Annual Report

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Commission File No. 1-32423

ALPHA NATURAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware		02-0733940
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)
One Alpha Place, P.O. Box 2345, Abingdon, Virginia		24212
(Address of principal executive offices)		(Zip Code)

PART I

It em  1.

Business

 

Overview

We are a leading Appalachian coal supplier. We produce, process and sell steam and metallurgical coal from eight regional business units, which, as of February 1, 2007, are supported by 38 active underground mines , 27 active surface mines and 10 preparation plants located throughout Virginia, West Virginia, Kentucky, and Pennsylvania, as well as a road construction business in West Virginia that recovers coal. We are also actively involved in the purchase and resale of coal mined by others, the majority of which we blend with coal produced from our mines, allowing us to realize a higher overall margin for the blended product than we would be able to achieve selling these coals separately.

Steam coal, which is primarily purchased by large utilities and industrial customers as fuel for electricity generation, accounted for approximately 66% of our 2006 coal sales volume. The majority of our steam coal sales volume in 2006 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 34% of our 2006 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. We believe that the use of the coal we sale will grow as demand for power and steel increases.

During 2006, we sold a total of 29.1 million tons of steam and metallurgical coal and generated coal sales revenues of $1,687.6 million, EBITDA of $279.4 million and net income of $128.2 million. We define and reconcile EBITDA and explain its importance, in note 3 under “Selected Financial Data.” Our coal sales during 2006 consisted of 24.7 million tons of produced and processed coal, including 1.4 million tons purchased from third parties and processed at our processing plants or loading facilities prior to resale, and 4.4 million tons of purchased coal that we resold without processing. Approximately 68% of the purchased coal in 2006 was blended with coal produced from our mines prior to resale. Approximately 35% of our sales revenue in 2006 was derived from sales made outside the United States, primarily in Canada, Italy, France, India, Brazil, and Turkey.

As of December 31, 2006, we owned or leased 548.6 million tons of proven and probable coal reserves. Of our total proven and probable reserves, approximately 82% are low sulfur reserves, with approximately 57% having sulfur content below 1.0%. Approximately 91% of our total proven and probable reserves have a high Btu content which creates more energy per unit when burned compared to coals with lower Btu content. We believe that our total proven and probable reserves will support current production levels for more than 20 years.

As discussed in Note 24 to our financial statements, we have one reportable segment — Coal Operations — which consists of our coal extracting, processing and marketing operations, as well as our purchased coal sales function and certain other coal-related activities, including our recovery of coal incidental to our road construction operations. Our equipment and part sales and equipment repairs operations, terminal services, coal analysis services, leasing of mineral rights, and the non-coal recovery portion of our road construction operations described below under “— Other Operations” are not included in our Coal Operations segment.

History

In 2002, ANR Holdings, LLC (“ANR Holdings”) was formed by First Reserve Fund IX, L.P. and ANR Fund IX Holdings, L.P. (referred to as the “First Reserve Stockholders” or collectively with their affiliates, “First Reserve”) and our management to serve as the top-tier holding company of the Alpha Natural Resources organization. On February 11, 2005, Alpha Natural Resources, Inc. succeeded to the business of ANR Holdings in a series of transactions that we refer to collectively as the “Internal Restructuring,” and on February 18, 2005, Alpha Natural Resources, Inc. completed an initial public offering of its common stock. When we use the terms “Alpha,” “we,” “our,” “the Company” and similar terms in this report, we mean (1) prior to our Internal Restructuring, ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. (a subsidiary of First Reserve Fund IX, L.P. prior to our Internal Restructuring) and subsidiaries on a combined basis and (2) after our Internal Restructuring, Alpha Natural Resources, Inc. and its consolidated subsidiaries. Alpha Natural Resources, Inc. was formed under the laws of the State of Delaware on November 29, 2004.

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On December 13, 2002, the First Reserve Stockholders, who then owned 100% of the membership interests of ANR Holdings, acquired the majority of the Virginia coal operations of Pittston Coal Company (our “Predecessor”), a subsidiary of the Brink’s Company (formerly known as The Pittston Company), through wholly-owned subsidiaries of ANR Holdings for $62.9 million.

On January 31, 2003, wholly owned subsidiaries of ANR Holdings acquired Coastal Coal Company, LLC for $67.8 million, and on March 11, 2003, ANR Holdings and its subsidiaries acquired the U.S. coal production and marketing operations of American Metals and Coal International, Inc. (“AMCI”) for $121.3 million. Of the consideration for the U.S. AMCI acquisition, $69.0 million was provided in the form of an approximate 44% membership interest in ANR Holdings issued to the owners of AMCI, which together with the issuances of an approximate 1% membership interest to Madison Capital Funding, LLC and Alpha Coal Management reduced the First Reserve Stockholders membership interest in ANR Holdings to approximately 55%.

On November 17, 2003, we acquired the assets of Mears Enterprises, Inc. (“Mears”) for $38.0 million.

On April 1, 2004, we acquired substantially all of the assets of Moravian Run Reclamation Co., Inc. for five thousand dollars in cash and the assumption by us of certain liabilities, including four active surface mines and two additional surface mines under development, operating in close proximity to and serving many of the same customers as our AMFIRE business unit located in Pennsylvania.

On May 10, 2004, we acquired a coal preparation plant and railroad loading facility located in Portage, Pennsylvania and related equipment and coal inventory from Cooney Bros. Coal Company for $2.5 million in cash and an adjacent coal refuse disposal site from a Cooney family trust for $0.3 million in cash.

On October 13, 2004, our AMFIRE business unit entered into a coal mining lease with Pristine Resources, Inc., a subsidiary of International Steel Group Inc., for the right to deep mine a substantial area of the Upper Freeport Seam in Pennsylvania.

On February 11, 2005, we succeeded to the business and became the indirect parent entity of ANR Holdings in connection with the Internal Restructuring and, on February 18, 2005, we completed an initial public offering of our common stock (the “IPO”).

On April 14, 2005, we sold the assets of our Colorado mining subsidiary, National King Coal LLC, and related trucking subsidiary, Gallup Transportation and Transloading Company, LLC (collectively, “NKC”) to an unrelated third party for cash in the amount of $4.4 million, plus an amount in cash equal to the fair market value of NKC’s coal inventory, and the assumption by the buyer of certain liabilities of NKC.

On October 26, 2005, we acquired the Nicewonder Coal Group’s coal reserves and operations in southern West Virginia and southwestern Virginia. The Nicewonder acquisition consisted of the purchase of the outstanding capital stock of White Flame Energy, Inc., Twin Star Mining, Inc. and Nicewonder Contracting, Inc., the equity interests of Powers Shop, LLC and Buchanan Energy, LLC and substantially all of the assets of Mate Creek Energy of W. Va., Inc. and Virginia Energy Company, and the business of Premium Energy, Inc. by merger. We paid an aggregate purchase price of $328.2 million in the Nicewonder acquisition.  The operations we acquired from the Nicewonder Coal Group constitute our eight business unit, Callaway Natural Resources.

 

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On May 1, 2006, we acquired certain coal mining operations in eastern Kentucky from Progress Fuels Corp, a subsidiary of Progress Energy (Progress Acquisition) for $28.8 million, including adjustments for working capital. The Progress Acquisition consisted of the purchase of the outstanding capital stock of Diamond May Coal Co. and Progress Land Corp. and the assets of Kentucky May Coal Co., Inc. The operations acquired are adjacent to our Enterprise business unit and have been integrated with Enterprise.

On December 28, 2006, we paid $3.3 million and were obligated to make an additional contribution of $7.0 million in 2007 for a 94% ownership interest in Gallatin Materials LLC (“Gallatin”), a lime manufacturing venture near Cincinnati, Ohio. Gallatin plans to construct two rotary pre-heater lime kilns over the next several years to produce lime to be sold primarily to coal-burning utilities as a scrubbing agent for removing sulfur dioxide from flue gas, helping them to meet increasingly stringent air quality standards under the federal Clean Air Act. The lime will also be sold to steel producers for use as flux in electric arc and basic oxygen furnaces. The minority owners were granted restricted member interests in Gallatin, which vest based on performance criteria approximately three years from the closing date and which, if earned in their entirety, would reduce our ownership to 77.5%. We are committed to providing financing through a $3.8 million loan and a $2.6 million letter of credit to cover project cost overruns.

Mining Methods

We produce coal using two mining methods: underground room and pillar mining using continuous mining equipment, and surface mining.

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 2006, approximately 58% of our coal production volume from mines operated by our subsidiaries’ employees and contractors 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.

The other underground mining method commonly used in the United States is the longwall mining method, which we do not currently use at any of our mines. In longwall mining, a rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the roof of the mine while it advances through the coal. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface. Our Central Appalachian reserves often include non-contiguous seams of coal that can be extracted at a lower cost using continuous mining as opposed to the more capital intensive longwall method.

Surface Mining. Surface mining is used when coal is found close to the surface. In 2006, approximately 42% of our coal production volume from mines operated by our subsidiaries’ employees and contractors came from surface mines. This method involves the removal of overburden (earth and rock covering the coal) with heavy earthmoving equipment and explosives, loading out the coal, replacing the overburden and topsoil after the coal has been excavated and reestablishing vegetation and plant life and making other improvements that have local community and environmental benefit. Overburden is typically removed at our mines using large, rubber-tired diesel loaders. Seam recovery for surface mining is typically 90% or more.

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Coal Characteristics

In general, coal of all geological compositions is characterized by end use as either steam coal or metallurgical coal. Heat value, sulfur and ash content, and volatility, in the case of metallurgical coal, are the most important variables in the profitable marketing and transportation of coal. These characteristics determine the best end use of a particular type of coal. We mine, process, market and transport bituminous coal, characteristics of which are described below.

Heat Value. The heat value of coal is commonly measured in British thermal units, or “Btus.” A Btu is the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. All of our coal is bituminous coal, a “soft” black coal with a heat content that ranges from 9,500 to 15,000 Btus per pound. This coal is located primarily in Appalachia, Arizona, the Midwest, Colorado and Utah and is the type most commonly used for electric power generation in the United States. Bituminous coal is also used for metallurgical and industrial steam purposes. Of our estimated 548.6 million tons of proven and probable reserves, approximately 91% 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 82% of our proven and probable reserves are low sulfur coal.

High sulfur coal can be burned in plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by 50% to 90%. Plants without scrubbers can burn high sulfur coal by blending it with lower sulfur coal or by purchasing emission allowances on the open market, allowing the user to emit a predetermined amount of sulfur dioxide. Some older coal-fired plants have been retrofitted with scrubbers, although most have shifted to lower sulfur coals as their principal strategy for complying with Phase II of the Clean Air Act’s Acid Rain regulations. We expect that any new coal-fired generation plant built in the United States will use clean coal-burning technology.

Ash & Moisture Content. Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from seam to seam. Ash content is an important characteristic of coal because electric generating plants must handle and dispose of ash following combustion. The absence of ash is also important to the process by which metallurgical coal is transformed into coke for use in steel production. Moisture content of coal varies by the type of coal, the region where it is mined and the location of coal within a seam. In general, high moisture content decreases the heat value and increases the weight of the coal, thereby making it more expensive to transport. Moisture content in coal, as sold, can range from approximately 5% to 30% of the coal’s weight.

Coking Characteristics. The coking characteristics of metallurgical coal are typically measured by the coal’s fluidity, ARNU and volatility. Fluidity and ARNU tests measure the expansion and contraction of coal when it is heated under laboratory conditions to determine the strength of coke that could be produced from a given coal. Typically, higher numbers on these tests indicate higher coke strength. Volatility refers to the loss in mass, less moisture, when coal is heated in the absence of air. The volatility of metallurgical coal determines the percentage of feed coal that actually becomes coke, known as coke yield. Coal with a lower volatility produces a higher coke yield and is more highly valued than coal with a higher volatility, all other metallurgical characteristics being equal.

Mining Operations

We currently have eight regional business units, including two in Virginia, four predominately in West Virginia, one in Pennsylvania, and one in Kentucky. As of February 1, 2007, these business units include 10 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 methods, underground room and pillar and surface mining. Our underground mines generally consist of one or more single or dual continuous miner sections which are made up of the continuous miner, shuttle cars, roof bolters and various ancillary equipment. Our surface mines are a combination of mountain top removal, contour, highwall miner, and auger operations using truck/loader equipment fleets along with large production tractors. Most of our preparation plants are modern heavy media plants that generally have both coarse and fine coal cleaning circuits. We employ preventive maintenance and rebuild programs to ensure that our equipment is modern and well-maintained. During 2006, most of our preparation plants also processed coal that we purchased from third party producers before reselling it to our customers. Within each regional business unit, mines have been developed at strategic locations in close proximity to our preparation plants and rail shipping facilities. Coal is transported from our regional business units to customers by means of railroads, trucks, barge lines and ocean-going vessels from terminal facilities.

 

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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, 2007:

 

Regional Business Units

 

								Number and Type of
								Mines as of
								February1, 2007												2006
					Preparation plant(s) as of			Under-												Production of Saleable Tons
Regional Business Unit		Location			February 1, 2007			ground			Surface			Total			Railroad			(in 000’s)(1)
Paramont		Virginia			Toms Creek				8			6			14			NS			5,640
Dickenson-Russell		Virginia			McClure River and Moss#3				6			1			7			CSX, NS			2,140
Kingwood		West Virginia			Whitetail				1			0			1			CSX			1,414
Brooks Run		West Virginia			Erbacon				3			1			4			CSX			2,749
Welch		West Virginia			Litwar and Kepler				12			0			12			NS			2,998
AMFIRE		Pennsylvania			Clymer and Portage				5			13			18			NS			3,398
Enterprise		Kentucky			Roxana				3			3			6			CSX			2,554
Callaway		West Virginia/ Virginia							0			3			3			NS			3,934
					Total				38			27			65						24,827

 

(1)	Includes coal purchased from third-party producers that was processed at our subsidiaries’ preparation plants in 2006.

CSX Railroad = CSX

Norfolk Southern Railroad = NS

The coal production and processing capacity of our mines and processing plants is influenced by a number of factors including reserve availability, labor availability, environmental permit timing and preparation plant capacity.

The following provides a brief description of our business units as of February 1, 2007

Paramont. Our Paramont business unit produces coal from eight underground mines using continuous miners and the room and pillar mining method. Three of the underground mines are operated by independent contractors. The coal from these mining operations 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 six 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 2006, Paramont purchased approximately 208,000 tons of coal from third parties that was blended with Paramont’s coal and shipped to our customers. As of February 1, 2007, the Paramont business unit was operating at a capacity to ship approximately five and one half million tons per year.

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Dickenson-Russell. Our Dickenson-Russell business unit produces coal from six underground mines using continuous miners and the room and pillar mining method. Three 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 2006, Dickenson-Russell purchased approximately 137,000 tons of coal from third parties that was blended with Dickenson-Russell’s coal and shipped to our customers. As of February 1, 2007, 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 2006, Kingwood purchased approximately 37,000 tons of coal from third parties that was blended with Kingwood’s coal and shipped to our customers. As of February 1, 2007, the Kingwood business unit was operating at a capacity to ship approximately one and one-half million tons per year.

Brooks Run. Our Brooks Run business unit produces coal from three underground mines using continuous miners and the room and pillar mining method. All of the mining operations at the Brooks Run business unit are staffed and operated by Brooks Run employees. The coal is transported by truck to the Erbacon preparation plant operated by Brooks Run where it is cleaned, blended and loaded onto rail for shipment to customers. The Brooks Run business unit has one surface mine operated by Brooks Run employees. Brooks Run purchased approximately 15,000 tons of coal from third parties in 2006. As of February 1, 2007, the Brooks Run business unit was operating at a capacity to ship approximately two million tons per year.

Welch. Our Welch business unit produces coal from twelve underground mines using continuous miners and the room and pillar mining method. Three of the underground mines are operated by our employees, and the others are operated by independent contractors. The coal is transported by truck or rail to the Litwar and Kepler 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, 2007. During 2006, the Welch business unit purchased approximately 868,000 tons of coal from third parties that was blended with other coals and shipped to our customers. As of February 1, 2007, the Welch business unit was operating at a capacity to ship approximately three and one-quarter million tons per year.

AMFIRE. Our AMFIRE business unit produces coal from five underground mines using continuous miners and the room and pillar mining method. All of the underground mining operations at AMFIRE are staffed and operated by AMFIRE employees. The underground coal is delivered directly by truck to the customer, or to the Clymer or Portage coal preparation plants or raw coal loading docks where it is cleaned, blended and loaded onto rail or truck for shipment to customers. AMFIRE also operates thirteen truck/loader surface mines, six of which are operated by independent contractors. The surface mined coal is delivered directly by truck to the customer or transported to the Clymer or Portage coal preparation plants or raw coal loading docks where it is blended and loaded onto rail or truck for shipment to customers. During 2006, AMFIRE purchased approximately 137,000 tons of coal from third parties that was blended with AMFIRE’s coal and shipped to our customers. As of February 1, 2007, the AMFIRE business unit was operating at a capacity to ship approximately three and one-quarter 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. Two of the underground mining operations at Enterprise are staffed and operated by Enterprise employees. The coal from these underground mines is transported by truck to the Roxana coal preparation plant operated by Enterprise where it is cleaned, blended and loaded onto rail for shipment to customers. Enterprise also has three truck/loader surface mines, two of which are operated by independent contractors. The coal produced by the surface mines is transported to the Roxana preparation plant and Pioneer load-out facility where it is blended and loaded onto rail for shipment to customers. During 2006, Enterprise purchased approximately 45,000 tons of coal from third parties that was blended with Enterprise’s coal and shipped to our customers. As of February 1, 2007, the Enterprise business unit was operating at a capacity to ship approximately three million tons per year. The Progress acquisition was included in the Enterprise operations beginning May 2006.

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Callaway. Our Callaway business unit produces coal from three surface mining operations operated by our Callaway employees and also recovers coal from the road construction business operated by our subsidiary Nicewonder Contracting, Inc. (NCI).  Coal from our White Flame Surface mine and the coal recovered by NCI is trucked to our Mate Creek load-out facility where it is blended and loaded onto rail for shipment to customers. Coal from the Premium Energy Surface mine and highwall miner is currently trucked to Arch Coal, Inc’s Mingo Logan mining complex, where a portion of the coal is sold to Arch Coal Inc. with the remaining tons to various other customers. Coal from the Twin Star surface mine is trucked to our Virginia Energy load-out facility where it is loaded onto rail cars for transport to customers. The Callaway business unit has no active underground operations and did not purchase any coal from third parties during 2006. As of February 1, 2007, the Callaway business unit was operating at a capacity to ship approximately four million tons per year, including coal recovered by NCI as part of its road construction business.

Marketing, Sales and Customer Contracts

Our marketing and sales force, which is principally based in Latrobe, Pennsylvania, included 35 employees as of December 31, 2006, 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.

W e sold a total of 29.1 million tons of coal in 2006, consisting of 24.7 million tons of produced and processed coal and 4.4 million tons of purchased coal that we resold without processing. Of our total purchased coal sales of 5.8 million tons in 2006, approximately 3.9 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 1.4 million tons of our 2006 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 26.7 million tons of coal in 2005, consisting of 20.6 million tons of produced and processed coal and 6.1 million tons of purchased coal that we resold without processing. Of our total purchased coal sales of 7.6 million tons in 2005, approximately 5.0 million tons were blended prior to resale. Approximately 1.5 million tons of our 2005 purchased coal sales were processed by us. We sold a total of 25.3 million tons of coal in 2004, consisting of 18.9 million tons of produced and processed coal and 6.4 million tons of purchased coal that we resold without processing. Of our total purchased coal sales of 7.3 million tons in 2004, approximately 5.9 million tons were processed prior to resale. The breakdown of tons sold by market served for 2006, 2005 and 2004 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)
2006			19.1			66	%		10.0			34	%
2005			16.7			62	%		10.0			38	%
2004			15.8			63	%		9.5			37	%

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(1)

Steam coal sales include sales to utility and industrial customers. Sales of steam coal to industrial customers, who we define as consumers of steam coal who do not generate electricity for sale to third parties, accounted for approximately 4%, 3% and 4% of total sales in 2006, 2005 and 2004, respectively.

(2)

Our sales of steam coal during 2006 and 2005 were made primarily to large utilities and industrial customers in the Eastern region of the United States, and our sales of metallurgical coal during those years were made primarily to steel companies in the Northeastern and Midwestern regions of the United States and in several countries in Europe, Asia and South America.

We sold coal to over 118 different customers in 2006. Our top ten customers in 2006 accounted for approximately 38% of 2006 revenues and our largest customer during 2006 accounted for approximately 7% of 2006 revenues. The following table provides information regarding our exports (including to Canada) in 2006, 2005 and 2004 by revenues and tons sold:

Year		Export Tons Sold			Export Tons Sold as a Percentage of Total Coal Sales			Export Sale Revenues (1)			Export Sales Revenue as a Percentage of Total Revenues
		(In millions, except percentages)
2006			7.2			25	%	$	668.8			35	%
2005			8.4			31	%	$	737.1			45	%
2004			8.1			32	%	$	597.9			48	%

 

(1)	Export sale revenues in 2006 and 2005 include approximately $0.7 million and $0.6 million, respectively, in equipment export sales. All other export sale revenues are coal sales revenues and freight and handling revenues.

Our export shipments during 2006, 2005 and 2004 serviced customers in 18, 16 and 18 countries, respectively, across North America, Europe, South America, Asia and Africa. Canada was our largest export market in 2006 , with sales to Canada accounting for approximately 17% of export revenues and 6% of total revenues. Canada was our largest export market in 2005 accounting for approximately 15% of export revenues and approximately 7% of total revenues, while 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. 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. The majority of the metallurgical coal sales contracts we entered into during 2004 and 2005 were long-term contracts. During 2006, approximately 63% and 45% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts and during 2005, approximately 86% and 75% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts.

At February 5, 2007, 83% of our planned 2007 production was committed and priced and 7% was committed and unpriced, with approximately 2.0 million tons uncommitted. Committed steam coal prices for 2007 average $48 to $49 per ton and committed metallurgical prices average $72 to $73 per ton. Approximately 43% of our planned production in 2008 was committed at February 5, 2007. At December 31, 2006, we had commitments to purchase 2.4 million tons of coal during 2007.

The terms of our contracts result from bidding and negotiations with customers. Consequently, the terms of these contracts typically vary significantly in many respects, including price adjustment features, provisions permitting renegotiation or modification of coal sale prices, coal quality requirements, quantity parameters, flexibility and adjustment mechanisms, permitted sources of supply, treatment of environmental constraints, options to extend and force majeure, suspension, termination and assignment provisions, and provisions regarding the allocation between the parties of the cost of complying with future governmental regulations.

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Distribution

We employ transportation specialists who negotiate freight and terminal agreements with various providers, including railroads, trucks, barge lines, and terminal facilities. Transportation specialists also coordinate with customers, mining facilities and transportation providers to establish shipping schedules that meet the customer’s needs. Our produced and processed coal is loaded from our ten preparation plants and in certain cases directly from our mines. The coal we purchased is loaded 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 73% of total shipments of coal volume produced and processed coal from our mines to the preparation plant to the customer in 2006. The balance was shipped from our preparation plants, loadout facilities or mines via truck. In 2006, approximately 8% of our coal sales were ultimately delivered to customers through transport on the Great Lakes, approximately 12% was moved through the Norfolk Southern export facility at Norfolk, Virginia, approximately 4% was moved through the coal export terminal at Newport News, Virginia operated by Dominion Terminal Associates, 2% was moved through the export terminal at Baltimore, Maryland, and approximately 1% was moved through an export terminal at New Orleans, LA. We own a 32.5% interest in the coal export terminal at Newport News, Virginia operated by Dominion Terminal Associates. See “— Other Operations.”

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 2006, only 3% 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 92% 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 2006 and 2005, we largely competed with producers from Australia, Canada, and other international producers of metallurgical coal.

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.

In addition to competition for coal sales in the United States and internationally, we compete with other coal producers, particularly in the Appalachian region, for the services of experienced coal industry employees at all levels of our mining operations.

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Other Operations

We have other operations and activities in addition to our normal coal production, processing and sales business, including:

Road Construction Business. NCI operates a road construction business under a contract with the State of West Virginia Department of Transportation. Pursuant to the contract, NCI is building approximately 11 miles of rough grade road in West Virginia over the next four to five years and, in exchange, NCI will be compensated by West Virginia based on the number of cubic yards of material excavated and/or filled to create a road bed, as well as for certain other cost components. As the road is constructed any coal recovered is sold by NCI as part of its coal operations.

Maxxim Rebuild. We own Maxxim Rebuild Co., LLC, a mining equipment company with facilities in Kentucky and Virginia. This business largely consists of repairing and reselling equipment and parts used in surface mining and in supporting preparation plant operations. Maxxim Rebuild had revenues of $34.9 million for 2006, of which approximately 86% was generated by services provided to our other subsidiaries and approximately 14% was generated by sales to external customers, including $0.7 million 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 2006, we shipped a total of 1.2 million tons of coal to our customers through the terminal. We make periodic cash payments in respect of the terminal for operating expenses, which are partially offset by payments we receive for transportation incentive payments and for renting our unused storage space in the terminal to third parties. Our cash payments for expenses for the terminal in 2006 were $4.9 million, partially offset by payments received in 2006 of $1.7 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%). We and our other interested partners are currently pursuing an investment of approximately $35.0 million for the construction of a new coal import facility at the terminal. Engineering and permitting work on the project has been completed. Construction could begin in the second half of 2007.

Gallatin Materials LLC. On December 28, 2006, the Company paid $3.3 million and we are obligated to make an additional contribution of $7.0 million in 2007 for a 94% ownership interest in Gallatin Materials LLC (Gallatin), a lime manufacturing venture near Cincinnati, Ohio. Gallatin plans to construct two rotary pre-heater lime kilns to produce lime to be sold primarily to coal-burning utilities as a scrubbing agent for removing sulfur dioxide from flue gas. The lime will also be sold to steel producers for use as flux in electric arc and basic oxygen furnaces.

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 94% of our coal production in 2006 came from mines operated by union-free employees, and as of December 31, 2006, over 92% of 3,546 employees were union-free. We believe our employee relations are good, and there have been no material work stoppages at any of our 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.

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We endeavor to conduct our mining operations in compliance with all applicable federal, state, and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations occur from time to time. None of the violations or the monetary penalties assessed upon us since our inception in 2002 has been material. Nonetheless, we expect that future liability under or compliance with environmental and safety requirements could have a material effect on our operations or competitive position. Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described below. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.

As of December 31, 2006, we had accrued $77.3 million for reclamation liabilities and mine closures, including $7.8 million of current liabilities.

Mining Permits and Approvals. Numerous governmental permits or approvals are required for mining operations. When we apply for these permits and approvals, we may be required to present data to federal, state or local authorities pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment. The authorization, permitting and/or implementation requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position to control another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.

In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including us, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior or better condition, productive use or other permitted condition. Typically, we submit our necessary permit applications several months, or even years, before we plan to begin mining a new area. Although permits may take six months or longer to obtain, in the past we have generally obtained our mining permits without significant delay. However, we cannot be sure that we will not experience difficulty in obtaining mining permits in the future.

Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals from the OSM, or from the applicable state agency if the state agency has obtained primacy. A state agency may achieve primacy if the state regulatory agency develops a mining regulatory program that is no less stringent than the federal mining regulatory program under SMCRA. States in which we have active mining operations have achieved primacy and a state agency is the regulatory authority for SMCRA permitting and enforcement activities.

SMCRA permit provisions include a complex set of requirements which include, but are not limited to: coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; disposal of excess spoil; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; post mining land use development; and re-vegetation.

The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes, but is not limited to, surveys and/or assessments of the following: cultural and historical resources; geology, including soils; existing vegetation; benthics; wildlife; potential for endangered species; surface and ground water hydrology; climatology; streams; and wetlands. The geologic data is used to define and model the soil and rock structures that will be encountered during the mining process. The geologic data and data from the other surveys and/or assessments are used to develop the mining and reclamation plans presented in the permit application. The mining and reclamation plans incorporate the provisions and performance standards of the state’s equivalent SMCRA regulatory program, and are also used to support applications for other authorizations and/or permits required to conduct coal mining activities. Also included in the permit application is information used for documenting surface and mineral ownership, variance requests, access roads, bonding information, mining methods, mining phases, other agreements that may relate to coal, other minerals, oil and gas rights, water rights, permitted areas, and ownership and control information required to determine compliance with OSM’s Applicant Violator System, including the mining and compliance history of officers, directors and principal owners of the entity.

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Once a permit application is prepared and submitted to the regulatory agency, it goes through an administrative completeness review and a thorough technical review. Also, before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of all reclamation obligations. After the application is submitted, a public notice or advertisement of the proposed permit is required to be given, which begins a notice period that is followed by a public comment period before a permit can be issued. It is not uncommon for a SMCRA mine permit application to take over a year to prepare, depending on the size and complexity of the mine, and anywhere from six months to two years or even longer for the permit to be issued. The variability in time frame required to prepare the permit and issue the permit can be attributed primarily to the various regulatory authorities’ discretion in the handling of comments and objections relating to the project received from the general public and other agencies. Also, it is not uncommon for a permit to be delayed as a result of litigation related to the specific permit or another related company’s permit.

In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund, which was created by SMCRA, requires a fee on all coal produced . The current fee is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal, but tax rate revisions were recently approved and will decrease to $0.315 per surface-mined ton and $0.135 per deep-mined ton in October 2007. Further reductions will occur in October 2012. The main purpose of the fee proceeds is to fund the reclamation of mine lands closed or abandoned prior to SMCRA’s adoption in 1977. In 2006, we recorded $5.0 million of expense related to this reclamation tax.

SMCRA stipulates compliance with many other major environmental statutes, including: the Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act (“RCRA”) and Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”).

Surety Bonds. Mine operators are often required by federal and/or state laws to assure, usually through the use of surety bonds, payment of certain long-term obligations including, but not limited to, mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other miscellaneous obligations. Although surety bonds are usually noncancelable during their term, many of these bonds are renewable on a yearly basis. The costs of these bonds have increased in recent years while the market terms of surety bonds have generally become more unfavorable to mine operators. These changes in the terms of the bonds have been accompanied by a decrease in recent years in the number of companies willing to issue surety bonds. We have a committed bonding facility with Travelers Casualty and Surety Company of America, pursuant to which Travelers has agreed, subject to certain conditions, to issue surety bonds on our behalf in a maximum amount of $150.0 million. During the fourth quarter of 2006, we also entered into a committed bonding facility with the Chubb Group of Insurance Companies. Chubb has agreed, subject to certain conditions, to issue surety bonds on our behalf in a maximum amount of $50.0 million. As of December 31, 2006, we have posted an aggregate of $138.0 million in reclamation bonds and $10.4 million of other types of bonds under these facilities.

Clean Air Act. The Clean Air Act and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter which may include controlling fugitive dust. The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of fine particulate matter measuring 2.5 micrometers in diameter or smaller, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired electricity generating plants. Continued tightening of the already stringent regulation of emissions from coal-fired power plants could eventually reduce the demand for coal.

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Clean Air Act requirements that may directly or indirectly affect our operations include the following:

 

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Acid Rain. Title IV of the Clean Air Act required a two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and applies to all coal-fired power plants generating greater than 25 Megawatts. Generally, the affected electricity generators have sought to meet these requirements by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances. Although we cannot accurately predict the future effect of this Clean Air Act provision on our operations, we believe that implementation of Phase II has resulted in, and will continue to result in, an upward pressure on the price of lower sulfur coals, as coal-fired power plants continue to comply with the more stringent restrictions of Title IV.

 

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Fine Particulate Matter. The Clean Air Act requires the U.S. Environmental Protection Agency (the “EPA”) to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for certain pollutants. Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels. For example, NAAQS currently exist for particulate matter with an aerodynamic diameter less than or equal to 10 microns, or PM10, and for fine particulate matter with an aerodynamic diameter less than or equal 2.5 microns, or PM2.5. The EPA designated all or part of 225 counties in 20 states as well as the District of Columbia as non-attainment areas with respect to the PM2.5 NAAQS. Individual states must identify the sources of emissions and develop emission reduction plans. These plans may be state-specific or regional in scope. Under the Clean Air Act, individual states have up to twelve years from the date of designation to secure emissions reductions from sources contributing to the problem. Meeting the new PM2.5 standard may require reductions of nitrogen oxide and sulfur dioxide emissions. Future regulation and enforcement of the new PM2.5 standard will affect many power plants, especially coal-fired plants and all plants in “non-attainment” areas.

 

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Ozone. Significant additional emissions control expenditures will be required at coal-fired power plants to meet the current NAAQS for ozone. Nitrogen oxides, which are a by-product of coal combustion, are classified as an ozone precursor. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding in the years ahead. For example, in November 2005, EPA issued a final rule, called the Phase 2 Ozone Rule, describing the action that states must take to reduce ground level ozone. The EPA designated counties in 32 states as non-attainment areas under the new standard. These states will have until June 2007 to develop plans, referred to as state implementation plans or SIPs, for pollution control measures that allow them to comply with the standards.

 

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NOx SIP Call. The NOx SIP Call program was established by the EPA in October 1998 to reduce the transport of ozone on prevailing winds from the Midwest and South to states in the Northeast, which said they could not meet federal air quality standards because of migrating pollution. The program is designed to reduce nitrous oxide emissions by one million tons per year in 22 eastern states and the District of Columbia. Installation of additional control measures, such as selective catalytic reduction devices, required under the final rules will make it more costly to operate coal-fired electricity generating plants, thereby making coal a less attractive fuel.

 

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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, 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. The rule is also subject to judicial challenge, which makes its impact difficult to assess.

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Clean Air Mercury Rule. On March15, 2005, the EPA issued the Clean Air Mercury Rule to permanently cap and reduce mercury emissions from coal-fired power plants. The Clean Air Mercury Rule establishes mercury emissions limits from new and existing coal-fired power plants and creates a market-based cap-and-trade program that is expected to reduce nationwide utility emissions of mercury in two phases. Stricter limitations on mercury emissions from power plants may adversely affect the demand for coal. In 2006, EPA proposed a federal plan to directly regulate mercury emissions from coal-fired power plants where certain states have not provided their own plans.

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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. In February 2004, EPA entered into a consent decree with parties including the states that had given notice of intent to sue in 2003 to compel the Agency to set new source performance standards. Under the consent decree, EPA promulgated final amendments to the new source performance standards for utility and industrial boilers in February 2006. In April 2006, ten states, the District of Columbia, and New York City petitioned the United States Court of Appeals for the District of Columbia Circuit for review of those new source performance standards for utility and industrial boilers, claiming that the EPA improperly refused to regulate carbon dioxide as a criteria pollutant and that the standards for sulfur dioxide and nitrogen oxides are insufficient. In June 2006, the United States Court of Appeals heard oral argument in a public nuisance action filed by eight states (Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York, and Vermont) and New York City to curb carbon dioxide emissions from power plants. In November 2006, the United States Supreme Court heard oral argument in a case that commenced in June 2003 challenging the EPA’s refusal to regulate carbon dioxide and other greenhouse gas emissions from new motor vehicles on the ground that it lacks the authority to list carbon dioxide as a criteria pollutant. If these lawsuits result in the issuance of a court order requiring the EPA to set emission limitations for carbon dioxide, this in turn could reduce the amount of coal our customers would purchase from us.

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Regional Emissions Trading . In December 2005, seven Northeastern states (Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York, and Vermont) signed the Regional Greenhouse Gas Initiative (RGGI) Agreement, calling for a ten percent reduction of carbon dioxide emissions by 2019, with compliance to begin January 1, 2009. Maryland signed onto RGGI in July 2006. The RGGI final model rule was issued on August 15, 2006, and participating states are developing their state rules. Climate change developments are also taking place on the west coast in California. In September 2006, California adopted greenhouse gas legislation that prohibits long-term base-load generation from having a greenhouse gas emissions rate greater than that of a combined cycle natural gas generator and that allows for long-term deals with generators that sequester carbon emissions. In October 2006, a trading partnership between California and the states participating in RGGI was announced. In December 2006, the California Public Utility Commission proposed regulations proposing to set a 1,000 lb/MWh carbon dioxide emission standard. The California Public Utility Commission is expected to adopt final regulations implementing California’s greenhouse gas legislation for investor-owned utilities in February 2007. These and other state climate change rules will likely require additional controls on coal-fired utilities and industrial boilers and may even cause some users of our coal to switch from coal to a lower carbon fuel. 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.

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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. Each state affected by this EPA program must develop and submit to EPA by mid-2007 a plan to achieve the goals of the program. The program may result in additional emissions restrictions from new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could affect the future market for coal.

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Clean Water Act. The Clean Water Act of 1972 (the “CWA”) and comparable state laws that regulate waters of the United States (“Jurisdictional Waters”) can affect coal mining operations both directly and indirectly. One of the direct impacts on coal mining and processing operations is Clean Water Act permitting requirements relating to the discharge of pollutants into Jurisdictional Waters. Indirect impacts of the CWA include discharge limits placed on coal-fired power plant ash handling facilities’ discharges. Continued litigation of CWA issues could eventually reduce the demand for coal.

Clean Water Act requirements that may directly or indirectly affect our operations include, but are not limited to, the following:

 

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Wastewater Discharge Act. Section 402 of the CWA establishes in-stream water quality criteria and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring and compliance with reporting requirements and performance standards are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water. The imposition of future restrictions on the discharge of certain pollutants into waters of the United States could affect the permitting process, increase the costs and difficulty of obtaining and complying with NPDES permits and could adversely affect our coal production.

Total Maximum Daily Load (“TMDL”) regulations established a process by which states designate stream segments as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, will be required to meet new TMDL effluent standards for these stream segments. Some of our operations currently discharge effluents into stream segments that have been designated as impaired. The adoption of new TMDL related effluent limitations for our coal mines could require more costly water treatment and could adversely affect our coal production.

Under the CWA, states must conduct an anti-degradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality. A state’s anti-degradation regulations would prohibit the diminution of water quality in these streams. In general, waters discharged from coal mines to high quality streams may be required to meet new “high quality” standards. This could cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits, and could adversely affect our coal production.

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Dredge and Fill Permits Act : Many mining activities, such as the development of refuse impoundments, fresh water impoundments, refuse fills, valley fills, and other similar structures, may result in impacts to Jurisdictional Waters. Jurisdictional Waters typically include wetlands, streams (including intermittent streams and their tributaries) and may, in certain instances, include man-made conveyances that have a hydrologic connection to such streams or wetlands. Prior to conducting such mining activities in jurisdictional waters, coal companies are required to obtain a Section 404 authorization (referred to as a dredge or fill permit) from the Army Corps of Engineers (“COE”). The COE is authorized to issue two types of Section 404 permits: a general permit referred to as a nationwide permit, more specifically a Nationwide Permit 21 (“NWP 21”) for surface mining activities and an individual permit. The COE may issue nationwide permits for any category of activities involving the discharge of dredge or fill material if the COE determines that such activities are similar in nature and will cause only minimal adverse environmental effects individually or cumulatively. Generally, the COE has used the NWP 21 to authorize impacts to jurisdictional waters from mining activities because the NWP process is a more streamlined permitting approach and consumes less COE resources.

      

The use of the NWP 21 to authorize stream impacts from mining activities was challenged in October 2003 in federal court in southern West Virginia. Although the challenge was successful at the district court level, the challenge was later overturned at the court of appeals. During the appeal period only, the COE was enjoined (only in the southern district of West Virginia) from using the NWP 21 to authorize dredge and fill activities for mining impacts. A similar challenge was filed in January 2005 prior to the court of appeals overturning the West Virginia district court) in federal court in eastern Kentucky and no decision has been rendered. Although we had operations in both states subject to the litigation, our Section 404 permits were in place and no production activities were interrupted. As a precaution to mitigate the uncertainty surrounding the use of the NWP 21 in these areas, we converted certain ongoing permits, pending applications, and planned applications from NWP 21 permits to individual permits. This precautionary step was taken to minimize the potential for future production interruptions.

 

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Mine Safety and Health. Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. In addition to federal regulatory programs, all of the states in which we operate also have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. In reaction to the recent mine accidents in West Virginia, state and federal legislatures and regulatory authorities have increased scrutiny of mine safety matters and passed more stringent laws governing mining. For example, in 2006, Congress enacted the Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”), which imposed additional burdens on coal operators, including (i) obligations related to (a) the development of new emergency response plans that address post-accident communications, tracking of miners, breathable air, lifelines, training and communication with local emergency response personnel, (b) establishing additional requirements for mine rescue teams, and (c) promptly notifying federal authorities in the event of a certain events, (ii) increased penalties for violations of the applicable federal laws and regulations, and (iii) the requirement that new standards be implemented regarding the manner in which closed areas of underground mines are sealed, and (iv) other matters. Various states also have enacted their own new laws and regulations addressing many of these same subjects. While existing and proposed regulations have a significant effect on our operating costs, our U.S. competitors are subject to the same degree of regulation.

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface- mined coal, neither amount to exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the United States. In 2006, we recorded $14.8 million of expense related to this excise tax.

Coal Industry Retiree Health Benefit Act of 1992. Unlike many companies in the coal business, we do not have any liability under the Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”), which requires the payment of substantial sums to provide lifetime health benefits to union-represented miners (and their dependents) who retired before 1992, because liabilities under the Coal Act that had been imposed on our Predecessor or acquired companies were retained by the sellers and, if applicable, their parent companies, in the applicable acquisition agreements. We should not be liable for these liabilities retained by the sellers unless they and, if applicable, their parent companies, fail to satisfy their obligations with respect to Coal Act claims and retained liabilities covered by the acquisition agreements.

Endangered Species Act. The federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to the areas in which we operate are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans. The U. S. Fish and Wildlife Service is working closely with OSM and State regulatory agencies to insure that Threatened and Endangered (T&E) species are protected from mining-related impacts. Should more stringent protective measures be applied to these T&E species or to their critical habitat, then we could experience increased operating costs or difficulty in obtaining future mining permits.

Resource Conservation and Recovery Act. The RCRA may affect coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. Currently, certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management.

Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion wastes generated at electric utility and independent power producing facilities, such as coal ash. In May 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under RCRA. The EPA is retaining the hazardous waste exemption for these wastes. However, the EPA has determined that national non-hazardous waste regulations under RCRA Subtitle D are needed for coal combustion wastes disposed in surface impoundments and landfills and used as mine-fill, and OSM is currently developing these regulations. 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.

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Due to the hazardous waste exemption for coal combustion waste such as ash, much coal combustion waste is currently put to beneficial use. For example, in one Pennsylvania mine from which we have the right to receive coal, we have used some ash as mine fill. The ash we use for this purpose is mixed with lime and serves to help alleviate the potential for acid mine drainage.

Federal and State Superfund Statutes. Superfund and similar state laws may affect coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault. In addition, mining operations may have reporting obligations under the Emergency Planning and Community Right to Know Act and the Superfund Amendments and Reauthorization Act.

Climate Change. One major by-product of burning coal is carbon dioxide, which is considered a greenhouse gas and is a major source of concern with respect to global warming. In November 2004, Russia ratified the Kyoto Protocol to the 1992 Framework Convention on Global Climate Change (the “Protocol”), which establishes a binding set of emission targets for greenhouse gases. With Russia’s accedence, the Protocol now has sufficient support and became binding on all those countries that have ratified it on February 16, 2005. Four industrialized nations have refused to ratify the Protocol — Australia, Liechtenstein, Monaco, and the United States. Although the targets vary from country to country, if the United States were to ratify the Protocol our nation would be required to reduce greenhouse gas emissions to 93% of 1990 levels from 2008 to 2012. Canada, which accounted for 5.4% of our sales volume in 2006, ratified the Protocol in 2002. Under the Protocol, Canada will be required to cut greenhouse gas emissions to 6% below 1990 levels in 2008 to 2012, either in direct reductions in emissions or by obtaining credits through the Protocol’s market mechanisms. This could result in reduced demand for coal by Canadian electric power generators.

Future regulation of greenhouse gases in the United States could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act, state adoption of a greenhouse regulatory scheme, or otherwise. The Bush Administration has proposed a package of voluntary emission reductions for greenhouse gases reduction targets which provide for certain incentives if targets are met. Some states, such as Massachusetts and California, have already issued regulations regulating greenhouse gas emissions from large power plants. Further, in 2002, the Conference of New England Governors and Eastern Canadian Premiers adopted a Climate Change Action Plan, calling for reduction in regional greenhouse emissions to 1990 levels by 2010, and a further reduction of at least 10% below 1990 levels by 2020. Increased efforts to control greenhouse gas emissions, including the future ratification of the Protocol by the U.S., could result in reduced demand for coal.

     

Additional Information

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You may access and read our SEC filings through our website, at www.alphanr.com, or the SEC’s website, at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. You may also request copies of our filings, at no cost, by telephone at (276) 619-4410 or by mail at: Alpha Natural Resources, Inc., One Alpha Place, P.O. Box 2345, Abingdon, Virginia 24212, attention: Investor Relations.

Our Audit Committee Charter, Compensation Committee Charter, Nominating and Corporate Governance Committee Charter, Corporate Governance Practices and Policies, and Code of Business Ethics are also available on our website and available in print to any stockholder who requests them.

 

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It em  1A.

Risk Factors

 

A substantial or extended decline in coal prices could reduce our revenues and the value of our coal reserves.

     

Our results of operations are substantially dependent upon the prices we receive for our coal. The prices we receive for coal depend upon factors beyond our control, including:

 

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the supply of and demand for domestic and foreign coal;

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the demand for electricity;

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domestic and foreign demand for steel and the continued financial viability of the domestic and/or foreign steel industry;

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the proximity to, capacity of, and cost of transportation facilities;

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domestic and foreign governmental regulations and taxes;

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air emission standards for coal-fired power plants;

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regulatory, administrative, and judicial decisions;

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the price and availability of alternative fuels, including the effects of technological developments; and

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the effect of worldwide energy conservation measures.

     

Declines in the prices we receive for our coal could adversely affect our operating results and our ability to generate the cash flows we require to improve our productivity and invest in our operations.

 

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Our coal mining production and delivery is subject to conditions and events beyond our control, which could result in higher operating expenses and/or decreased production and sales and adversely affect our operating results.

     

A majority of our coal mining operations are conducted in underground mines and the balance of our operations are 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:

 

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delays and difficulties in acquiring, maintaining or renewing necessary permits or mining or surface rights;

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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;

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mining and processing equipment failures and unexpected maintenance problems;

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limited availability of mining and processing equipment and parts from suppliers;

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interruptions due to transportation delays;

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adverse weather and natural disasters, such as heavy rains and flooding;

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accidental mine water discharges;

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the termination of material contracts by state or other governmental authorities;

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the unavailability of qualified labor;

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strikes and other labor-related interruptions; and

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unexpected mine safety accidents, including fires and explosions from methane and other sources.

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If any of these conditions or events occur in the future at any of our mines or affect deliveries of our coal to customers, they may increase our cost of mining and delay or halt production at particular mines or sales to our customers either permanently for varying lengths of time, which could adversely affect our operating results. For example, in 2004 we experienced mine roof stability issues at our Kingwood underground mine, which resulted in a 23% decrease in production at this mine for 2004 as compared to 2003 full-year production (including production in 2003 prior to our acquisition of the mine). In addition, Hurricanes Katrina and Rita, which struck the Gulf Coast in August and September 2005, resulted in delayed shipments of our coal to our customers.

 

Any change in coal consumption patterns by steel producers or North American electric power generators resulting in a decrease in the use of coal by those consumers could result in lower prices for our coal, which would reduce our revenues and adversely impact our earnings and the value of our coal reserves.

    

Steam coal accounted for approximately 66% and 62% of our coal sales volume during 2006 and 2005, respectively. The majority of our sales of steam coal for 2006 and 2005 were to U.S. and Canadian electric power generators. The amount of coal consumed for U.S. and Canadian electric power generation is affected primarily by the overall demand for electricity, the location, availability, quality and price of competing fuels for power such as natural gas, nuclear, fuel oil and alternative energy sources such as hydroelectric power, technological developments, and environmental and other governmental regulations. We expect many new power plants will be built to produce electricity during peak periods of demand, when the demand for electricity rises above the “base load demand,” or minimum amount of electricity required if consumption occurred at a steady rate. However, we also expect that many of these new power plants will be fired by natural gas because they are cheaper to construct than coal-fired plants and because natural gas is a cleaner burning fuel. In addition, the increasingly stringent requirements of the Clean Air Act may result in more electric power generators shifting from coal to natural gas-fired power plants. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of steam coal that we mine and sell, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

We produce metallurgical coal that is used in both the U.S. and foreign steel industries. Metallurgical coal accounted for approximately 34% and 38% of our coal sales volume during 2006 and 2005, respectively. 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 could impact the collectibility of our accounts receivable from U.S. steel industry customers. In addition, the U.S. steel industry increasingly relies on electric arc furnaces or pulverized coal processes to make steel. These processes do not use coke. If this trend continues, the amount of metallurgical coal that we sell and the prices that we receive for it could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves. In the international market for metallurgical coal, there are indications that coal prices may have begun to level off or decline from their current, historically high levels. In a report issued at the end of November 2005, the EIA reported that 2005 steel production in China has been well above projections, resulting in a glut of steel despite China’s current position as the world’s largest consumer of steel. If the demand and pricing for metallurgical coal in international markets decreases in the future, the amount of metallurgical coal that we sell and the prices that we receive for it could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

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Forward sales and forward purchase contracts that are not accounted for as a hedge could cause earnings volatility in our statement of income for a given period.

     

We participate in forward purchase and forward sales contracts that are considered derivative instruments under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) that do not qualify under the “normal purchase and normal sales” exception. Transactions that do not qualify for this exception are required to be marked to market. Changes in fair value are recognized either in earnings or equity, depending on whether these transactions qualify for hedge accounting. Our contracts do not currently qualify for hedge accounting. Accordingly, changes in fair value have been recognized in earnings. During 2006, we increased coal sales revenue related to mark-to-market gains on open over the counter (“OTC”) coal sales contracts in the amount of $6.1 million and increased expense related to mark-to-market losses on open OTC coal purchase contracts as cost of coal sales in the amount of $5.7 million, resulting in an increase in pretax earnings of $0.4 million. At December 31, 2006, we had unrealized gains (losses) on open sales and purchase contracts in the amount of $6.1 million and ($5.9 million), respectively. These amounts are recorded in prepaid expenses and other current assets and accrued expenses and other current liabilities, respectively.  Due to market price fluctuations, we could see earnings volatility that we would normally not incur. 

 

A decline in demand for metallurgical coal would limit our ability to sell our high quality steam coal as higher-priced metallurgical coal and could affect the economic viability of certain of our mines that have higher operating costs.

Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on the prevailing conditions in the metallurgical and steam coal markets. We decide whether to mine, process and market these coals as metallurgical or steam coal based on management’s assessment as to which market is likely to provide us with a higher margin. We consider a number of factors when making this assessment, including the difference between the current and anticipated future market prices of steam coal and metallurgical coal, the lower volume of saleable tons that results from producing a given quantity of reserves for sale in the metallurgical market instead of the steam market, the increased costs incurred in producing coal for sale in the metallurgical market instead of the steam market, the likelihood of being able to secure a longer-term sales commitment by selling coal into the steam market and our contractual commitments to deliver different types of coals to our customers. During 2004, we believe that we sold approximately 8% of our produced and processed coal as metallurgical coal that we would have sold as steam coal in the market conditions prevalent during 2003. We believe that we generated approximately $65.0 million in additional revenues by selling this production as metallurgical coal rather than steam coal during 2004, based on a comparison of the actual sales price and volume versus the then-prevailing market price for steam coal and the volume of coal that we would have sold if the coal had been mined, processed and marketed as steam coal. A decline in the metallurgical market relative to the steam market could cause us to shift coal from the metallurgical market to the steam market, thereby reducing our revenues and profitability. 

 

Most of our metallurgical coal reserves possess quality characteristics that enable us to mine, process and market them as high quality steam coal. However, some of our mines operate profitably only if all or a portion of their production is sold as metallurgical coal to the steel market. If demand for metallurgical coal declined to the point where we could earn a more attractive return marketing the coal as steam coal, these mines may not be economically viable and may be subject to closure. Such closures would lead to accelerated reclamation costs, as well as reduced revenue and profitability.

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

     

Since our formation and the acquisition of our Predecessor in December 2002, we have completed four significant acquisitions and several smaller acquisitions and investments. We continually seek to expand our operations and coal reserves through acquisitions. If we are unable to successfully integrate the companies, businesses or properties we are able to acquire, our profitability may decline and we could experience a material adverse effect on our business, financial condition or results of operations. Acquisition transactions involve various inherent risks, including:

 

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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;

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the potential loss of key customers, management and employees of an acquired business;

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

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problems that could arise from the integration of the acquired business; and

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unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the acquisition.

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Any one or more of these factors could cause us not to realize the benefits anticipated to result from an acquisition. For example, in combining our Predecessor and acquired companies, we have incurred significant expenses to develop unified reporting systems and standardize our accounting functions. Additionally, we were unable to profitably operate NKC, which we acquired in connection with our acquisition of AMCI. In September 2004, we recorded an impairment charge of $5.1 million to reduce the carrying value of the assets of NKC to their estimated fair value, and we sold the assets of NKC on April 14, 2005.

Moreover, any acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. For instance, in connection with the Nicewonder acquisition, we issued and subsequently repaid $221.0 million principal amount of promissory installment notes of one of our indirect, wholly-owned subsidiaries, we issued 2,180,233 shares of our common stock valued at approximately $53.2 million, and we entered into a new $525.0 million credit facility, a portion of the net proceeds of which we used to pay the cash purchase price and acquisition expenses and the first installment of principal due on the promissory notes. In addition, future acquisitions could result in our assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous acquisitions.

 

The inability of the sellers of our Predecessor and acquired companies to fulfill their indemnification obligations to us under our acquisition agreements could increase our liabilities and adversely affect our results of operations and financial position.

     

In the acquisition agreements we entered into with the sellers of our Predecessor and acquired companies, including the acquisition agreements we entered into related to the Nicewonder, Progress and Gallatin acquisitions, the respective sellers and, in some of our acquisitions, their parent companies, agreed to retain responsibility for and indemnify us against damages resulting from certain third-party claims or other liabilities, such as workers’ compensation liabilities, black lung liabilities, postretirement medical liabilities and certain environmental or mine safety liabilities. The failure of any seller and, if applicable, its parent company, to satisfy their obligations with respect to claims and retained liabilities covered by the acquisition agreements could have an adverse effect on our results of operations and financial position if claimants successfully assert that we are liable for those claims and/or retained liabilities. The obligations of the sellers and, in some instances, their parent companies, to indemnify us with respect to their retained liabilities will continue for a substantial period of time, and in some cases indefinitely. The sellers’ indemnification obligations with respect to breaches of their representations and warranties in the acquisition agreements will terminate upon expiration of the applicable indemnification period (generally 18-24 months from the acquisition date for most representations and warranties, and from two to five years from the acquisition date for environmental representations and warranties), are subject to deductible amounts and will not cover damages in excess of the applicable coverage limit. The assertion of third-party claims after the expiration of the applicable indemnification period or in excess of the applicable coverage limit, or the failure of any seller to satisfy its indemnification obligations with respect to breaches of its representations and warranties, could have an adverse effect on our results of operations and financial position. See “— If our assumptions regarding our likely future expenses related to benefits for non-active employees are incorrect, then expenditures for these benefits could be materially higher than we have predicted.

 

Our inability to continue or expand the existing road construction and mining business of the Nicewonder Companies could adversely affect the expected benefits from the Nicewonder Acquisition.

     

One of our subsidiaries acquired the business of Nicewonder Contracting, Inc. (“NCI”) pursuant to the Nicewonder acquisition. NCI operates a road construction business under a contract with the State of West Virginia. Pursuant to the contract, NCI is building appro ximately 11 miles of rough grade highway in West Virginia over the next four to five years and, in exchange, NCI will be compensated by West Virginia based on the number of cubic yards of material excavated and/or filled to create a road bed, as well as for certain other cost components. In the course of the road construction, NCI will recover any coal encountered and sell the coal to its customers, subject to certain costs, including coal loading, transportation, coal royalty payments and applicable taxes and fees.

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The State of West Virginia has only approved funding for a portion of this road construction. If West Virginia does not fund the remaining sections of the highway project, it would adversely affect NCI’s earnings. Even if West Virginia funds the remainder of this project through the next four to five years, we are uncertain whether the state will fund any similar projects in the future. In addition, we have no current experience conducting and completing road projects and will rely on the expertise of the existing employees of NCI in order to operate the project, and other road projects we may undertake, profitably. Furthermore, litigation has been filed against NCI and the State of West Virginia claiming that the project violated competitive bidding and prevailing wage laws and regulations. If successful, the litigation could make the project considerably less advantageous to NCI or restrict or prohibit NCI from completing the project.

 

The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues and profitability.

Our largest customer during 2006 accounted for approximately 7% of our total revenues. We derived approximately 38% of our 2006 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 56% of our 2006 sales volume was sold under long-term coal supply agreements. At December 31, 2006, our long-term coal supply agreements had remaining terms of up to 10 years and an average remaining term of approximately two years. When our current contracts with customers expire or are otherwise renegotiated, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including pricing terms less favorable to us. As of February 05, 2007, approximately 10% and 57%, respectively, of our planned production for 2007 and 2008 was uncommitted. We may not be able to enter into coal supply agreements to sell this production on terms, including pricing terms, as favorable to us as our existing agreements. For additional information relating to our long-term coal supply contracts, see “Business — Marketing, Sales and Customer Contracts.”

As electric utilities continue to adjust to frequently changing regulations, including the Acid Rain regulations of the Clean Air Act, the Clean Air Mercury Rule, the Clean Air Interstate Rule and the possible deregulation of their industry, they are becoming increasingly less willing to enter into long-term coal supply contracts and instead are purchasing higher percentages of coal under short-term supply contracts. The industry shift away from long-term supply contracts could adversely affect us and the level of our revenues. For example, fewer electric utilities will have a contractual obligation to purchase coal from us, thereby increasing the risk that we will not have a market for our production. The prices we receive in the spot market may be less than the contractual price an electric utility is willing to pay for a committed supply. Furthermore, spot market prices tend to be more volatile than contractual prices, which could result in decreased revenues.

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Certain provisions in our long-term supply contracts may reduce the protection these contracts provide us during adverse economic conditions or may result in economic penalties upon our failure to meet specifications.

     

Price adjustment, “price reopener” and other similar provisions in long-term supply contracts may reduce the protection from short-term coal price volatility traditionally provided by these contracts. Price reopener provisions are particularly common in international metallurgical coal sales contracts. Some of our coal supply contracts contain provisions that allow for the price to be renegotiated at periodic intervals. Price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to agree on a new price, sometimes between a pre-set “floor” and “ceiling.” In some circumstances, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Any adjustment or renegotiation leading to a significantly lower contract price could result in decreased revenues. Accordingly, supply contracts with terms of one year or more may provide only limited protection during adverse market conditions.

Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of our agreements where the customer bears transportation costs permit the customer to terminate the contract if the transportation costs borne by them increase substantially. In addition, some of these contracts allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that increase the price of coal beyond specified limits.

Due to the risks mentioned above with respect to long-term supply contracts, we may not achieve the revenue or profit we expect to achieve from these sales commitments.

 

Disruption in supplies of coal produced by contractors and other third parties could temporarily impair our ability to fill customers’ orders or increase our costs.

          

In addition to marketing coal that is produced by our subsidiaries’ employees, we utilize contractors to operate some of our mines. Operational difficulties at contractor-operated mines, changes in demand for contract miners from other coal producers, and other factors beyond our control could affect the availability, pricing, and quality of coal produced for us by contractors. For example, during 2005, production at our contractor operations ran approximately 25% behind plan, primarily due to shortages in the supply of labor. As a result of this shortfall, we were forced to purchase coal at a higher cost than planned so that we could meet commitments to customers. To meet customer specifications and increase efficiency in fulfillment of coal contracts, we also purchase and resell coal produced by third parties from their controlled reserves. The majority of the coal that we purchase from third parties is blended with coal produced from our mines prior to resale and we also process (which includes washing, crushing or blending coal at one of our preparation plants or loading facilities) a portion of the coal that we purchase from third parties prior to resale. We sold 5.8 million tons of coal purchased from third parties during 2006, representing approximately 20% of our total sales during 2006. We believe that approximately 68% of our purchased coal sales in 2006 was blended with coal produced from our mines prior to resale, and approximately 5% of our total sales in 2006 consisted of coal purchased from third parties that we processed before resale. The availability of specified qualities of this purchased coal may decrease and prices may increase as a result of, among other things, changes in overall coal supply and demand levels, consolidation in the coal industry and new laws or regulations. Disruption in our supply of contractor-produced coal and purchased coal could temporarily impair our ability to fill our customers’ orders or require us to pay higher prices in order to obtain the required coal from other sources. Any increase in the prices we pay for contractor-produced coal or purchased coal could increase our costs and therefore lower our earnings. Although increases in market prices for coal generally benefit us by allowing us to sell coal at higher prices, those increases also increase our costs to acquire purchased coal, which lowers our earnings.

 

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.

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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 25% of our sales in 2006. The demand for U.S. coal exports is dependent upon a number of factors outside of our control, including the overall demand for electricity in foreign markets, currency exchange rates, the demand for foreign-produced steel both in foreign markets and in the U.S. market (which is dependent in part on tariff rates on steel), general economic conditions in foreign countries, technological developments, and environmental and other governmental regulations. For example, if the value of the U.S. dollar were to rise against other currencies in the future, our coal would become relatively more expensive and less competitive in international markets, which could reduce our foreign sales and negatively impact our revenues and net income. In addition, if the amount of coal exported from the United States were to decline, this decline could cause competition among coal producers in the United States to intensify, potentially resulting in additional downward pressure on domestic coal prices.

 

Fluctuations in transportation costs and the availability or reliability of transportation could affect the demand for our coal or temporarily impair our ability to supply coal to our customers.

     

Transportation costs represent a significant portion of the total cost of coal for our customers. Increases in transportation costs, such as those experienced during 2005 and 2006, could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, coordination of the many eastern loading facilities, the large number of small shipments, terrain and labor issues all combine to make shipments originating in the eastern United States inherently more expensive on a per-mile basis than shipments originating in the western United States.

Historically, high coal transportation rates from the western coal producing areas into Central Appalachian markets limited the use of western coal in those markets. More recently, however, lower rail rates from the western coal producing areas to markets served by eastern U.S. producers have created major competitive challenges for eastern producers. This increased competition could have a material adverse effect on our business, financial condition and results of operations.

We depend upon railroads, trucks, beltlines, ocean vessels and barges to deliver coal to our customers. Disruption of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, terrorist attacks, and other events could temporarily impair our ability to supply coal to our customers, resulting in decreased shipments. Certain shipments of our coal to customers were delayed by hurricanes in the Gulf Coast in 2005. In some cases, this delay will affect the timing of our recognition of revenue from these sales. Decreased performance levels over longer periods of time could cause our customers to look to other sources for their coal needs, negatively affecting our revenues and profitability.

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In 2006, 73% of our produced and processed coal volume was transported from the preparation plant to the customer by rail. In the past, we have experienced a general deterioration in the reliability of the service provided by rail carriers, which increased our internal coal handling costs. If there are continued disruptions of the transportation services provided by the railroad companies we use and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

We have investments in mines, loading facilities, and ports that in most cases are serviced by a single rail carrier. Our operations that are serviced by a single rail carrier are particularly at risk to disruptions in the transportation services provided by that rail carrier, due to the difficulty in arranging alternative transportation. If a single rail carrier servicing our operations does not provide sufficient capacity, revenue from these operations and our return on investment could be adversely impacted. The states of West Virginia and Kentucky have recently increased enforcement of weight limits on coal trucks on their public roads. It is possible that other states in which our coal is transported by truck could undertake similar actions to increase enforcement of weight limits. Such stricter enforcement actions could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production on a profit-making basis and could therefore adversely affect revenues and earnings.

 

Our business will be adversely affected if we are unable to develop or acquire additional coal reserves that are economically recoverable.

     

Our profitability depends substantially on our ability to mine coal reserves possessing quality characteristics desired by our customers in a cost-effective manner. As of December 31, 2006, we owned or leased 548.6 million tons of proven and probable coal reserves that we believe will support current production levels for more than 20 years, which is less than the publicly reported amount of proven and probable coal reserves and reserve lives (based on current publicly reported production levels) of the other large publicly traded coal companies. We have not yet applied for the permits required, or developed the mines necessary, to mine all of our reserves. Permits are becoming increasingly more difficult and expensive to obtain and the review process continues to lengthen. In addition, we may not be able to mine all of our reserves as profitably as we do at our current operations.

     

Because our reserves are depleted as we mine our coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. If we are unable to replace or increase our coal reserves on acceptable terms, our production and revenues will decline as our reserves are depleted. Exhaustion of reserves at particular mines also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to acquire additional coal reserves through acquisitions in the future also could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, or the lack of suitable acquisition candidates.

 

We face numerous uncertainties in estimating our recoverable coal reserves, and inaccuracies in our estimates could result in decreased profitability from lower than expected revenues or higher than expected costs.

     

Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our estimates of reserve information on engineering, economic and geological data assembled and analyzed by our internal engineers and which is periodically reviewed by third-party consultants. There are numerous uncertainties inherent in estimating the quantities and qualities of, and costs to mine, recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:

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future mining technology improvements;

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the effects of regulation by governmental agencies;

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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; and

▪

future coal prices, operating costs, capital expenditures, severance and excise taxes, royalties and development and reclamation costs.

 

Defects in title of any leasehold interests in our properties could limit our ability to mine these properties or result in significant unanticipated costs.

     

We conduct a significant part of our mining operations on properties that we lease. Title to most of our leased properties and mineral rights is not thoroughly verified until a permit to mine the property is obtained, and in some cases title with respect to leased properties is not verified at all. Our right to mine some of our reserves may be materially adversely affected by defects in title or boundaries. In order to obtain leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs or could even lose our right to mine, which could adversely affect our profitability.

 

Mining in Central and Northern Appalachia is more complex and involves more regulatory constraints than mining in other areas of the United States, which could affect our mining operations and cost structures in these areas.

     

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

 

Our work force could become increasingly unionized in the future, which could adversely affect the stability of our production and reduce our profitability.

          

Approximately 94% of our 2006 coal production came from mines operated by union-free employees. As of December 31, 2006, over 92% of our 3,546 employees are union-free. However, our subsidiaries’ employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. Any further unionization of our subsidiaries’ employees, or the employees of third-party contractors who mine coal for us, could adversely affect the stability of our production and reduce our profitability.

 

Our unionized work force could strike in the future, which could disrupt production and shipments of our coal and increase costs.

          

One of our subsidiaries has two negotiated wage agreements with the United Mine Workers of America (“UMWA”). These agreements, covering 275 employees as of December 31, 2006, expire on December 31, 2009. One of our other subsidiaries is currently negotiating a wage agreement with the UMWA covering an aggregate of 24 employees that expired on December 31, 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. Also, one of our other subsidiaries, that is idle, had a wage agreement with the UMWA that could be terminated by our subsidiary or the UMWA with notice but since it is idle, no employees are effected at this time. However, if the operation becomes active again, these employees could be affected.

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Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

     

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. During 2006, we had $0.7 million of bad debt expense. Our customer base is changing with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear on payment default. These new power plant owners may have credit ratings that are below investment grade. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default.

We have contracts to supply coal to energy trading and brokering companies under which those companies sell coal to end users. If the creditworthiness of the energy trading and brokering companies declines, this would increase the risk that we may not be able to collect payment for all coal sold and delivered to or on behalf of these energy trading and brokering companies.

 

The government extensively regulates our mining operations, which imposes significant costs on us, and future regulations could increase those costs or limit our ability to produce and sell coal.

     

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

 

•

employee health and safety;

•

mandated benefits for retired coal miners;

•

mine permitting and licensing requirements;

•

reclamation and restoration of mining properties after mining is completed;

•

air quality standards;

•

water pollution;

•

plant and wildlife protection;

•

the discharge of materials into the environment;

•

surface subsidence from underground mining; and

•

the effects of mining on groundwater quality and availability.

    

The costs, liabilities and requirements associated with these regulations may be costly and time consuming and may delay commencement or continuation of exploration or production operations. Failure to comply with these regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we are pursued for these sanctions, costs and liabilities, our mining operations and, as a result, our profitability could be adversely affected.

The possibility exists that new legislation and/or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. For example, in reaction to recent mine accidents in West Virginia, state and federal legislatures and regulatory authorities have increased scrutiny of mine safety matters and passed more stringent laws governing mining. In 2006, Congress enacted the MINER Act, which imposed additional burdens on coal operators, including (i) obligations related to (a) the development of new emergency response plans that address post-accident communications, tracking of miners, breathable air, lifelines, training and communication with local emergency response personnel, (b) insuring the availability of mine rescue teams, and (c) promptly notifying federal authorities in the event of a certain events, (ii) increased penalties for violations of the applicable federal laws and regulations, and (iii) the requirement that new standards be implemented regarding the manner in which closed areas of underground mines are sealed and (iv) other matters. Various states also have enacted their own new laws and regulations addressing many of these same subjects. Our compliance with these or any new mine health and safety regulations could increase our mining costs. New legislation or administrative regulations (or new judicial interpretations or administrative enforcement of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. These regulations, if proposed and enacted in the future, could have a material adverse effect on our financial condition and results of operations.

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Extensive environmental regulations affect our customers and could reduce the demand for coal as a fuel source and cause our sales to decline.

     

The Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. Such regulations will require significant emissions control expenditures for many coal-fired power plants to comply with applicable ambient air quality standards. As a result, these generators may switch to other fuels that generate less of these emissions or install more effective pollution control equipment, possibly reducing future demand for coal and the construction of coal-fired power plants.

Various new and proposed laws and regulations may require further reductions in emissions from coal-fired utilities. For example, under the new Clean Air Interstate Rule issued on March 10, 2005, the EPA will further regulate sulfur dioxide and nitrogen oxides from coal-fired power plants. When fully implemented, this rule is expected to reduce sulfur dioxide emissions in affected states by over 70% and nitrogen oxides emissions by over 60% from 2003 levels. The stringency of this cap may require many coal-fired sources to install additional pollution control equipment, such as wet scrubbers, to comply. Installation of additional pollution control equipment required by this rule could result in a decrease in the demand for low sulfur coal (because sulfur would be removed by the new emissions control equipment), potentially driving down prices for low sulfur coal. In addition, under the Clean Air Act, coal-fired power plants will be required to control hazardous air pollution emissions by no later than 2009, which likely will require significant new investment in pollution-control devices by power plant operators. Further, on March 15, 2005, the EPA finalized the Clean Air Mercury Rule intended to control mercury emissions from power plants, which could require coal-fired power plants to install new pollution controls or comply with a mandatory, declining cap on the total mercury emissions allowed from coal-fired power plants nationwide. Both the Clean Air Mercury Rule and the Clean Air Interstate Rule are subject to administrative reconsideration and judicial challenge. These standards and future standards could have the effect of making coal-fired plants unprofitable, thereby decreasing demand for coal. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use.

Several proposals are pending in Congress and various states that are designed to further reduce emissions of sulfur dioxide, nitrogen oxides and mercury from power plants, and certain ones could regulate additional air pollutants. If such initiatives are enacted into law, power plant operators could choose fuel sources other than coal to meet their requirements, thereby reducing the demand for coal. Current and possible future governmental programs are or may be in place to require the purchase and trading of allowances associated with the emission of various substances such as sulfur dioxide, nitrous oxide, mercury and carbon dioxide. Changes in the markets for and prices of allowances could have a material effect on demand for and prices received for our coal.

A regional haze program initiated by the EPA to protect and to improve visibility at and around national parks, national wilderness areas and international parks restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas, and may require some existing coal-fired power plants, and certain thermal dryers, to install additional control measures designed to limit haze-causing emissions.

One major by-product of burning coal is carbon dioxide, which is considered a greenhouse gas and is a major source of concern with respect to global warming. In November 2004, Russia ratified the Kyoto Protocol to the 1992 Framework Convention on Global Climate Change (the “Protocol”), which establishes a binding set of emission targets for greenhouse gases. With Russia’s accedence, the Protocol now has sufficient support and became binding on all those countries that have ratified it on February 16, 2005. Four industrialized nations have refused to ratify the Protocol — Australia, Liechtenstein, Monaco, and the United States. Although the targets vary from country to country, if the United States were to ratify the Protocol, our nation would be required to reduce greenhouse gas emissions to 93% of 1990 levels in a series of phased reductions from 2008 to 2012. Canada, which accounted for approximately 5.3% of our 2006 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.

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Future regulation of greenhouse gases in the United States could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act, or otherwise. The Bush Administration has proposed a package of voluntary emission reductions for greenhouse gases reduction targets which provide for certain incentives if targets are met. Some states, such as Massachusetts, have already issued regulations regulating greenhouse gas emissions from large power plants. Further, in 2002, the Conference of New England Governors and Eastern Canadian Premiers adopted a Climate Change Action Plan, calling for reduction in regional greenhouse emissions to 1990 levels by 2010, and a further reduction of at least 10% below 1990 levels by 2020. Increased efforts to control greenhouse gas emissions, including the future ratification of the Protocol by the United States, could result in reduced demand for our coal. See “Environmental and Other Regulatory Matters.”

 

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.

     

Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Our Predecessor and acquired companies also utilized certain hazardous materials and generated similar wastes. We may be subject to claims under federal and state statutes and/or common law doctrines for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of current or former conditions at sites that we own or operate currently, as well as at sites that we or our Predecessor and acquired companies owned or operated in the past, and at contaminated sites that have always been owned or operated by third parties. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share. We have not been subject to claims arising out of contamination at our facilities, and are not aware of any such contamination, but may incur such liabilities in the future.

We maintain extensive coal slurry impoundments at a number of our mines. Such impoundments are subject to extensive regulation. Slurry impoundments maintained by other coal mining operations have been known to fail, releasing large volumes of coal slurry. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as streams or bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.

These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect us.

 

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

     

Mining companies must obtain numerous permits that impose strict regulations on various environmental and safety matters in connection with coal mining. These include permits issued by various federal and state agencies and regulatory bodies. The permitting rules are complex and may change over time, making our ability to comply with the applicable requirements more difficult or even impossible, thereby precluding continuing or future mining operations. Private individuals and the public have certain rights to comment upon, submit objections to, and otherwise engage in the permitting process, including through court intervention. Accordingly, the permits we need may not be issued, maintained or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to conduct our mining operations. An inability to conduct our mining operations pursuant to applicable permits would reduce our production, cash flow, and profitability.

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Permits under Section 404 of the Clean Water Act are required for coal companies to conduct dredging or filling activities in jurisdictional waters for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. The Army Corps of Engineers (the “COE”) is empowered to issue “nationwide” permits for specific categories of filling activity that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404. Nationwide Permit 21 authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. On October 23, 2003, several citizens groups sued the COE in the U.S. District Court for the Southern District of West Virginia seeking to invalidate “nationwide” permits utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. Although the lower court enjoined the issuance of Nationwide 21 permits, that decision was overturned by the Fourth Circuit Court of Appeals, which concluded that the COE complied with the Clean Water Act in promulgating this permit. Although we had no operations that were immediately impacted or interrupted, the lower court’s decision required us to convert certain current and planned applications for Nationwide 21 permits to applications for individual permits. A similar lawsuit was filed on January 27, 2005 in the U.S. District Court for the Eastern District of Kentucky and remains pending, and other lawsuits may be filed in other states where we operate. Although it is not possible to predict the results of the Kentucky litigation, it could adversely affect our Kentucky operations.

 

Due to political and economic uncertainties in Venezuela, our investment in Excelven Pty Ltd could be at risk for loss

In 2004, we acquired a 24.5% interest in Excelven Pty Ltd, which, through its subsidiaries, controls the rights to the Las Carmelitas mining venture in Venezuela and the related Palmarejo export port facility on Lake Maracaibo in Venezuela.  The project is currently in the development stage, and final governmental approval of the project has not yet been obtained.  Political and economic uncertainties in Venezuela could delay or prevent such governmental approval from being obtained or otherwise impede execution of the project. Such political and economic uncertainties could also lead to events such as civil unrest, work stoppages or the nationalization or other expropriation of private enterprises by the Venezuelan government, which could result in a loss of all or a portion of our investment in Excelven, which is in excess of $5.8 million to date. 

 

Our mining operations consume significant quantities of commodities. If commodity prices increase significantly or rapidly, it could impact our cost of production.

 

Coal mines consume large quantities of commodities such as steel, copper, rubber products and liquid fuels. Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for these products are strongly impacted by the global commodities market. A rapid or significant increase in cost of some commodities could impact our mining costs because we have limited ability to negotiate lower prices, and, in some cases, do no have a ready substitute for these commodities.

 

We have reclamation and mine closure obligations. If the assumptions underlying our accruals are inaccurate, we could be required to expend greater amounts than anticipated.

 

The Surface Mining Control and Reclamation Act establish operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. We accrue for the costs of current mine disturbance and of final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our experience. The amounts recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected.

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Our ability to operate our company effectively could be impaired if we fail to attract and retain key personnel.

     

Our ability to operate our business and implement our strategies depends, in part, on the efforts of our executive officers and other key employees. In addition, our future success will depend on, among other factors, our ability to attract and retain other qualified personnel. The 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.

 

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. For example, during the year of 2005, production at our contractor operations was running approximately 25% behind plan, primarily due to shortages in the supply of labor. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our profitability.

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Our amount of 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.

Our financial performance could be affected by our amount of indebtedness. At December 31, 2006, we had $445.7 million of indebtedness outstanding, representing 56% of our total capitalization. This indebtedness consisted of $175.0 million principal of our 10% senior notes due 2012, a $247.5 term loan under our credit facility and $23.2 million of other indebtedness, including $1.5 million of capital lease obligations extending through March 2009, $0.7 million principal amount that we incurred in connection with the Gallatin Acquisition related to funds loaned by an unrelated third party to assist in the construction of the kiln and $21.0 million payable to an insurance premium finance company. In addition, under our credit facility we had $81.1 million of letters of credit outstanding at December 31, 2006.

In connection with the Nicewonder acquisition, we refinanced all outstanding indebtedness under our prior credit facility with a new credit facility, which provides for up to $525.0 million of borrowings, including a $275.0 million revolving credit facility and a $250.0 million term loan. In addition, under the terms of the Nicewonder acquisition, one of our indirect, wholly-owned subsidiaries issued $221.0 million in promissory installment notes, which have been paid in full. We may also incur additional indebtedness in the future.

This level of indebtedness could have important consequences to our business. For example, it could:

 

•

increase our vulnerability to general adverse economic and industry conditions;

•

make it more difficult to self-insure and obtain surety bonds or letters of credit;

•

limit our ability to enter into new long-term sales contracts;

•

make it more difficult for us to pay interest and satisfy our debt obligations, including our obligations with respect to the notes;

•

require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions and other general corporate activities;

•

limit our ability to obtain additional financing to fund future working capital, capital expenditures, research and development, debt service requirements or other general corporate requirements;

•

limit our flexibility in planning for, or reacting to, changes in our business and in the coal industry;

•

place us at a competitive disadvantage compared to less leveraged competitors; and

•

limit our ability to borrow additional funds.

     

If our cash flows and capital resources are insufficient to fund our debt service obligations or our requirements under our other long-term liabilities, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations, including our obligations with respect to the notes, or our requirements under our other long term liabilities. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our 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 current credit facility.

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Despite our current leverage, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our significant indebtedness.

     

We may be able to incur substantial additional indebtedness in the future. The terms of our new credit facility and the indenture governing our senior notes do not prohibit us from doing so. Our current credit facility provides for a revolving line of credit of up to $275.0 million, of which $193.9 million was available as of December 31, 2006. The addition of new debt to our current debt levels could increase the related risks that we now face. For example, the spread over the variable interest rate applicable to loans under our credit facility is dependent on our leverage ratio, and it would increase if our leverage ratio increases. Additional drawings under our revolving line of credit could also limit the amount available for letters of credit in support of our bonding obligations, which we will require as we develop and acquire new mines.

 

The covenants in our credit facility and the indenture governing the notes impose restrictions that may limit our operating and financial flexibility.

     

Our credit facility and the indenture governing our senior notes contain a number of significant restrictions and covenants that limit our ability and our subsidiaries’ ability to, among other things, incur additional indebtedness or enter into sale and leaseback transactions, pay dividends, make redemptions and repurchases of certain capital stock, make loans and investments, create liens, engage in transactions with affiliates and merge or consolidate with other companies or sell substantially all of our assets.

These covenants could adversely affect our ability to finance our future operations or capital needs or to execute preferred business strategies. In addition, if we violate these covenants and are unable to obtain waivers from our lenders, our debt under these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able repay our debt or borrow sufficient funds to refinance it. Even if we were able to obtain new financing, it may not be on commercially reasonable terms, on terms that are acceptable to us, or at all. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected.

 

Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal.

     

Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations. These bonds are typically renewable annually. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral or other less favorable terms upon those renewals. The ability of surety bond issuers and holders to demand additional collateral or other less favorable terms has increased as the number of companies willing to issue these bonds has decreased over time. Our failure to maintain, or our inability to acquire, surety bonds that are required by state and federal law would affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal. That failure could result from a variety of factors including, without limitation:

 

•

lack of availability, higher expense or unfavorable market terms of new bonds;

•

restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our credit facility or the indenture governing our senior notes; and

•

the exercise by third-party surety bond issuers of their right to refuse to renew the surety.

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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, 2006, we had $81.1 million of letters of credit in place, of which $70.7 million served as collateral for reclamation surety bonds and $10.4 million secured miscellaneous obligations. Our credit facility provides for revolving commitments of up to $275.0 million, all of which can be used to issue additional letters of credit. In addition, obligations secured by letters of credit may increase in the future. Any such increase would limit our available borrowing capacity under our current or future credit facilities and could negatively impact our ability to obtain additional financing to fund future working capital, capital expenditure or other general corporate requirements. Moreover, if we do not maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our mining operations.

 

If our assumptions regarding our likely future expenses related to benefits for non-active employees are incorrect, then expenditures for these benefits could be materially higher than we have predicted.

At the times that we acquired the assets of our Predecessor and acquired companies, the Predecessor and acquired operations were subject to long-term liabilities under a variety of benefit plans and other arrangements with active and inactive employees. We assumed a portion of these long-term obligations and are continuing to incur additional costs from our operations for postretirement, workers’ compensation and black lung liabilities. The current and non-current accrued portions of these long-term obligations, as reflected in our consolidated financial statements as of December 31, 2006, included $50.8 million of postretirement medical obligations and $8.3 million of self-insured workers’ compensation and black lung obligations. These obligations have been estimated based on assumptions that are described in the notes to our consolidated financial statements included elsewhere in this annual report. However, if our assumptions are incorrect, we could be required to expend greater amounts than anticipated.

Several states in which we operate consider changes in workers’ compensation laws from time to time, which, if enacted, could adversely affect us. In addition, if any of the sellers from whom we acquired our operations fail to satisfy their indemnification obligations to us with respect to postretirement claims and retained liabilities, then we could be required to expend greater amounts than anticipated. See “— The inability of the sellers of our Predecessor and acquired companies to fulfill their indemnification obligations to us under our acquisition agreements could increase our liabilities and adversely affect our results of operations.” Moreover, under certain acquisition agreements, we agreed to permit responsibility for black lung claims related to the sellers’ former employees who are employed by us for less than one year after the acquisition to be determined in accordance with law (rather than specifically assigned to one party or the other in the agreements). We believe that the sellers remain liable as a matter of law for black lung benefits for their former employees who work for us for less than one year; however, an adverse ruling on this issue could increase our exposure to black lung benefit liabilities.

 

Demand for our coal changes seasonally and could have an adverse effect on the timing of our cash flows and our ability to service our existing and future indebtedness.

     

Our business is seasonal, with operating results varying from quarter to quarter. We have historically experienced lower sales during winter months primarily due to the freezing of lakes that we use to transport coal to some of our customers. As a result, our first quarter cash flow and profits have been, and may continue to be, negatively impacted. Lower than expected sales by us during this period could have a material adverse effect on the timing of our cash flows and therefore our ability to service our obligations with respect to our existing and future indebtedness.

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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.

 

If we are unable to accurately estimate the overall risks or costs when we bid on a road construction contract which is ultimately awarded to us, we may achieve a lower than anticipated profit or incur a loss on the contract.

A larger percentage of our road construction revenues and contract backlog are typically derived from fixed unit price contracts. Fixed unit price contracts require us to perform the contract for a fixed unit price irrespective of our actual costs. As a result, we realize a profit on these contracts only if we successfully estimate our costs and then successfully control actual costs and avoid cost overruns. If our cost estimates for a contract are inaccurate, or if we do not execute the contract within our cost estimates, then cost overruns may cause us to incur losses or cause the contract not to be as profitable as we expected. This, in turn, could negatively affect our cash flow, earnings and financial position.

The costs incurred and gross profit realized on those contracts can vary, sometimes substantially, from the original projections due to a variety of factors, including, but not limited to:

•

onsite conditions that differ from those assumed in the original bid;

•

delays caused by weather conditions;

•

contract modifications creating unanticipated costs not covered by change orders;

•

changes in availability, proximity and costs of materials, including diesel fuel, explosives, and parts and supplies for our equipment;

•

coal recovery which impacts the allocation of cost to road construction;

•

availability and skill level of workers in the geographic location of a project;

•

our suppliers’ or subcontractors’ failure to perform;

•

mechanical problems with our machinery or equipment;

•

citations issued by a governmental authority, including the Occupational Safety and Health Administration and the Mine Safety and Health Administration;

•

difficulties in obtaining required governmental permits or approvals;

•

changes in applicable laws and regulations; and

•

claims or demands from third parties alleging damages arising from our work.

 

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It em 1B.

Unresolved Staff Issues

None

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Ite m 2.

Properties

 

Coal Reserves

     

We estimate that, as of December 31, 2006, we owned or leased total proven and probable coal reserves of approximately 548.6 million tons. We believe that our total proven and probable reserves will support current production levels for more than 20 years. “Reserves” are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. “Proven (Measured) Reserves” are defined by SEC Industry Guide 7 as reserves for which (1) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (2) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. “Probable reserves” are defined by SEC Industry Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our internal engineers, geologists and finance associates. We periodically update our reserve estimates to reflect past coal production, new drilling information and other geological or mining data, and acquisitions or sales of coal properties. Coal tonnages are categorized according to coal quality, mining method, permit status, mineability and location relative to existing mines and infrastructure. In accordance with applicable industry standards, proven reserves are those for which reliable data points are spaced no more than 2,700 feet apart. Probable reserves are those for which reliable data points are spaced 2,700 feet to 7,900 feet apart. Further scrutiny is applied using geological criteria and other factors related to profitable extraction of the coal. These criteria include seam height, roof and floor conditions, yield and marketability.

We periodically retain outside experts to independently verify our estimates of our coal reserves. The most recent of these reviews for our operations other than the Callaway and Progress reserves was completed in November 2004, and we obtained an independent third party review of the Callaway reserves that was completed in September 2005 as well as an independent third party review of the Progress reserves upon acquisition in May 2006. These reviews included the preparation of reserve maps and the development of estimates by certified professional geologists based on data supplied by us and using standards accepted by government and industry, including the methodology outlined in U.S. Geological Survey Circular 891. Reserve estimates were developed using criteria to assure that the basic geologic characteristics of the reserves (such as minimum coal thickness and wash recovery, interval between deep mineable seams and mineable area tonnage for economic extraction) were in reasonable conformity with existing and recently completed mine operation capabilities on our various properties. As a result of the November 2004 review, we increased our reserve estimate from 326.5 million tons as of January 1, 2004 to 514.5 million tons as of October 15, 2004.

As with most coal-producing companies in Appalachia, the great majority of our coal reserves are subject to leases from third-party landowners. These leases convey mining rights to the coal producer in exchange for a percentage of gross sales in the form of a royalty payment to the lessor, subject to minimum payments. Five percent of our reserve holdings are owned and require no royalty or per-ton payment to other parties. The average royalties paid by us for coal reserves from our producing properties was $3.24 per ton in 2006, representing 4.5% of our 2006 coal sales revenue.

 

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Although our coal leases have varying renewal terms and conditions, they generally last for the economic life of the reserves. According to our current mine plans, any leased reserves assigned to a currently active operation will be mined during the tenure of the applicable lease. Because the great majority of our leased or owned properties and mineral rights are covered by detailed title abstracts prepared when the respective properties were acquired by predecessors in title to us and our current lessors, we generally do not thoroughly verify title to, or maintain title insurance policies on, our leased or owned properties and mineral rights.

The following table provides the “quality” (sulfur content and average Btu content per pound) of our coal reserves as of December 31, 2006.

					Recoverable Reserves Proven&						Sulfur Content						Average Btu
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				141.7			102.3			29.8			9.6			139.4			2.3
Dickenson-Russell		Virginia				27.7			27.7			0			0			27.7			0
Kingwood		West Virginia				28.0			0			17.0			11.0			28.0			0
Brooks Run		West Virginia				25.2			6.4			18.8			0			10.1			15.1
Welch		West Virginia				89.3			89.3			0			0			89.3			0
AMFIRE		Pennsylvania				64.5			14.0			21.7			28.8			55.1			9.4
Enterprise/Enterprise Land & Reserve, Inc(3)		Kentucky				151.1			49.8			49.2			52.1			140.5			10.6
Callaway		West Virginia and Virginia				21.1			21.1			0			0			9.0			12.1
Totals						548.6			310.6			136.5			101.5			499.1			49.5
Percentages									57	%		25	%		18	%		91	%		9	%

________________

 

(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. 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.

(3)	Includes proven and probable reserves in Kentucky controlled by our subsidiary Enterprise Land & Reserve Inc obtained from the Progress Energy acquisition.

 

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The following table summarizes, by regional business unit, the tonnage of our coal reserves that is assigned to our operating mines, our property interest in those reserves and whether the reserves consist of steam or metallurgical coal, as of December 31, 2006.

 

					Recoverable
					Reserves Proven &			Total Tons						Total Tons
Regional Business Unit		State			Probable(1 )			Assigned(2 )			Unassigned(2)			Owned			Leased			Coal Type(3)
					(In millions of tons)
								(In millions of tons)						(In millions of tons)
Paramont/ Alpha Land and Reserves(4)		Virginia				141.7			56.5			85.2			0			141.7		Steam and Metallurgical
Dickenson-Russell		Virginia				27.7			27.7			0			0			27.7		Steam and Metallurgical
Kingwood		West Virginia				28.0			19.6			8.4			0			28.0		Steam and Metallurgical
Brooks Run		West Virginia				25.2			12.5			12.7			2.4			22.8		Steam and Metallurgical
Welch		West Virginia				89.3			43.4			45.9			1.1			88.2		Steam and Metallurgical
AMFIRE.		Pennsylvania				64.5			60.2			4.3			3.5			61.0		Steam and Metallurgical
Enterprise/Enterprise Land and Reserve Inc(5)		Kentucky				151.1			17.9			133.2			20.2			130.9		Steam
Callaway		West Virginia and Virginia				21.1			18.9			2.2			1.1			20.0		Steam and Metallurgical
Totals						548.6			256.7			291.9			28.3			520.3
Percentages									47	%		53	%		5	%		95	%

________________

 

(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. 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.

 

(5)	Includes proven and probable reserves in Kentucky controlled by our subsidiary Enterprise Land & Reserve Inc obtained from the Progress Energy acquisition.

 

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The following map shows the locations of Alpha’s properties, including the number of mines and preparation plants as of February 1, 2007 and 2006 production of saleable tons for each of our eight regional business units:

 

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

 

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It em  3.

Legal Proceedings

       

General. We are a party to a number of legal proceedings incident to our 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 our consolidated cash flows, results of operations or financial condition.

I tem  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, 2006.

PART II

 

It em  5.

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

     

The initial public offering of our common stock commenced on February 15, 2005. The Company’s common stock has been listed on the New York Stock Exchange since that time under the symbol “ANR.” There was no public market for our common stock prior to this date.

Price range of our common stock

Trading in our common stock commenced on the New York Stock Exchange on February 15, 2005 under the symbol “ANR”. The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock reported in the New York Stock Exchange consolidated tape.

2005		High			Low
First Quarter		$	30.50		$	21.65
Second Quarter			29.50			22.00
Third Quarter			32.73			23.83
Fourth Quarter			30.47			18.70
2006		High			Low
First Quarter		$	23.43		$	19.48
Second Quarter			25.50			20.37
Third Quarter			19.14			15.10
Fourth Quarter			16.51			14.42

As of January 15, 2007, there were approximately 255 registered holders of record of our common stock, including 192 unvested restricted stock positions. The transfer agent and registrar for our common stock is Computershare Trust Company, N.A.

Dividend Policy

We do not presently pay dividends on our common stock.

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Equity Compensation Plan Information

Plan Category		(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights			(b) Weighted- average exercise price of outstanding options, warrants and rights			(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders			1,608,739		$	18.02			1,955,318	(1)
Equity compensation plans not approved by security holders			—			—			—
Total			1,608,739		$	18.02			1,955,318

(1)	The Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan has 1,955,318 shares of common stock available for future issuance to qualified participants as of December 31, 2006.

 

I tem  6.

Selected Financial Data

The following table presents selected financial and other data about us and our Predecessor for the most recent five fiscal periods. The selected financial data as of December 31, 2006 and 2005 and for the years then ended have been derived from the audited consolidated financial statements and related footnotes of Alpha Natural Resources, Inc. and subsidiaries included in this annual report. The selected historical financial data as of December 31, 2004 and for the year then ended 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. The selected historical financial data as of December 31, 2003 and for the year then ended and for the period from December 14, 2002 to December 31, 2002 have been derived from the audited combined balance sheet of ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. and subsidiaries not included in this annual report. The selected historical financial data for the period from January 1, 2002 through December 13, 2002 (the “Predecessor Period”) have been derived from our Predecessor’s combined financial statements not included in this annual report. You should read the following table in conjunction with the financial statements, the related notes to those financial statements, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, see Item 1A “Risk Factors” of this report for a discussion of risk factors that could impact our future results of operations.

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		Alpha Natural Resources, Inc and Subsidiaries						ANR FUND IX Holdings, L.P. and Alpha NR Holding, Inc. and Subsidiaries									Predecessor
		Year Ended December 31, 2006			Year Ended December 31, 2005			Year Ended December 31, 2004			Year Ended December 31, 2003			December 14, 2002 to December 31, 2002			January 1, 2002 to December 13, 2002
		(In thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Coal revenues		$	1,687,553		$	1,413,174		$	1,079,981		$	694,596		$	6,260		$	154,715
Freight and handling revenues			188,366			185,555			141,100			73,800			1,009			17,001
Other revenues			34,743			27,926			28,347			13,453			101			6,031
Total revenues			1,910,662			1,626,655			1,249,428			781,849			7,370			177,747
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)			1,352,450			1,184,092			920,359			626,265			6,268			158,924
Freight and handling costs			188,366			185,555			141,100			73,800			1,009			17,001
Cost of other revenues			22,982			23,675			22,994			12,488			120			7,973
Depreciation, depletion and amortization			140,851			73,122			55,261			35,385			274			6,814
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)			67,952			88,132			40,607			21,926			471			8,797
Costs to exit business			—			—			—			—			—			25,274
Total costs and expenses			1,772,601			1,554,576			1,180,321			769,864			8,142			224,783
Refund of federal black lung excise tax			—			—			—			—			—			2,049
Other operating income, net			—			—			—			—			—			1,430
Income (loss) from operations			138,061			72,079			69, 107			11,985			(772	)		(45,557	)
Other income (expense):
Interest expense			(41,774	)		(29,937	)		(20,041	)		(7,848	)		(203	)		(35	)
Interest income			839			1,064			531			103			6			2,072
Miscellaneous income			523			91			722			574			—			—
Total other income (expense), net			(40,412	)		(28,782	)		(18,788	)		(7,171	)		(197	)		2,037
Income (loss) before income taxes and minority interest			97,649			43,297			50,319			4,814			(969	)		(41,520	)
Income tax expense (benefit)			(30,519	)		18,953			5,150			898			(334	)		(17,198	)
Minority interest			—			2,918			22,781			1,164			—			—
Income (loss) from continuing operations			128,168			21,426			22,388			2,752			(635	)		(24,322	)
Loss from discontinued operations			—			(213	)		(2,373	)		(490	)		—			—
Net income (loss)		$	128,168		$	21,213		$	20,015		$	2,262		$	(635	)	$	(24,322	)

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		Alpha Natural Resources, Inc and Subsidiaries						ANR FUND IX Holdings, L.P. and Alpha NR Holding, Inc. and Subsidiaries									Predecessor
		Year Ended December 31, 2006			Year Ended December 31, 2005			Year Ended December 31, 2004			Year Ended December 31, 2003			December 14, 2002 to December 31, 2002			January 1, 2002 to December 13, 2002
		(In thousands, except per share and per ton amounts)
Earnings per share data:
Net income (loss) per share, as adjusted(1)
Basic and diluted:
Income from continuing operations		$	2.00		$	0.38		$	1.52		$	0.19
Loss from discontinued operations			—			—			(0.16	)		(0.04	)
Net income per basic and diluted share		$	2.00		$	0.38		$	1.36		$	0.15
Pro forma net income (loss) per share(2)
Basic and diluted:
Income from continuing operations					$	0.35		$	0.25
Loss from discontinued operations						—			(0.07	)
Net income per basic and diluted share					$	0.35		$	0.18
Balance sheet data (at period end):
Cash and cash equivalents		$	33,256		$	39,622		$	7,391		$	11,246		$	8,444		$	88
Operating and working capital			116,464			35,074			56,257			32,714			(12,223	)		4,268	)
Total assets			1,145,793			1,013,658			477,121			379,336			108,442			156,328
Notes payable and long-term debt, including current portion			445,651			485,803			201,705			84,964			25,743			—
Stockholders’ equity and partners’ capital (deficit)			344,049			212,765			45,933			86,367			23,384			(132,997	)
Statement of cash flows data:
Net cash provided by (used in):
Operating activities		$	210,081		$	149,643		$	106,776		$	54,104		$	(295	)	$	(13,816	)
Investing activities			(160,046	)		(339,387	)		(86,202	)		(100,072	)		(38,893	)		(22,054	)
Financing activities			(56,401	)		221,975			(24,429	)		48,770			47,632			35,783	)
Capital expenditures			131,943			122,342			72,046			27,719			960			21,866
Other data
Production:
Produced/processed			24,827			20,602			19,069			17,199
Purchased			4,090			6,284			6,543			3,938
Total			28,917			26,886			25,612			21,137
Tons Sold:
Steam			19,050			16,674			15,836			14,809
Met			10,029			10,023			9,490			6,804
Total			29,079			26,697			25,326			21,613
Coal sales realization/ton:
Steam		$	49.05		$	41.33		$	32.66		$	27.14
Met		$	75.09		$	72.24		$	59.31		$	37.35
Total		$	58.03		$	52.93		$	42.64		$	32.14
Cost of coal sales/ton		$	46.51		$	44.35		$	36.34		$	28.98
Coal margin/ton		$	11.52		$	8.58		$	6.30		$	3.16
EBITDA, as adjusted(3)		$	279,435		$	145,197		$	119,327		$	47,663

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(1)

Basic earnings per share is computed by dividing net income or loss by the weighted average number of shares of common stock outstanding during the periods. Diluted earnings per share is computed by dividing net income or loss by the weighted average number of shares of common stock and dilutive common stock equivalents outstanding during the periods. Common stock equivalents include the number of shares issuable on exercise of outstanding options less the number of shares that could have been purchased with the proceeds from the exercise of the options based on the average price of common stock during the period. Due to the Internal Restructuring on February 11, 2005 and initial public offering of common stock completed on February 18, 2005, the calculation of earnings per share for 2005, 2004, and 2003 reflects certain adjustments, as described below.

The numerator for purposes of computing basic and diluted net income (loss) per share, as adjusted, includes the reported net income (loss) and a pro forma adjustment for income taxes to reflect the pro forma income taxes for ANR Fund IX Holdings, L.P.’s portion of reported pre-tax income (loss), which would have been recorded if the issuance of the shares of common stock received by the FR Affiliates in exchange for their ownership in ANR Holdings in connection with the Internal Restructuring had occurred as of January 1, 2003. For purposes of the computation of basic and diluted net income (loss) per share, as adjusted, the pro forma adjustment for income taxes only applies to the percentage interest owned by ANR Fund IX Holding, L.P., the non-taxable FR Affiliate. No pro forma adjustment for income taxes is required for the percentage interest owned by Alpha NR Holding, Inc., the taxable FR Affiliate, because income taxes have already been recorded in the historical results of operations. Furthermore, no pro forma adjustment to reported net income (loss) is necessary subsequent to February 11, 2005 because we are subject to income taxes.

The denominator for purposes of computing basic net income (loss) per share, as adjusted, reflects the retroactive impact of the common shares received by the FR Affiliates in exchange for their ownership in ANR Holdings in connection with the Internal Restructuring on a weighted-average outstanding share basis as being outstanding as of January 1, 2003. The common shares issued to the minority interest owners of ANR Holdings in connection with the Internal Restructuring, including the immediately vested shares granted to management, have been reflected as being outstanding as of February 11, 2005 for purposes of computing the basic net income (loss) per share, as adjusted. The unvested shares granted to management on February 11, 2005 that vest monthly over the two-year period from January 1, 2005 to December 31, 2006 are included in the basic net income (loss) per share, as adjusted, computation as they vest on a weighted-average outstanding share basis starting on February 11, 2005. The 33,925,000 new shares issued in connection with the initial public offering have been reflected as being outstanding since February 14, 2005, the date of the initial public offering, for purposes of computing the basic net income (loss) per share, as adjusted.

The unvested shares issued to management are considered options for purposes of computing diluted net income (loss) per share, as adjusted. Therefore, for diluted purposes, all remaining unvested shares granted to management are added to the denominator subsequent to February 11, 2005 using the treasury stock method, if the effect is dilutive. In addition, the treasury stock method is used for outstanding stock options, if dilutive, beginning with the November 10, 2004 grant of options to management to purchase units in ACM that were automatically converted into options to purchase up to 596,985 shares of Alpha Natural Resources, Inc. common stock at an exercise price of $12.73 per share.

 

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The computations of basic and diluted net income (loss) per share, as adjusted for 2005, 2004 and 2003 are set forth below:

		Year Ended December 31,
		2005			2004			2003
		(in thousands, except share and per share amounts)
Numerator:
Reported income from continuing operations		$	21,426		$	22,388		$	2,752
Deduct: Income tax effect of ANR Fund IX Holdings, L.P. income from continuing operations prior to Internal Restructuring			(91	)		(1,149	)		(138	)
Income from continuing operations, as adjusted			21,335			21,239			2,614
Reported loss from discontinued operations			(213	)		(2,373	)		(490	)
Add: Income tax effect of ANR Fund IX Holdings, L.P. loss from discontinued operations prior to Internal Restructuring			2			149			27
Loss from discontinued operations, as adjusted			(211	)		(2,224	)		(463	)
Net income, as adjusted		$	21,124		$	19,015		$	2,151
Denominator:
Weighted average shares— basic			55,664,081			13,998,911			13,998,911
Dilutive effect of stock options and restricted stock grants			385,465			—			—
Weighted average shares— diluted			56,049,546			13,998,911			13,998,911
Net income per share, as adjusted— basic and diluted:
Income from continuing operations, as adjusted		$	0.38		$	1.52		$	0.19
Loss from discontinued operations, as adjusted			—			(0.16	)		(0.04	)
Net income per share, as adjusted		$	0.38		$	1.36		$	0.15

 

(2)

Pro forma net income (loss) per share gives effect to the following transactions as if each of these transactions had occurred on January 1, 2004: the Nicewonder Acquisition and related debt refinancing in October 2005, the Internal Restructuring and initial public offering in February 2005, the issuance in May 2004 of $175.0 million principal amount of 10% senior notes due 2012, and the entry into a $175.0 million revolving credit facility in May 2004.

(3)

EBITDA is defined as net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, less interest income. EBITDA, as adjusted is EBITDA, further adjusted for minority interest. EBITDA and EBITDA, as adjusted, are non-GAAP measures 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 and EBITDA, as adjusted, are not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.

    

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

		Year Ended December 31,
		2006			2005			2004			2003
Net income		$	128,168		$	21,213		$	20,015		$	2,262
Interest expense			41,774			29,937			20,041			7,848
Interest income			(839	)		(1,064	)		(531	)		(103	)
Income tax expense (benefit)			(30,519	)		18,860			3,960			668
Depreciation, depletion and amortization			140,851			73,405			56,012			36,054
EBITDA			279,435			142,351			99,497			46,729
Minority interest			—			2,846			19,830			934
EBITDA, as adjusted		$	279,435		$	145,197		$	119,327		$	47,663

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It em  7.

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

     

You should read the following discussion and analysis in conjunction with our financial statements and related notes and our “Selected Historical Financial Data” included elsewhere in this annual report. The historical financial information discussed below for periods prior to the completion of our Internal Restructuring on February 11, 2005 is for ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc and subsidiaries on a combined basis, which prior to the completion of our Internal Restructuring were the owners of a majority of the membership interests of ANR Holdings, our top-tier holding company, and for Alpha Natural Resources, Inc. and subsidiaries on a consolidated basis for periods from and after the completion of our Internal Restructuring.

Overview

We produce, process and sell steam and metallurgical (met) coal from eight regional business units, which, as of February 1, 2007, are supported by 38 active underground mines, 27 active surface mines and 10 preparation plants located throughout Virginia, West Virginia, Kentucky, and Pennsylvania, as well as a road construction business in West Virginia that recovers coal. We also sell coal produced by others, the majority of which we process and/or blend with coal produced from our mines prior to resale, providing us with a higher overall margin for the blended product than if we had sold the coals separately. Our sales of steam coal in 2006 and 2005 accounted for approximately 66% and 62%, respectively, of our annual coal sales volume, and our sales of metallurgical coal in 2006 and 2005, which generally sells at a premium over steam coal, accounted for approximately 34% and 38%, respectively, of our annual coal sales volume. The increase in our percentage of steam coal sold was mainly due to our recent acquisitions which lead to an overall increase in tons sold while total met tons sold remained unchanged. Our sales of steam coal during 2006 and 2005 were made primarily to large utilities and industrial customers in the Eastern region of the United States, and our sales of met coal during those years were made primarily to steel companies in the Northeastern and Midwestern regions of the United States and in several countries in Europe, Asia and South America. Approximately 35% of our sales revenue in 2006 and 45% of our sales revenue in 2005 was derived from sales made outside the United States, primarily in Canada, Japan, Brazil, Korea and several countries in Europe. This decrease is due to a 6% decrease in export tons sold combined with an increase in our overall sales revenue.

In addition, we generate other revenues from equipment and parts sales, equipment repair, road construction, rentals, royalties, commissions, coal handling, terminal and processing fees, and coal and environmental analysis fees. We also record revenue for freight and handling charges incurred in delivering coal to our customers, which we treat as being reimbursed by our customers. However, these freight and handling revenues are offset by equivalent freight and handling costs and do not contribute to our profitability.

Our business is seasonal, with operating results varying from quarter to quarter. We generally experience lower sales and hence build coal inventory during the winter months primarily due to the freezing of lakes that we use to transport coal to some of our customers.

Our primary expenses are for wages and benefits, supply costs, repair and maintenance expenditures, cost of purchased coal, royalties, freight and handling costs, and taxes incurred in selling our coal. Historically, our cost of coal sales per ton is lower for sales of our produced and processed coal than for sales of purchased coal that we do not process prior to resale.

We have one reportable segment, Coal Operations, which includes all of our revenues and costs from coal production and sales, freight and handling, rentals, commissions, coal handling and processing operations and coal recovery incidental to our road construction operations. These revenues and costs included in our Coal Operations segment are reported by us in our coal revenues and cost of coal sales, except for the revenues and costs from rentals, commissions, and coal handling and processing operations, which we report in our other revenues and cost of other revenues, respectively.

 

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Table of Contents

 

Internal Restructuring and Our Initial Public Offering. On February 11, 2005, we completed a series of transactions in connection with the Internal Restructuring for the purpose of transitioning our top-tier holding company from a limited liability company to a corporation, and on February 18, 2005, we completed the initial public offering of our common stock. Further information regarding our Internal Restructuring and our initial public offering can be found in Note 2 to our consolidated financial statements included in this annual report. As a result of our initial public offering and our Internal Restructuring, we have incurred during the period after the initial public offering and Internal Restructuring and will continue to incur additional expenses that we did not incur in prior periods, including expenses associated with compliance with corporate governance and periodic financial reporting requirements for public companies. Moreover, all of our income is now subject to income tax and therefore the effective tax rates reflected in our financial statements for periods prior to the Internal Restructuring are not indicative of our effective tax rates after our Internal Restructuring.