries of ANR Holdings. The acquisition of U.S. AMCI (described in note 20) was completed on March 11, 2003. Concurrent with the acquisition of U.S. AMCI, ANR Holdings issued additional membership interests in the aggregate amount of 45.3% to the former owners of U.S. AMCI, Madison Capital Funding, LLC and members of management in exchange for the net assets of U.S. AMCI and cash. After completion of this transaction, the FR Affiliates owned 54.7% of ANR Holdings.
      The acquisition of Mears Enterprises, Inc. and affiliated entities (described in note 20) was completed on November 17, 2003.
      The financial statements for the period from December 14, 2002 to December 31, 2002, and the years ended December 31, 2003 and 2004 are presented on a combined basis. The entities included in the combined financial statements, except our Predecessor, are collectively referred to as “the Company”.
      The Company and its operating subsidiaries are engaged in the business of extracting, processing and marketing coal from deep and surface mines, principally located in the Eastern and Southeastern regions of the United States, for sale to utility and steel companies in the United States and in international markets.
Operating Subsidiaries of Alpha Natural Resources, LLC:
      Companies with coal reserves and/or production facilities:
  •  Paramont Coal Company Virginia, LLC
 
  •  Dickenson-Russell Coal Company, LLC
 
  •  Alpha Terminal Company, LLC
 
  •  Alpha Land and Reserves, LLC
 
  •  AMFIRE, LLC and Subsidiaries
 
  •  McDowell-Wyoming Coal Company, LLC and Subsidiaries
      Companies providing administrative, sales and other services:
  •  Alpha Coal Sales Co., LLC
 
  •  Alpha Natural Resources Capital Corp.
 
  •  Alpha Natural Resources Services, LLC

70


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
  •  Maxxim Rebuild Co., LLC
 
  •  Maxxim Shared Services, LLC
      Holding companies:
  •  Maxxum Carbon Resources, LLC
 
  •  Esperanza Coal Co., LLC
Principles of Combination
      The accompanying combined financial statements include the accounts of the Company described above. All significant intercompany accounts and transactions have been eliminated.
Predecessor
      Prior to December 13, 2002, the Company had no operations. On December 13, 2002, the Company acquired the majority of the Virginia coal operations of Pittston Coal Company (the Combined Virginia Entity or Predecessor) through a number of asset acquisitions by the Company’s subsidiaries. The Combined Virginia Entity is considered the Predecessor to the Company. As such, the historical financial statements of the Combined Virginia Entity are included in the accompanying combined financial statements, including the combined statements of operations, cash flows, and shareholders’ equity, for the period from January 1, 2002 to December 13, 2002 (the “Predecessor combined financial statements”). The Predecessor combined financial statements are not necessarily indicative of the future financial position or results of operations of the Company.
      The Predecessor’s combined financial statements have not been adjusted to give effect to the acquisition. For this reason, the combined financial statements of the Company after the acquisition are not comparable to the Predecessor’s combined financial statements prior to the acquisition.
The Company
      The accompanying combined balance sheets as of December 31, 2004 and 2003, and the combined statements of operations, cash flows, and stockholder’s equity and partners’ capital for the years ended December 31, 2004 and 2003 and the period from December 14, 2002 to December 31, 2002, reflect the combined financial position, results of operations and cash flows of the Company from the date of acquisition of the Predecessor. See also note 20.
Subsequent Internal Restructuring and Initial Public Offering
      On February 11, 2005, the Company completed a series of transactions to transition from a structure in which the Company’s top-tier holding company was a limited liability company, ANR Holdings, to one in which the top-tier holding company is a corporation, Alpha Natural Resources, Inc., which was formed on November 29, 2004. These transactions are referred to collectively as the Internal Restructuring, and they included the following:
  •  Alpha Coal Management, LLC (ACM) was dissolved and liquidated, after which (1) the interests in ANR Holdings previously held by ACM were distributed to and held directly by the Company’s officers and employees who were owners of ACM prior to its dissolution and (2) outstanding options to purchase units in ACM were automatically converted into options to purchase up to 596,985 shares of Alpha Natural Resources, Inc. common stock at an exercise price of $12.73 per share, and Alpha

71


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
  Natural Resources, Inc. assumed the obligations of ACM under the Alpha Coal Management, LLC 2004 Long-Term Incentive Plan.
 
  •  Alpha Natural Resources, Inc. assumed the obligations of ANR Holdings to make distributions to (1) affiliates of AMCI in an aggregate amount of $6,000, representing the approximate incremental tax resulting from the recognition of additional tax liability resulting from the Internal Restructuring and (2) First Reserve Fund IX, L.P. in an aggregate amount of approximately $4,500, representing the approximate value of tax attributes conveyed as a result of the Internal Restructuring (collectively, the Sponsor Distributions). The Sponsor Distributions to affiliates of AMCI are payable in five equal installments on the dates for which estimated income tax payments are due in each of April 2005, June 2005, September 2005, January 2006 and April 2006. The Sponsor Distributions to First Reserve Fund IX, L.P. are payable in three installments of approximately $2,100, $2,100 and $300 on December 15, 2007, 2008 and 2009, respectively. The Sponsor Distributions will be payable in cash or, to the extent Alpha Natural Resources, Inc. is not permitted by the terms of the senior credit facility or the indenture governing the senior notes to pay the Sponsor Distributions in cash, in shares of Alpha Natural Resources, Inc. common stock.
 
  •  First Reserve Fund IX, L.P., the direct parent of Alpha NR Holding, Inc., contributed all of the outstanding common stock of Alpha NR Holding, Inc. to Alpha Natural Resources, Inc. in exchange for 12,462,992 shares of Alpha Natural Resources, Inc. common stock and demand promissory notes in an aggregate adjusted principal amount of $206,734.
 
  •  ANR Fund IX Holdings, L.P., Madison Capital Funding, LLC and affiliates of AMCI contributed all of their membership interests in ANR Holdings to Alpha Natural Resources, Inc. in exchange for 13,052,431 shares of Alpha Natural Resources, Inc. common stock and demand promissory notes in an aggregate adjusted principal amount of $310,958.
 
  •  The officers and employees who were the members of ACM contributed all of their interests in ANR Holdings to Alpha Natural Resources, Inc. in exchange for 2,772,157 shares of Alpha Natural Resources, Inc. common stock.
 
  •  The Board of Directors of Alpha Natural Resources, Inc. declared a pro rata distribution to the former members of ANR Holdings in an aggregate amount equal to the net proceeds Alpha Natural Resources, Inc. received upon the exercise by the underwriters of their over-allotment option with respect to the public offering described below.
 
  •  Alpha Natural Resources, Inc. recorded a change of $3,044 in net deferred income taxes (an estimated increase of $100,600 in gross deferred tax assets, less an estimated increase of $97,556 in the valuation allowance for deferred tax assets) recognized upon the completion of the Internal Restructuring.
 
  •  The Company, the FR Affiliates and affiliates of AMCI amended certain of the post-closing arrangements previously entered into as part of the Company’s acquisition of U.S. AMCI.
 
  •  Alpha Natural Resources, Inc. contributed the membership interests in ANR Holdings received in the Internal Restructuring to Alpha NR Holding, Inc. and another indirect wholly-owned subsidiary of Alpha Natural Resources, Inc.
      The accompanying unaudited pro forma balance sheet data as of December 31, 2004 gives effect to the Internal Restructuring described above as if it had occurred on December 31, 2004.
      The following unaudited pro forma statement of operations data for the years ended December 31, 2004 and 2003 give effect to the Internal Restructuring described above, the issuance of $175,000 principal amount of 10% senior notes due 2012 by our subsidiaries Alpha Natural Resources, LLC and Alpha Natural

72


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
Resources Capital Corp. and the entry by Alpha Natural Resources, LLC into a $175,000 credit facility in May 2004 (see note 12), which we refer to as the 2004 Financings, and the 2003 Acquisitions (see note 20), as if the Internal Restructuring, 2004 Financings, and 2003 Acquisitions had occurred on January 1, 2003. This pro forma data is for informational purposes only, and should not be considered indicative of results that would have been achieved had the transactions listed above actually been consummated on January 1, 2003:
                 
    Year Ended December 31,
     
    2004   2003
         
Pro forma revenues
  $ 1,269,718     $ 902,766  
Pro forma net income
    29,637       536  
      The following unaudited table reconciles reported net income to pro forma net income as if the Internal Restructuring, 2004 Financings, and 2003 Acquisitions had occurred on January 1, 2003:
                 
    Year Ended
    December 31,
     
    2004   2003
         
Reported net income
  $ 20,015     $ 2,262  
Add: Pro forma results of operations related to the 2003 Acquisitions, net of income taxes
          3,507  
Deduct: Pro forma effects of the 2004 Financings, net of income taxes
    (1,672 )     (7,728 )
Add: Elimination of minority interest, net of income tax effects of Internal Restructuring
    11,294       2,495  
             
Pro forma net income
  $ 29,637     $ 536  
             
      The following unaudited pro forma earnings per share data for the years ended December 31, 2004 and 2003 give effect to the Internal Restructuring, the 2004 Financings, and the 2003 Acquisitions as if these transactions had occurred on January 1, 2003:
                 
    Year Ended December 31,
     
    2004   2003
         
Pro forma earnings per share data:
               
Basic earnings per share
  $ 1.10     $ 0.02  
Shares outstanding — basic
    26,942,650       26,942,650  
Diluted earnings per share
  $ 1.04     $ 0.02  
Shares outstanding — diluted
    28,484,586       28,484,586  
      On February 18, 2005, Alpha Natural Resources, Inc. completed the initial public offering of 33,925,000 shares of its common stock, including 4,425,000 shares issued pursuant to the exercise in full of the underwriters’ over-allotment option. Alpha Natural Resources, Inc. received net proceeds (after deducting issuance costs) of $596,592 from the offering. Alpha Natural Resources, Inc. used $517,982 of the net proceeds to repay all outstanding principal and accrued interest on its demand promissory notes issued in the Internal Restructuring to the FR Affiliates, affiliates of AMCI and Madison Capital Funding LLC, and the remaining $78,610 of the net proceeds were distributed by Alpha Natural Resources, Inc. on a pro rata basis to its stockholders of record as of the close of business on February 11, 2005 pursuant to the distribution declared by Alpha Natural Resources, Inc.’s Board of Directors in connection with the Internal Restructuring.
      At December 31, 2004, included in other assets are deferred costs related to the initial public offering in the amount of $3,665. These deferred costs will be charged against the proceeds of the public offering.

73


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
      The following unaudited pro forma, as adjusted, earnings per share data for the years ended December 31, 2004 and 2003 give effect to the Internal Restructuring, the 2004 Financings, the 2003 Acquisitions, and our initial public offering of common stock completed on February 18, 2005 as if these transactions had occurred on January 1, 2003:
                 
    Year Ended December 31,
     
    2004   2003
         
Pro forma, as adjusted, earnings per share data:
               
Basic earnings per share
  $ 0.49     $ 0.01  
Shares outstanding — basic
    60,867,650       60,867,650  
Diluted earnings per share
  $ 0.47     $ 0.01  
Shares outstanding — diluted
    62,409,586       62,409,586  
(2) Summary of Significant Accounting Policies and Practices
     (a) Cash and Cash Equivalents
      Cash and cash equivalents consist of cash and highly liquid, short-term investments. Cash and cash equivalents are stated at cost, which approximates fair market value. For purposes of the combined statements of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.
     (b) Trade Accounts Receivable and Allowance for Doubtful Accounts
      Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company establishes provisions for losses on accounts receivable when it is probable that all or part of the outstanding balance will not be collected. The Company regularly reviews collectibility and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance-sheet credit exposure related to its customers.
      The changes in the allowance for doubtful accounts were as follows:
         
Bad debt provision
  $ 5  
       
Balance as of December 31, 2002
    5  
Bad debt provision
    68  
       
Balance as of December 31, 2003
    73  
Bad debt provision
    152  
Bad debt write-offs
    (132 )
       
Balance as of December 31, 2004
  $ 93  
       
     (c) Inventories
      Coal inventories are stated at the lower of cost or market. The cost of coal inventories is determined based on average cost of production, which includes all costs incurred to extract, transport and process the coal. Coal is classified as inventory at the point in time the coal is extracted from the mine and weighed at a loading facility.

74


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
      Material and supplies inventories are valued at average cost, less an allowance for obsolete and surplus items.
     (d) Property, Plant, and Equipment
      Costs for mineral properties, mineral rights, and mine development incurred to expand capacity of operating mines or to develop new mines are capitalized and charged to operations on the units-of-production method over the estimated proven and probable reserve tons. Mine development costs include costs incurred for site preparation and development of the mines during the development stage. Mobile mining equipment and other fixed assets are stated at cost and depreciated on a straight-line basis over estimated useful lives ranging from 2 to 20 years. Leasehold improvements are amortized, using the straight-line method, over their estimated useful lives or the term of the lease, whichever is shorter. Major repairs and betterments that significantly extend original useful lives or improve productivity are capitalized and depreciated over the period benefited. Maintenance and repairs are expensed as incurred.
     (e) Impairment of Long-Lived Assets
      In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-lived Assets, long-lived assets, such as property, plant, equipment, and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and would no longer be depreciated. The assets and liabilities of a disposal group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.
     (f) Goodwill and Other Intangible Assets
      Goodwill represents the excess of costs over fair value of net assets of businesses acquired. Pursuant to SFAS No. 142, Goodwill and Other Intangible Assets, goodwill and intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142. The Company performs its impairment test in August of each year. SFAS No. 142 also requires that intangible assets with estimable useful lives be amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with SFAS No. 144. The impairment review in August 2004 supported the carrying value of goodwill.
     (g) Health Insurance Programs
      The Company is principally self-insured for costs of health and medical claims. The Company utilizes commercial insurance to cover specific claims in excess of $250.
     (h) Income Taxes
      The Company and the Predecessor account for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial

75


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which those items are expected to reverse.
     (i) Asset Retirement Obligation
      Minimum standards for mine reclamation have been established by various regulatory agencies and dictate the reclamation requirements at the Company’s operations. The Company records these reclamation obligations under the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which the legal obligation associated with the retirement of the long-lived asset is incurred. When the liability is initially recorded, the offset is capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. To settle the liability, the obligation is paid, and to the extent there is a difference between the liability and the amount of cash paid, a gain or loss upon settlement is recorded. The Company annually reviews its estimated future cash flows for its asset retirement obligation.
      In connection with the business acquisitions described in note 20, the Company recorded the fair value of the reclamation liabilities assumed as part of the acquisitions in accordance with SFAS No. 143.
      The Predecessor charged expenditures relating to environmental regulatory requirements and reclamation costs undertaken during mine operations against earnings as incurred. Estimated site restoration and post-closure reclamation costs were charged against earnings using the units-of-production method over the expected economic life of each mine. Accrued reclamation costs were subject to review by our Predecessor’s management on a regular basis and were revised when appropriate for changes in future estimated costs and/or regulatory requirements.
     (j) Royalties
      Lease rights to coal lands are often acquired in exchange for royalty payments. Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable against future production. These advance payments are deferred and charged to operations as the coal reserves are mined. The Company regularly reviews recoverability of advance mining royalties and establishes or adjusts the allowance for advance mining royalties as necessary using the specific identification method. In instances where advance payments are not expected to be offset against future production royalties, the Company establishes a provision for losses on the advance payments that have been paid and the scheduled future minimum payments are expensed and recognized as liabilities. Advance royalty balances are charged off against the allowance when the lease rights are either terminated or expire.
      The changes in the allowance for advance mining royalties were as follows:
         
Balance as of December 31, 2003 and 2002
  $  
Provision for non-recoupable advance mining royalties
    758  
Write-offs of advance mining royalties
    (11 )
       
Balance as of December 31, 2004
  $ 747  
       
     (k) Revenue Recognition
      The Company recognizes revenue on coal sales when title passes to the customer in accordance with the terms of the sales agreement. Revenue from domestic coal sales is recorded at the time of shipment or delivery to the customer, and the customer takes ownership and assumes risk of loss based on shipping terms. Revenue

76


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
from international coal sales is recorded at the time coal is loaded onto the shipping vessel, when the customer takes ownership and assumes risk of loss. In the event that new contracts are negotiated with a customer and shipments commence before the old contract is complete, the Company recognizes as revenue the lower of the cumulative amount billed or an amount based on the weighted average price of the new and old contracts applied to the tons sold.
      Freight and handling costs paid to third-party carriers and invoiced to coal customers are recorded as freight and handling costs and freight and handling revenues, respectively.
      Other revenues generally consist of equipment and parts sales, equipment rebuild and maintenance services, coal handling and processing, trucking services for unrelated parties, royalties, commissions on coal trades, and rental income. These revenues are recognized in the period earned or when the service is completed.
     (l) Deferred Financing Costs
      In connection with obtaining financing, the Company incurred deferred financing costs totaling $10,525, $5,181, and $340 during the years ended December 31, 2004 and 2003, and the period from December 14, 2002 to December 31, 2002, respectively. These financing costs have been deferred and are included in other assets in the accompanying combined balance sheets. Also see note 12. These deferred financing costs are being amortized to interest expense over the life of the related indebtedness or credit facility. Amortization expense for the years ended December 31, 2004 and 2003, and the period from December 14, 2002 to December 31, 2002 totaled $4,474, $1,276, and $59, respectively. Due to the termination of a prior credit facility, amortization expense for the year ended December 31, 2004 includes a $2,819 write-off of deferred financing costs.
     (m) Virginia Coalfield Employment Enhancement Tax Credit
      For tax years 1996 through 2007, Virginia companies with an economic interest in coal earn tax credits based upon tons sold, seam thickness, and employment levels. The maximum credit earned equals $0.40 per ton for surface mined coal and $1.00 or $2.00 per ton for deep mined coal depending on seam thickness. Credits allowable are reduced from the maximum amounts if employment levels are not maintained from the previous year, and no credit is allowed for coal sold to Virginia utilities. Currently, the cash benefit of the credit is realized three years after being earned and either offsets taxes imposed by Virginia at 100% or is refundable by the state at 85% of the face value to the extent taxes are not owed. The Company records the present value of the portion of the credit that is refundable as a reduction of operating costs as it is earned. The Company records the portion of the credit that is allocated to Alpha NR Holding, Inc. as an other asset. The Company records the portion of the credit that is allocated to ANR Fund IX Holdings, L.P. and minority interest owners as noncash distributions.
     (n) Workers’ Compensation and Pneumoconiosis (Black Lung) Benefits
Workers’ Compensation
      The Company is self-insured for workers’ compensation claims at certain of its operations in West Virginia. Workers’ compensation at all other locations in West Virginia is insured through the West Virginia state insurance program. Workers’ compensation claims at locations in all other states where the Company operates are covered by a third-party insurance provider.
      The liabilities for workers’ compensation claims that are self-insured are estimates of the ultimate losses incurred based on the Company’s experience, and include a provision for incurred but not reported losses.

77


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
Adjustments to the probable ultimate liabilities are made annually based on an actuarial study and adjustments to the liability are recorded based on the results of this study.
Black Lung Benefits
      The Company is required by federal and state statutes to provide benefits to employees for awards related to black lung. These claims are covered by a third-party insurance provider in all locations where the Company operates with the exception of West Virginia. The Company is self-insured for state black lung related claims at certain locations in West Virginia.
      The liabilities for state black lung related claims in West Virginia that are self-insured are estimates of the ultimate losses incurred based on the Company’s experience, and include a provision for incurred but not reported losses. Estimates of the liabilities are made annually based on an actuarial study and adjustments to the liability are recorded based on the results of this study.
      The Company did not assume any responsibility for workers’ compensation or black lung claims incurred by any of its subsidiaries prior to their acquisition. Also see note 20.
     (o) Postretirement Benefits Other Than Pensions
      The Company accounts for health care and life insurance benefits provided for current and certain retired employees and their dependents by accruing the cost of such benefits over the service lives of employees. Unrecognized actuarial gains and losses are amortized over the estimated average remaining service period for active employees and over the estimated average remaining life for retirees.
     (p) Equity Investments
      The accompanying combined financial statements include the accounts of the Company and its majority owned subsidiaries. Investments in unconsolidated subsidiaries representing ownership of at least 20% but less than 50% are accounted for under the equity method. Under the equity method of accounting, the Company’s proportionate share of the investment company’s income is included in the Company’s net income or loss with a corresponding increase or decrease in the carrying value of the investment.
     (q) Equity-Based Compensation Awards
      The Company accounts for equity-based compensation awards granted to employees in accordance with Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Compensation cost for equity-based awards is recognized in an amount equal to the difference between the exercise price of the award and the fair value of the Company’s equity on the date of grant. In accordance with APB Opinion No. 25, the Company recognized compensation expense of $91 related to the period from the grant date on November 10, 2004 (see note 16(e)) to December 31, 2004 for equity-based awards that had an exercise price less than the fair value of the Company’s common shares on the grant date.

78


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
      The following table illustrates the effect on net income as if the Company had applied the fair value recognition provisions of SFAS No. 123 to equity-based employee compensation using the Black-Scholes option-pricing model for 2004:
         
    For the Year Ended
    December 31, 2004
     
Reported net income
  $ 20,015  
Add: Equity-based compensation expense included in reported net income, net of income taxes and minority interest
    50  
Deduct: Total equity-based compensation expense determined under fair-value based method, net of income taxes and minority interest
    (72 )
       
Pro forma net income
  $ 19,993  
       
      The Company had not granted equity-based awards prior to November 2004. The fair value of equity-based awards granted in November 2004 was estimated on the date of the grant using the Black-Scholes option pricing model with the following assumptions:
         
Expected life (years)
    4.0  
Expected volatility
    38.0 %
Risk-free interest rate
    3.38 %
Expected annual dividend
  $ 0.10  
      As described in note 16(e), the options granted in November 2004 to purchase units of ACM were automatically converted into options to purchase 596,985 shares of Alpha Natural Resources, Inc. common stock in connection with the Internal Restructuring on February 11, 2005. The weighted-average fair value of options granted in 2004 was $9.04 on an as converted basis.
      The effects on pro forma net income of expensing the estimated fair value of equity-based awards are not necessarily representative of the effects on reported net income for future periods due to such factors as the vesting periods of stock options and the potential issuance of additional awards in future years.
     (r) New Accounting Pronouncements
      In November 2004, the Financial Accounting Standards Board (the FASB) issued SFAS No. 151, Inventory Costs, which amends the guidance in Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). SFAS No. 151 clarifies that abnormal amounts of idle facility expense, freight, handling costs, and wasted materials (spoilage) should be recognized as current-period charges instead of inventory costs. The provisions of this pronouncement will be effective for inventory costs incurred during fiscal years ending after June 15, 2005. The Company is currently evaluating whether the adoption of SFAS No. 151 will have any material financial statement impact.
      In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which requires companies to expense the fair value of equity awards over the required service period. This Statement is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123(R) supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, which uses the intrinsic value method to value stock-based compensation. The effective date of SFAS No. 123(R) will be as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. There are various methods of adopting SFAS No. 123(R), and the Company has not yet determined what method it will use. The Company will adopt SFAS No. 123(R) effective July 1, 2005.

79


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
      In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions. This Statement’s amendments are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, SFAS No. 153 eliminates the narrow exception for nonmonetary exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. The provisions of this pronouncement will be effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not expect the adoption of SFAS No. 153 will have any material financial statement impact.
     (s) Use of Estimates
      The preparation of the combined financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant items subject to such estimates and assumptions include the allowance for doubtful accounts; inventories; mineral reserves; allowance for non-recoupable advance mining royalties; asset retirement obligations; employee benefit liabilities; future cash flows associated with assets; useful lives for depreciation, depletion, and amortization; workers’ compensation and black lung claims; postretirement benefits other than pensions; income taxes; and fair value of financial instruments. Due to the subjective nature of these estimates, actual results could differ from those estimates.
     (t) Reclassifications
      Certain prior period amounts have been reclassified to conform to the current year presentation.
(3) Notes and Other Receivables
      Notes and other receivables consisted of the following:
                   
    December 31,
     
    2004   2003
         
Notes receivable
  $ 5,986     $ 577  
Other receivables
    4,849       4,165  
             
 
Total notes and other receivables
  $ 10,835     $ 4,742  
             
      As part of a coal purchase agreement, the Company loaned an unrelated coal supplier $10,000 on June 10, 2004 at a variable interest rate to be repaid in installments over a two-year period beginning in August 2004. The loan is secured by the assets of the company and personally guaranteed by the company’s owner. As of December 31, 2004, $5,398 of the outstanding amount is included in current notes and other receivables and $3,083 is included in other assets.

80


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
(4) Inventories
      Inventories consisted of the following:
                   
    December 31,
     
    2004   2003
         
Raw coal
  $ 3,888     $ 4,710  
Saleable coal
    42,899       23,629  
Materials and supplies
    7,782       4,774  
             
 
Total inventories
  $ 54,569     $ 33,113  
             
(5) Prepaid Expenses and Other Current Assets
      Prepaid expenses and other current assets consisted of the following:
                   
    December 31,
     
    2004   2003
         
Prepaid insurance
  $ 16,577     $ 15,643  
Advance mining royalties
    4,831       1,928  
Refundable income taxes
    2,798        
Other prepaid expenses
    4,709       1,685  
             
 
Total prepaid expenses and other current assets
  $ 28,915     $ 19,256  
             
(6) Property, Plant, and Equipment
      Property, plant, and equipment consisted of the following:
                   
    December 31,
     
    2004   2003
         
Land
  $ 5,380     $ 4,514  
Mineral rights
    85,245       89,652  
Plant and mining equipment
    188,891       121,442  
Vehicles
    2,058       1,976  
Mine development
    11,205       2,333  
Office equipment and software
    7,264       5,865  
Construction in progress
    1,769       2,592  
             
      301,812       228,374  
Less accumulated depreciation, depletion, and amortization
    83,848       30,227  
             
 
Property, plant, and equipment, net
  $ 217,964     $ 198,147  
             
      As of December 31, 2004, the Company had commitments to purchase approximately $43,300 of new equipment, expected to be acquired at various dates through 2005.
      Depreciation expense was $50,679, $28,438, and $104 and depletion expense was $3,541, $2,396, and $45 for the years ended December 31, 2004 and 2003, and the period from December 14, 2002 to December 31, 2002, respectively.

81


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
(7) Goodwill
      The changes in the carrying amount of goodwill were as follows:
         
Balance as of December 31, 2002
  $  
Acquisition of U.S. AMCI
    17,121  
       
Balance as of December 31, 2003
    17,121  
2004 Adjustments
    1,520  
       
Balance as of December 31, 2004
  $ 18,641  
       
      The carrying amount of goodwill was increased by $1,520 during the year ended December 31, 2004 due to the final settlement of the amount of working capital acquired in the U.S. AMCI acquisition. See note 20.
(8) Other Intangibles
      Other intangible assets consisted of the following:
                           
        December 31,
    Estimated    
    Remaining Life   2004   2003
             
Sales contracts
    3 years     $ 3,248     $ 3,937  
Noncompete agreements
    2 years       250       200  
Other
                13  
                   
              3,498       4,150  
Less accumulated amortization
            2,343       1,254  
                   
 
Total other intangibles, net
          $ 1,155     $ 2,896  
                   
      As of December 31, 2004, aggregate annual future amortization expense associated with other intangible assets was as follows:
             
Years ending December 31:
       
 
2005
  $ 581  
 
2006
    436  
 
2007
    138  
       
   
Total
  $ 1,155  
       
      Total amortization expense recognized on intangible assets was $1,792, $5,220, and $125 for the years ended December 31, 2004 and 2003, and the period from December 14, 2002 to December 31, 2002, respectively.

82


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
(9) Other Assets
      Other assets consisted of the following:
                   
    December 31,
     
    2004   2003
         
Advance mining royalties, net
  $ 8,841     $ 9,638  
Deferred loan costs, net
    10,237       3,460  
Deferred common stock offering costs
    3,665        
Notes receivable
    3,451        
Investment in terminaling facility
    1,005       1,005  
Investment in Excelven Pty Ltd
    4,500        
Virginia tax credit receivable
    4,806       2,434  
Other
    321       1,814  
             
 
Total other assets
  $ 36,826     $ 18,351  
             
(10) Note Payable
      At December 31, 2004 and 2003, the Company has a note payable that financed certain insurance premiums in the amount of $15,228 and $14,425, respectively. Interest and principal are due in monthly installments, with interest at the rate of 4.39% and 3.55% for 2004 and 2003, respectively, with the final payment due November 13, 2005. The insurance policies financed include workers’ compensation, black lung, and property and liability coverages.
(11) Accrued Expenses and Other Current Liabilities
      Accrued expenses and other current liabilities consisted of the following:
                   
    December 31,
     
    2004   2003
         
Wages and employee benefits
  $ 20,201     $ 12,770  
Current portion of asset retirement obligation
    6,691       7,820  
Taxes other than income taxes
    6,136       6,243  
Freight
    12,376       1,974  
Contractor escrow
    1,615       1,499  
Deferred gains on sales of property interests
    808       355  
Deferred revenues
    1,086        
Current portion of self-insured workers’ compensation benefits
    1,612       450  
Workers’ compensation insurance premium payable
    3,567       773  
Interest payable
    1,632       210  
Additional consideration on acquisition
    5,000        
Accrued stock offering costs
    2,010        
Other
    5,549       3,048  
             
 
Total accrued expenses and other current liabilities
  $ 68,283     $ 35,142  
             

83


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
(12) Long-Term Debt
      Long-term debt consisted of the following:
                     
    December 31,
     
    2004   2003
         
10% Senior notes due 2012
  $ 175,000     $  
Revolving credit facility
    8,000       10,000  
Variable rate term loan
          45,000  
Seller financing (El Paso CGP Company)
          8,000  
8.75% term notes
          4,664  
Variable rate term notes
    1,466       2,679  
Capital lease obligation
    1,995        
Other
    16       196  
             
   
Total long-term debt
    186,477       70,539  
 
Less current portion
    1,693       13,329  
             
   
Long-term debt, net of current portion
  $ 184,784     $ 57,210  
             
      On May 18, 2004, Alpha and its wholly-owned subsidiary, Alpha Natural Resources Capital Corp., issued $175,000 of 10% senior notes due June 2012 in a private placement offering under Rule 144A of the Securities Act of 1933, as amended, resulting in net proceeds of approximately $171,500 after fees and other offering costs. The senior notes are unsecured but are guaranteed fully and unconditionally on a joint and several basis by all of Alpha’s wholly-owned domestic restricted subsidiaries. Interest is payable semi-annually in June and December. Additional interest on the senior notes is payable in certain circumstances if a registration statement with respect to an offer to exchange the notes for a new issue of equivalent notes registered under the Securities Act has not been declared effective on or prior to February 14, 2005 (270 days after the notes were issued), or if the offer to exchange the notes is not consummated within 30 business days after February 14, 2005. The amount of this additional interest is equal to 0.25% of the principal amount of the notes per annum during the first 90-day period after a failure to have the registration statement declared effective or consummate the exchange offer, and it will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until the registration statement has been declared effective and the exchange offer has been consummated, up to a maximum amount of additional interest of 1.0% per annum.
      On May 28, 2004, Alpha entered into a new revolving credit facility with a group of lending institutions led by Citicorp North America, Inc., as administrative agent (Citicorp Credit Facility). The Citicorp Credit Facility, as amended, provides for a revolving line of credit of up to $125,000 and a funded letter of credit facility of up to $50,000. As of December 31, 2004, the Company had $8,000 principal amount in borrowings outstanding under the revolving line of credit and $2,991 in letters of credit outstanding, leaving $114,009 available for borrowing. As of December 31, 2004, the funded letter of credit facility was fully utilized at $50,000 at an annual fee of 3.1% of the outstanding amount. Amounts drawn under the revolver bear interest at a variable rate based upon either the prime rate or a London Interbank Offered Rate (LIBOR), in each case plus a spread that is dependent on our leverage ratio. The interest rate applicable to our borrowings under the revolver was 7.0% as of December 31, 2004. The principal balance of the revolving credit note is due in May 2009. ANR Holdings and each of the subsidiaries of Alpha have guaranteed Alpha’s obligations under the revolving credit facility. The obligations of Alpha, ANR Holdings and Alpha’s subsidiaries under the Citicorp Credit Facility are collateralized by all of the assets of Alpha, ANR Holdings and Alpha’s subsidiaries. The Citicorp Credit Facility contains various affirmative and negative covenants which, among

84


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
others, establish net worth, interest coverage and leverage ratio requirements. The Company must pay an annual commitment fee up to a maximum of 1/2 of 1% of the unused portion of the commitment. The Company was in compliance with its debt covenants under the Citicorp Credit Facility as of December 31, 2004.
      Prior to May 28, 2004, the Company had a term loan and revolving credit facility with a group of lending institutions led by PNC Bank (PNC). As of December 31, 2003, $45,000 principal amount was outstanding under the term loan. The term note had a variable interest rate (4.39% at December 31, 2003) and was payable in quarterly principal installments of $2,250 plus interest, with a final balloon payment due March 11, 2006. The PNC credit facility provided for a revolving line of credit of up to $75,000. As of December 31, 2003, $10,000 principal amount and letters of credit totaling $24,014 were outstanding. Amounts drawn under the revolver had a variable interest rate (3.92% at December 31, 2003). The principal balance of the revolving credit note was due March 11, 2006. ANR Holdings and each of the subsidiaries of the Company had guaranteed Alpha’s obligations under the credit facility. The Company paid an annual commitment fee of 1/2 of 1% of the unused portion of the commitment. The PNC term loan and credit facility were paid in full on May 28, 2004.
      In conjunction with the purchase of Coastal Coal Company, LLC, the Company issued a note payable to El Paso CGP on January 31, 2003. The balance of the note at December 31, 2003 was $8,000. The note had a fixed interest rate of 14% and was due on March 11, 2009. This note was paid in full in May 2004.
      In conjunction with the purchase of the U.S. coal production and marketing operations of AMCI (U.S. AMCI) on March 11, 2003, the Company assumed term notes payable to Komatsu Financial LP. The balance of the notes at December 31, 2003, was $3,719. The notes had fixed interest rates with a weighted average of 8.75% at December 31, 2003, and were payable in monthly installments ranging from $4 to $24, through August 1, 2006. These notes were paid in full in May 2004.
      The Company has term notes payable to The CIT Group Equipment Financing, Inc. in the amount of $1,466 at December 31, 2004 and $2,679 at December 31, 2003. The term notes bear interest at variable rates with a rate of 5.71% at December 31, 2004 and a weighted average rate of 4.84% at December 31, 2003 and are payable in monthly installments ranging from $34 to $64, through April 2, 2006.
      In conjunction with the purchase of U.S. AMCI, the Company assumed term notes payable to the Caterpillar Financial Services Corporation. The balance of the notes at December 31, 2003, was $945. The notes had a fixed interest rate of 8.75% and were payable in monthly installments ranging from $9 to $25, through October 5, 2004. These notes were paid in full in May 2004.
      The Company issued notes payable to Pittston Coal Company for the purchase of certain assets of that company on December 13, 2002. The balance of the notes at December 31, 2002, was $25,743. In 2003, the notes were paid in full.
      The Company entered into a capital lease for equipment in conjunction with the purchase of substantially all of the assets of Moravian Run Reclamation Co., Inc. on April 1, 2004. The lease has a term of sixty months with monthly payments ranging from $20 to $60 with a final balloon payment of $180 in March 2009. The effective interest rate on the capital lease is approximately 12.15%. The capitalized cost of the leased property was $1,995 at December 31, 2004. Accumulated amortization was $378 at December 31, 2004. Amortization expense on capital leases is included with depreciation expense.
      The Company’s long-term debt is collateralized by substantially all assets of the Company.

85


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
      Future maturities of long-term debt, including capital lease obligations, are as follows as of December 31, 2004:
             
Year ending December 31:
       
 
2005
  $ 1,693  
 
2006
    736  
 
2007
    500  
 
2008
    316  
 
2009
    8,232  
 
Thereafter
    175,000  
       
   
Total long-term debt
  $ 186,477  
       
      Following is a schedule of future minimum lease payments under capital lease obligations together with the present value of the net minimum lease payments as of December 31, 2004:
             
Year ending December 31:
       
 
2005
  $ 720  
 
2006
    600  
 
2007
    600  
 
2008
    360  
 
2009
    240  
       
   
Total future minimum lease payments
    2,520  
Less amount representing interest
    (525 )
       
   
Present value of future minimum lease payments
    1,995  
Less current portion
    (505 )
       
   
Long-term capital lease obligation
  $ 1,490  
       

86


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
(13) Asset Retirement Obligation
      At December 31, 2004 and 2003, the Company has recorded asset retirement obligation accruals for mine reclamation and closure costs totaling $39,579 and $40,427, respectively. The portion of the costs expected to be incurred within a year in the amount of $6,691 and $7,820, at December 31, 2004 and 2003, respectively, is included in accrued expenses and other current liabilities. These regulatory obligations are secured by surety bonds in the amount of $91,394 at December 31, 2004 and $84,512 at December 31, 2003. Changes in the reclamation obligation were as follows:
           
Pittston Coal Company acquisition
  $ 15,050  
Accretion for 2002
    57  
       
 
Total asset retirement obligation at December 31, 2002
    15,107  
Coastal Coal Company, LLC acquisition
    12,861  
U.S. AMCI acquisition
    8,768  
Mears Enterprises, Inc. acquisition
    2,079  
Accretion for 2003
    2,699  
Sites added in 2003
    1,165  
Expenditures in 2003
    (2,252 )
       
 
Total asset retirement obligation at December 31, 2003
    40,427  
Accretion for 2004
    3,301  
2004 acquisitions
    1,189  
Sites added in 2004
    3,657  
Revisions in estimated cash flows
    (5,689 )
Expenditures in 2004
    (3,306 )
       
 
Total asset retirement obligation at December 31, 2004
  $ 39,579  
       
(14) Deferred Gains on Sales of Property Interests
      In February 2003, the Company sold an overriding royalty interest in certain mining properties for $11,850. The gain on this transaction in the amount of $850 was deferred and is being amortized over the associated remaining term of the mineral lease. This property interest was acquired from El Paso CGP Company in the acquisition of the Coastal Coal properties.
      In April 2003, the Company sold mineral properties for $53,625 in a sale/leaseback transaction. These properties had originally been acquired from Pittston Coal Company. The estimated gain on this transaction in the amount of $7,057 was deferred and is being amortized over the ten-year term of the lease. Also see note 20.
      The Company recognized $959 and $618 of the above deferred gains for the years ended December 31, 2004 and 2003, respectively. In addition, for the year ended December 31, 2004, the deferred gain was increased by $3,514 for revisions in estimated cash flows underlying the asset retirement obligation relating to the mineral properties which had been sold, increased by $1,480 for revisions in the estimated contract reclamation liability assumed in conjunction with the acquisition of the Virginia coal operations of Pittston Coal Company, and decreased by $5,000 relating to the accrual of additional consideration for the acquisition of the Virginia coal operations of Pittston Coal Company.

87


 

ANR FUND IX HOLDINGS, L.P. AND ALPHA NR HOLDING, INC. AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(In thousands, except percentages and share data)
(15) Fair Value of Financial Instruments
      The estimated fair values of financial instruments under SFAS No. 107, Disclosures About Fair Value of Financial Instruments, are determined based on relevant market information. These estimates involve uncertainty and cannot be determined with precision. The following methods and assumptions are used to estimate the fair value of each class of financial instrument.
      Cash and Cash Equivalents, Trade Accounts Receivables, Note Payable, Bank Overdraft, Trade Accounts Payable, and Other Current Liabilities: The carrying amounts approximate fair value due to the short maturity of these instruments.
      Notes Receivable: The fair value approximates the carrying value as the rates associated with the receivables are comparable to current market rates.