Alpha Natural Resources (ANR)

Our marketing and sales force, which is principally based in Abingdon, Virginia, included 28 employees as of December 31, 2008, and consists of sales managers, distribution/traffic managers, contract administrators 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 marketing efforts are centered on customer needs and requirements.  Our overall sales philosophy is to market coal products and blends tailored to meet our customer's individual needs and specifications.  Coal products and blends are sourced from Alpha’s captive production supplemented by third party purchase coal when needed to better meet customer requirements or enhance overall economics.  By offering coal of both steam and metallurgical grades 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 and steel manufacturers who have been customers of ours or our Predecessor and acquired companies for decades.

We sold a total of 28.3 million tons of coal in 2008, consisting of 23.4 million tons of produced and processed coal and 4.9 million tons of purchased coal that we resold without processing. Of our total purchased coal sales of 6.4 million tons in 2008, approximately 4.2 million tons were blended prior to resale, meaning the coal was mixed with coal produced from our mines prior to resale, which generally allows us to realize a higher overall margin for the blended product than we would be able to achieve selling these coals separately. Approximately 1.5 million tons of our 2008 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 28.5 million tons of coal in 2007, consisting of 24.4 million tons of produced and processed coal and 4.1 million tons of purchased coal that we resold without processing. Of our total purchased coal sales of 5.8 million tons in 2007, approximately 3.7 million tons were blended prior to resale.  Approximately 1.7 million tons of our 2007 purchased coal sales were processed by us. We 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. Approximately 1.4 million tons of our 2006 purchased coal sales were processed by us.  The breakdown of tons sold by market served for 2008, 2007 and 2006 is set forth in the table below:

 

		Steam Coal Sales (1) (2)								Metallurgical Coal Sales (2)
Year		Tons				% of Total Sales Volume				Tons				% of Total Sales Volume
		(In millions, except percentages)
2008			16.4				58	%			11.9				42	%
2007			17.5				62	%			11.0				38	%
2006			19.1				66	%			10.0				34	%

	(1	)	Steam coal sales include sales to utility and industrial customers. Sales of steam coal to industrial customers, who we define as consumers of steam coal who do not generate electricity for sale to third parties, accounted for approximately 3%, 3% and 4% of total sales in 2008, 2007 and 2006, respectively.
	(2	)	Our sales of steam coal during 2008, 2007, and 2006 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 countries in Europe, Asia and South America.

 

We sold coal to over 100 different customers in 2008. Our top ten customers in 2008 accounted for approximately 53.5% of 2008 revenues and our largest customer during 2008 accounted for approximately 12.1% of 2008 revenues. The following table provides information regarding our exports (including to Canada) in 2008, 2007 and 2006 by revenues and tons sold:

Year		Export Tons Sold				Export Tons Sold as a Percentage of Total Coal Sales Volume				Export Sales Revenues (1)				Export Sales Revenue as a Percentage of Total Revenues
2008			8.8				31	%		$	1,318.7				52	%
2007			7.8				27	%		$	705.4				37	%
2006			7.2				25	%		$	668.8				35	%

 

(1

)

Export sale revenues in 2008, 2007, and 2006 include approximately $1.5 million, $1.2 million and $0.7 million, respectively, in equipment export sales from our Maxxim Rebuild business. All other export sale revenues are coal revenues and freight and handling revenues.

Our export shipments during 2008, 2007 and 2006 serviced customers in 20, 14 and 18 countries, respectively, across North America, Europe, South America, Asia and Africa. Brazil was our largest export market in 2008, with sales to Brazil accounting for approximately 14% of export revenues and 7% of total revenues. Canada was our largest export market in 2007 and 2006, with sales to Canada accounting for approximately 15% and 17% of export revenues, respectively, and 6% of total revenues for 2007 and 2006.  All of our sales are made in U.S. dollars, which reduces foreign currency risk. Approximately 4% 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 affected 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 2005 and 2006 were long-term contracts. During 2008, approximately 80% and 64% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts and during 2007, approximately 81% and 44% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts.

 

 

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Our sales backlog, including backlog subject to price reopener and/or extension provisions, was approximately 34.7 million tons as of January 16, 2009 and approximately 36.4 million tons at the beginning of 2008. Of these tons, approximately 56% and 63% were expected to be filled within one year.

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

 

Distribution

We employ transportation specialists who negotiate freight and terminal agreements with various providers, including railroads, trucks, barge lines, and terminal facilities. Transportation specialists also coordinate with customers, mining facilities and transportation providers to establish shipping schedules that meet the customer's needs. Our produced and processed coal is loaded from our eleven preparation plants, loadout facilities, and in certain cases directly from our mines. The coal we purchase 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, lake-going vessels and ocean-going vessels from terminal facilities. Rail shipments constituted approximately 58% of total shipments of coal volume produced and processed coal from our mines to the preparation plant to the customer in 2008. The balance was shipped from our preparation plants, loadout facilities or mines via truck. In 2008, approximately 4% of our coal sales were delivered to our customers through transport on the Great Lakes, approximately 19% was moved through the Norfolk Southern export facility at Norfolk, Virginia, approximately 8% was moved through the coal export terminal at Newport News, Virginia operated by Dominion Terminal Associates, and less than 2% was moved through the export terminals at Baltimore, MD and New Orleans, LA. We own a 40.6% interest in the coal export terminal at Newport News, VA 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. 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. In 2008, imports accounted for a relatively small percentage of total U.S coal consumption.  As of October 2008, 3% of total U.S. coal consumption in 2008 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 greater than 93% of 2008 domestic coal consumption as of October 2008. 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 and commercial and industrial outputs 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 2008 and 2007, we largely competed with producers from Australia, Canada, and other international producers of metallurgical coal.

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 one to two 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.  The Company also has other minor road construction projects in conjunction with other surface mining 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 $42.0 million for 2008, of which approximately 85% was generated by services provided to our other subsidiaries and approximately 15% was generated by sales to external customers, including $1.5 million to export customers.

Dominion Terminal Associates. Through our subsidiary Alpha Terminal Company, LLC, we hold a 40.6% interest in DTA, a 20 million-ton annual capacity coal export terminal located in Newport News, Virginia. The terminal, constructed in 1984, provides the advantages of unloading/transloading equipment with ground storage capability, providing producers with the ability to custom blend export products without disrupting mining operations. During 2008, we shipped a total of 2.3 million tons of coal to our customers through the terminal. We make periodic cash payments in respect of the terminal for operating expenses, which are offset by payments we receive for transportation incentive payments and for renting our unused storage space in the terminal to third parties. In 2008, we received cash payments related to the terminal of $6.6 million, partially offset by payments we made for expenses of $5.7 million. The terminal is held in a partnership with subsidiaries of two other companies, Arch Coal and Peabody Energy.  

Gallatin.  In December 2006, our subsidiary, Palladian, acquired a 94% ownership interest in Gallatin, a start-up lime manufacturing business in Verona, Kentucky.  In September 2008, we sold our interest in Gallatin for cash in the amount of $45.0 million.

 

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.

 

 

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Employee and Labor Relations

Approximately 96% of our coal production in 2008 came from mines operated by union-free employees, and as of December 31, 2008, over 93% of 3,779 employees were union-free. We believe our employee relations are good.  There have been no material work stoppages at any of our properties in the past ten years.

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.

 

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 discharge of materials into the environment, surface subsidence from underground mining, and the effects of mining on groundwater and surface water quality and quantities.  These requirements have had, and will continue to have, a significant effect on our production costs and our competitive position.  More stringent future requirements may impose substantial increases in equipment and operating costs on us and delays, interruptions, or a termination of operations, the extent of which cannot be predicted. We intend to respond to any such future requirements at the appropriate time by implementing necessary modifications to facilities or operating procedures. Future requirements, such as those related to greenhouse gas emissions, may also impose substantial cost increases on coal-fired power plants and industrial boilers, thereby reducing the demand for coal. Any such requirements may adversely affect our mining operations, cost structure, revenues, or the ability of our customers to use coal.

Federal and state laws and regulations also address the reclamation and restoration of mining properties after mining has been completed. As of December 31, 2008, we had accrued $98.9 million for reclamation liabilities and mine closures, including $8.4 million of current liabilities.

We strive 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, along with changing interpretations of these requirements, violations occur from time to time. Since our inception in 2002, none of the assessed violations or associated monetary penalties has been material to our operations. Nonetheless, we expect that future liability under or compliance with environmental, health 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 and criminal sanctions, could be imposed for failure to comply with these requirements.

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. Considerable and increasing government attention in the United States and other countries is being paid to reducing greenhouse gas emissions, including emissions from coal-fired power plants. Congress is actively considering legislation to reduce greenhouse gas emissions in the United States, and there are a number of state and regional initiatives underway.  Efforts to reduce greenhouse gas emissions could adversely affect the price and demand for coal.

The United States has not ratified the Kyoto Protocol to the 1992 Framework Convention on Global Climate Change (the “Protocol”), which became effective for many countries in 2005 and establishes a binding set of emission targets for greenhouse gases. However, the United States is actively participating in various international initiatives to reduce greenhouse gas emissions, including negotiations for a new international climate treaty to replace the Protocol. Under the current schedule, the new treaty would be agreed to in late 2009.

In addition to possible future U.S. treaty obligations, regulation of greenhouse gases in the United States could occur pursuant to federal legislation, regulatory changes under the Clean Air Act, state initiatives, or otherwise. At the federal level, Congress is actively considering numerous climate change bills, including bills that would establish nationwide cap-and-trade programs to reduce greenhouse gas emissions. This consideration is expected to continue in 2009 under the new Administration, which as identified climate change legislation as one of its priorities.

To date, the U.S. Environmental Protection Agency (the “USEPA”) has not regulated carbon dioxide emissions.  In 2007, however, the U.S. Supreme Court ruled in Massachusetts v. Environmental Protection Agency that the Clean Air Act gives the USEPA the authority to regulate vehicle tailpipe emissions of greenhouse gases and that the USEPA had not yet articulated a reasonable basis for not issuing such regulation.  A similar lawsuit, currently pending before the U.S. Court of Appeals for the District of Columbia Circuit, challenges the USEPA’s failure in 2006 to regulate carbon dioxide in its new source performance standards covering power plants and industrial boilers.  Consequently, the USEPA may seek to impose emission limitations for carbon dioxide from stationary sources such as power plants.

State and regional climate change initiatives are taking effect before federal action. Ten Northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont) have entered into the Regional Greenhouse Gas Initiative (“RGGI”) Agreement, calling for a ten percent reduction of carbon dioxide emissions by 2018. RGGI has commenced auctioning of carbon dioxide allowances for its first control period of 2009 to 2011. Many other greenhouse gas initiatives, including the Western Regional Climate Action Initiative and recently enacted California legislation, are in various stages of development.

Implementation of these or any other climate change standards or initiatives will likely require additional controls on coal-fired power plants and industrial boilers and may even cause some users of our coal to switch from coal to a lower carbon fuel or more generally reduce the demand for coal-fired electricity generation. This could result in an indeterminate decrease in price and demand for coal nationally.

Mining Permits and Approvals. Numerous governmental permits or approvals are required for mining operations.  The permitting process requires us to present data to federal, state or local authorities pertaining to the effects or impacts that any of our proposed production, processing of coal, or other activities may have upon the environment. The authorization, permitting and/or implementation requirements imposed by the permits or authorizations may be costly, time and resource consuming, and may delay commencement or continuation of our operations. Also, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and/or deny or cause delay in the issuance of additional permits if certain officers, directors or stockholders have violated federal or state mining laws or if any of those people is in a position to control another entity that has outstanding permit violations.

Typically, our necessary permit applications are submitted several months, or even years, before we plan to begin mining a new area. Although some permits or authorizations may take six months or longer to obtain, in the past we have generally obtained our mining permits without significant delay. However, as there have been a growing number of court challenges filed against agency decisions to issue coal mining permits, we cannot be sure that difficulty in obtaining timely permits in the future will not occur.

 

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 that state agency has obtained primacy. States in which we have active mining operations have achieved primacy.

 

 

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SMCRA permit provisions and performance standards include a complex set of requirements which include, but are not limited to the following: reclamation performance bonds; 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; re-vegetation: 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”).

Also, the Abandoned Mine Land Fund, which was created by SMCRA, imposes a fee on all coal produced. In 2008, 2007 and 2006, we recorded expenses of $4.3 million, $5.0 million and $5.0 million, respectively, for this reclamation tax.

Mountaintop Removal (“MTR”) mining is a legal but controversial method of surface mining.  MTR accounted for less than ten percent of our total 2008 coal production. Certain special interest groups have recently waged a public relations assault upon MTR and have encouraged the introduction of legislation at the state and federal level to restrict or ban it. Should changes in laws, regulations or availability of permits severely restrict or ban MTR in the future, our production and associated profitability could be adversely impacted.

 

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. 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. We also have a committed bonding facility with the Chubb Group of Insurance Companies, pursuant to which Chubb has agreed, subject to certain conditions, to issue surety bonds on our behalf in a maximum amount of $50.0 million. We further have a facility with Safeco Insurance Company of America whereby they have agreed, subject to certain conditions, to issue surety bonds on our behalf in a maximum amount of $35.0 million. As of December 31, 2008, we have posted an aggregate of $149.0 million in reclamation bonds and $9.6 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 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 power plants. As many of these regulatory programs are still under development or are subject to judicial challenge, it is not always possible to determine their impact on coal demand nationwide.  In addition to the greenhouse gas issues discussed above, the air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the following:

 

·

Acid Rain. Title IV of the Clean Air Act required a two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and applies to all coal-fired power plants generating greater than 25 Megawatts. Generally, the affected electricity generators have sought to meet these requirements by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances. Because the Acid Rain program is a mature program, we believe that the impact of this regulation has been factored into the demand for coal nationally. Accordingly, we do not believe that the Acid Rain program by itself will continue to impact the demand for coal nationally.

·

Fine Particulate Matter. The Clean Air Act requires the USEPA 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 to 2.5 microns, or PM2.5. The USEPA 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 that are separate and distinct from the reductions that may be required under any other program. 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. The combination of these actions may impact demand for coal nationally, but we are unable to predict the magnitude of the impact.

	·	Ozone. The USEPA’s revised ozone NAAQS became effective May 27, 2008. As a result, significant additional emissions control expenditures may be required at coal-fired power plants to meet the revised ozone NAAQS. Nitrogen oxides, which are a by-product of coal combustion, are classified as an ozone precursor. Accordingly, we expect that there may be additional emissions control requirements necessary on new and expanded coal-fired power plants and industrial boilers in the years ahead.  The combination of these actions may impact demand for coal nationally, but we are unable to predict the magnitude of the impact.
	·	Clean Air Interstate Rule. In 2005, the USEPA issued the Clean Air Interstate Rule (“CAIR”) requiring power plants in 29 eastern states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrogen oxide. The CAIR requires states to regulate power plants under a cap and trade program similar to the system now in effect for acid deposition control. When fully implemented, the CAIR is expected to reduce regional sulfur dioxide emissions by over 70% and nitrogen oxides emissions by over 60% from 2003 levels. The CAIR 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. Following prolonged judicial action, the CAIR is currently in effect, with the USEPA required to initiate further proceedings to modify it.  Such proceedings, which likely will make the CAIR more stringent, are likely to take about two years.  The CAIR may impact demand for coal nationally, but we are unable to predict the magnitude of the impact.

 

·

Regional Haze. The USEPA 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 USEPA program was required to submit to the USEPA a Regional Haze SIP to achieve the goals of the program. Most affected states based their SIPs on the CAIR.  As a result of the ongoing CAIR proceedings, we are unable to predict the magnitude of the impact of the Regional Haze Rule.

 

·

New Source Review. A number of pending regulatory changes and court actions will affect the scope of the USEPA’s new source review program, which under certain circumstances requires existing coal-fired power plants to install the more stringent air emissions control equipment required of new plants.  The changes to the new source review program may impact demand for coal nationally, but as the final form of the requirements after their revision is not known, we are unable to predict the magnitude of the impact.

 

·

State Initiatives. The Clean Air Act generally authorizes states to issue air emissions regulations more stringent than the federal regulations.  In addition to the federal programs, several states have proposed or adopted legislation or regulations limiting air emissions, such as sulfur dioxide, nitrogen oxide, and mercury from coal-fired power plants.

 

 

 

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Clean Water Act. The Clean Water Act and comparable state laws that regulate waste water discharges and certain dredge and fill activities waters of the United States (“Jurisdictional Waters”) may affect coal mining operations both directly and indirectly. The Clean Water Act requirements that may directly or indirectly affect our operations include, but are not limited to, the following:

·

Wastewater Discharges. Section 402 of the Clean Water Act establishes in-stream water quality criteria and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (“NPDES”). Many of our operations are required to obtain NPDES permits, and regular monitoring and compliance with reporting requirements and performance standards are preconditions for the issuance and renewal of NPDES permits. 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.  Any more stringent discharge limits placed on ash handling facilities or other operations at coal-fired power plants also could adversely affect the price and demand for coal.   In 2007, the USEPA filed a lawsuit against another major coal company for alleged exceedances of its Clean Water Act permit limits. Subsequently, each of Alpha’s operating subsidiaries conducted an assessment of its NPDES monitoring and reporting practices, which identified some exceedances of permit limits.  In 2008, each of Alpha’s West Virginia subsidiaries entered into Consent Orders with the West Virginia Department of Environmental Protection on this matter, resulting in their agreement to pay penalties totaling $0.7 million.    The Clean Water Act also empowers states to develop and enforce “in stream” water quality standards, establish total maximum daily load (“TMDL”) limitations for stream segments designated as impaired, and adopt anti-degradation restrictions for high quality waters.  Under each of these programs, our discharges and those of coal-fired power plants could be subject to substantially more stringent discharge limits.  In particular, some of our operations currently discharge effluents into stream segments that have been designated as impaired and 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.

 

·

Dredge and Fill Permits. Certain of our activities involving road building, placement of excess material, and mine development require a Section 404 dredge and fill permit from the Army Corps of Engineers (“COE”) and a Section 401 certification or its equivalent from the state in which the mining activities are proposed.  In recent years, the Section 404 permitting process has faced various challenges, and is subject to ongoing challenges, in the courts.   These challenges have resulted in increased costs and delays in the permitting process. On February 13, 2009, the U.S. Court of Appeals for the fourth circuit issued an industry favorable ruling in the OVEC v Aracoma (Chambers) case.  This ruling affirms the legality of in-stream sediment control structures and should allow the COE to begin clearing up the serious backlog of 404 permits that are currently pending.  Other pending decisions to active challenges or legislative or policy changes could cause additional increases in the costs, time and difficulty associated with obtaining and complying with the permits, and could, as a result, adversely affect our coal production.

      

Endangered Species Act. The federal Endangered Species Act (“ESA”) and counterpart state legislation protect species threatened with possible extinction. A number of species indigenous to the areas in which we operate are protected under the ESA.  Compliance with ESA requirements could 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. However, based on the species that have been identified to date and the current implementation of applicable laws and regulations, we do not believe there are any species protected under the ESA that would materially and adversely affect our ability to obtain permits and 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 species subject to the ESA are protected from mining-related impacts. Should more stringent ESA protective measures be applied, then we could experience increased operating costs or difficulty in obtaining future mining permits.

 

Resource Conservation and Recovery Act (“RCRA”). Currently, certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from RCRA.  However, if mining operations are subjected to RCRA in the future, compliance with RCRA requirements could affect coal mining operations by establishing additional requirements for the treatment, storage, and disposal of wastes generated by coal mining activities.

The USEPA 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 that 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.  It is anticipated that the recent fly ash spill at the Tennessee Valley Authority’s Kingston Power Plant will likely result in increased scrutiny by the USEPA and OSM during this rule-making process.  For example, House Natural Resources Chairman Nick J. Rahall has just recently proposed a bill that would require coal-ash impoundments to be subject to the same standards as coal slurry impoundments under SMCRA.

 

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 liability may be imposed on waste generators, site owners or operators and others regardless of fault. In 2008, USEPA notified us that we might be a de minimis contributor to a Superfund site. In addition, although unlikely due to the stringent nature of the current SMCRA regulations, mining operations may have reporting obligations under the Emergency Planning and Community Right to Know Act and the Superfund Amendments and Reauthorization Act.  

 

 

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Davis-Bacon Act.  The State of West Virginia adopted in major part the Davis-Bacon Act of 1931.  Due to our road construction business with the State of West Virginia, we may be required to pay wages that comply with the Davis-Bacon Act.  Generally, the Davis-Bacon Act stipulates that every contract in excess of $2,000, to which any U.S. state or the District of Columbia is a party, for construction, alteration, and/or repair, including painting and decorating, of public buildings or public works of any U.S. state or the District of Columbia within the geographical limits of any U.S. state or the District of Columbia, and which requires or involves the employment of mechanics and/or laborers shall contain a provision stating the minimum wages to be paid various classes of laborers and mechanics which shall be based upon the wages that will be determined by the Secretary of Labor to be prevailing for the corresponding classes of laborers and mechanics employed on projects of a character similar to the contract work in the city, town, village, or other civil subdivision of the state in which the work is to be performed.

In December 2004, prior to our Nicewonder Acquisition in October 2005, the Affiliated Construction Trades Foundation brought an action against the West Virginia Department of Transportation, Division of Highways (“WVDOH”) and Nicewonder Contracting, Inc. ("NCI"), which became our wholly-owned indirect subsidiary after the Nicewonder Acquisition, in the United States District Court in the Southern District of West Virginia. The plaintiff sought a declaration that the contract between NCI and the State of West Virginia related to NCI's road construction project was illegal as a violation of applicable West Virginia and federal competitive bidding and prevailing wage laws. The plaintiff also sought an injunction prohibiting performance of the contract but has not sought monetary damages.

On September 5, 2007, the Court ruled that the WVDOH and the Federal Highway Administration (who is now a party to the suit) could not, under the circumstances of this case, enter into a contract not requiring the contractor to pay the prevailing wages as required by the Davis-Bacon Act. Although the Court has not yet decided what remedy it will impose, we expect a ruling before the end of the first quarter of 2010.  We anticipate that the most likely remedy is a directive that the contract be renegotiated for such payment. If that renegotiation occurs, the WVDOH has committed to agree and NCI has a contractual right to insist, that additional costs resulting from the order will be reimbursed by the WVDOH and as such neither NCI nor the Company believe, at this time, that they have any monetary expense from this ruling. As of December 31, 2008, the Company recorded a $7.9 million long-term receivable for the recovery of these costs from the WVDOH and a $7.9 million long-term liability for the obligations under the ruling.

 

 

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Item 1A.

Risk Factors

 

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 58% and 62% of our coal sales volume during 2008 and 2007, respectively. The majority of our sales of steam coal for 2008 and 2007 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 42% and 38% of our coal sales volume during 2008 and 2007, respectively.  Any deterioration in conditions in the U.S. steel industry would reduce the demand for our metallurgical coal and could impact the collectability 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. 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.

 

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

     

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

·

the supply of and demand for domestic and foreign coal;

·

the demand for electricity;

·

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

·

interruptions due to transportation delays;

·

domestic and foreign governmental regulations and taxes;

·

air emission standards for coal-fired power plants;

·

regulatory, administrative, and judicial decisions;

·

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

·

the effect of worldwide energy conservation measures; and

·

the proximity to, capacity of, and cost of transportation and port facilities.

During 2008, the market for coal experienced considerable price volatility. Although there was an overall increase in the average sales price of our coal in 2008, in the fourth quarter of 2008, the average realized price per ton decreased from the peak price level that had been reached in the third quarter of 2008. In addition, global demand for coal declined significantly in the fourth quarter of 2008.

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.

Ongoing instability and volatility in the worldwide financial markets have created uncertainty, which could adversely affect our business and the price of our common shares.

As widely reported, financial markets in the United States, Europe and Asia have been experiencing extreme disruption in recent months, including, among other things, extreme volatility in security prices, severely diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others, including real estate. The current tightening of credit in financial markets could adversely affect our customers’ ability to obtain financing for operations and could result in a decrease in the demand, the cancellation of orders for our coal products, or the restructuring of agreements with our coal customers. In particular, steel producers in several countries have recently announced price and production cuts. Continuation or worsening of the current economic conditions, a prolonged global, national or regional economic recession or other similar events could have a material adverse effect on the demand for coal and on our sales, margins, and profitability. During this recent period of intense market disruption, the market price for our common shares has declined substantially.  We continue to monitor economic developments and the resulting impact on our business and other suppliers and customers closely.  However, we are unable to predict the likely duration and severity of the current disruption in financial markets and adverse economic conditions in the U.S. and other countries and the impact these events may have on our operations and the industry in general.

 

 

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

     

Our operations and those of our customers are subject to extensive environmental laws and regulations relating to air quality standards, water pollution, plant and wildlife protection, the discharge of materials into the environment, surface subsidence from underground mining, the effects of mining on groundwater and surface water quality and quantities, and permitting of operations.  These requirements are a significant part of the costs of our respective businesses, and our costs relating to environmental matters are increasing as environmental requirements become more stringent.

In particular, the Clean Air Act and similar state and local laws and regulations limit 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.  A series of more stringent requirements are expected to become effective in coming years.

One major by-product of burning coal is carbon dioxide, which is a greenhouse gas and is a major source of concern with respect to global warming. Future regulation of greenhouse gases in the United States could occur pursuant to potential U.S. treaty obligations, such as the projected new treaty to replace the Kyoto Protocol, and new legislation that may establish a carbon tax or cap-and-trade program. State and regional climate change initiatives, such as the Regional Greenhouse Gas Initiative of eastern states, the Western Regional Climate Action Initiative, and recently enacted California legislation, may take effect before federal action.

Considerable uncertainty is associated with these air emissions initiatives. The content of new treaties or legislation is not yet determined and many of the new regulatory initiatives remain subject to review by the agencies or the courts. Predicting the economic effects of climate change legislation is difficult given the various alternatives proposed and the complexities of the interactions between economic and environmental issues.  Any more stringent air emissions requirements, however, are likely to impose significant emissions control expenditures on many coal-fired power plants and industrial boilers and could have the effect of making them unprofitable. As a result, these generators may switch to other fuels that generate less of these emissions, possibly reducing future demand for coal and the construction of coal-fired power plants. Any switching of fuel sources away from coal, closure of existing coal-fired plants, or reduced construction of new plants could have a material effect on demand for and prices received for our 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 to comply with applicable ambient air quality standards.  In the future, there may be fuel switching away from coal.

Also, see Item 1, “Environmental and Other Regulatory Matters” for a discussion of environmental issues potentially affecting our operations.

The government also extensively regulates other aspects of 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.

     

In addition to environmental requirements, 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, and other mine permitting and licensing requirements.

    

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 laws, regulations or 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 mine accidents during 2005 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.

During 2008, MSHA continued its regulatory proceedings to implement the MINER Act. Various states also have enacted their own new laws and regulations addressing many of these same subjects.  In 2007, the State of West Virginia, for example, enacted legislation that imposes additional burdens on coal operators, including, among other things, a) the prohibition of the use of belt air unless approval is obtained; b) imposing additional design requirements for seals; c) mandating education and certification programs for miners; and d) continuing its advance for the imposition of additional technological improvements recommended by a task force. Our compliance with these or any new mine health and safety laws and regulations could increase our mining costs and could have a material adverse effect on our financial condition and results of operations.

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

     

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

·

enactment of new environmental or health and safety laws or regulations or changes in interpretations of current requirements;

·

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

·

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

·

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

·

mining and processing equipment failures and unexpected maintenance problems;

·

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

·

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

·

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

·

accidental mine water discharges;

·

the unavailability of qualified labor;

·

strikes and other labor-related interruptions; and

·

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

 

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 or for varying lengths of time, which could adversely affect our operating results and could result in impairments to our assets.

 

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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.

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. 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.  This competition could result in a decrease in our market share in this region and a decrease in our revenues.

 

Demand for our low sulfur coal and the prices that we can obtain for it are also affected by, among other things, the price of emissions allowances. Decreases in the prices of these emissions allowances could make low sulfur coal less attractive to our customers. In addition, more widespread installation by electric utilities of technology that reduces sulfur emissions (which could be accelerated by increases in the prices of emissions allowances), may make high sulfur coal more competitive with our low sulfur coal. This competition could adversely affect our business and results of operations.

We also compete in international markets against coal produced in other countries. Measured by tons sold, exports accounted for approximately 31% of our sales in 2008. 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.

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 periodically reviewed by third-party consultants. There are numerous uncertainties inherent in estimating the quantities and qualities of, and costs to mine, recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:

·

future mining technology improvements;

·

the effects of governmental regulations;

·

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; and

·

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

Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

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.

 

Our work force could become increasingly unionized in the future and our unionized or union-free hourly work force could strike, which could adversely affect the stability of our production and reduce our profitability.

          

Approximately 96% of our 2008 coal production came from mines operated by union-free employees. As of December 31, 2008, over 93% of our 3,779 employees are union-free. However, our subsidiaries' employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. Any further unionization of our subsidiaries' employees, or the employees of third-party contractors who mine coal for us, could adversely affect the stability of our production and reduce our profitability.

One of our Virginia subsidiaries has two contracts with the United Mine Workers of America (“UMWA”) that cover approximately 248 employees.  One of our West Virginia subsidiaries has a Bituminous Coal Operators Association (“BCOA”) contract with the UMWA covering approximately 17 UMWA employees.  Also, the other West Virginia subsidiary, which is idle, has a BCOA 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 affected at this time. However, if the operation becomes active again, these employees could be affected.

 

 

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As is the case with our union-free operations, the UMWA represented employees could strike, which would disrupt our production, increase our costs, and disrupt shipments of coal to our customers, which could reduce our profitability.

A shortage of skilled labor in the Appalachian region could pose a risk to achieving improved labor productivity and competitive costs and could adversely affect our profitability.

     

Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least a year of experience and proficiency in multiple mining tasks. In recent years, a shortage of trained coal miners in the Appalachian region has caused us to operate certain units without full staff, which decreases our productivity and increases our costs. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our profitability.

 

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.

     

We continually seek to expand our operations and coal reserves through acquisitions. In the past five years, we have completed six significant acquisitions and several smaller acquisitions and investments.  Our ability to complete acquisitions is subject to availability of attractive targets on terms acceptable to us and general market conditions, among other things.  If we are unable to successfully integrate the companies, businesses or properties that we acquire, our profitability may decline and we could experience a material adverse effect on our business, financial condition or results of operations. Acquisition transactions involve various inherent risks, including:

·

uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental or mine safety liabilities) of, acquisition candidates;

·

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

·

the ability to achieve identified operating and financial synergies from an acquisition in the amounts and on the timeframe;

·

problems that could arise from the integration of the acquired business, including the application of our internal control processes to the acquired business; and

·

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

 

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

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 in October 2005, 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. In addition, 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.  Future acquisitions could also result in our assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous acquisitions.

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.   During 2008, approximately 80% and 64% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts. At December 31, 2008, our long-term coal supply agreements had remaining terms of up to eight 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. For additional information relating to our long-term coal supply contracts, see “Business -- Marketing, Sales and Customer Contracts.”

As of January 16, 2009, approximately 11% and 62%, respectively, of our planned production for 2009 and 2010 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.

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.

 

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.

As a result of the economic slowdown that has resulted in deep cuts in worldwide steel production and the application of such price adjustment and other similar provisions in our long-term supply contracts, we had to restructure certain agreements under mutually acceptable terms with our steel customers in late 2008. A continuation or decline in the current economic conditions would likely result in an increase in the number of restructured agreements.

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.

 

 

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

Our largest customer during 2008 accounted for approximately 12% of our total revenues. We derived approximately 54% of our 2008 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 reduce their purchases of coal from us significantly 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.

 

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 results may be negatively impacted.  Lower than expected sales by us during this period could have an adverse affect on the timing of our cash flows and therefore our ability to service our obligations with respect to our existing and future indebtedness.

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 the fourth quarter of 2008, steel production worldwide decreased 24% resulting in a decrease in the demand for metallurgical coal. Any further deterioration in conditions in the U.S. steel industry could further reduce the demand for our metallurgical coal.  Furthermore, 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 all the production from these mines had to be sold as steam coal, theses mines may not be economically viable and subject to closure. Such closures would lead to asset impairment charges, accelerated reclamation costs, as well as reduced revenue and profitability.

  

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 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 4.9 million tons of coal purchased from third parties during 2008, representing approximately 17% of our total sales during 2008. We believe that approximately 65% of our purchased coal sales in 2008 were blended with coal produced from our mines prior to resale, and approximately 5% of our total sales in 2008 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.

  

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, such as diesel fuel. 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 not have a ready substitute for these commodities.

 

Fair value of derivative instruments 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 Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”).  SFAS 133 requires all derivative financial instruments to be reported on the balance sheet at fair value. Changes in fair value are recognized either in earnings or equity, depending on whether the transaction qualifies for hedge accounting, and if so, the nature of the underlying exposure that is being hedged and how effective the derivatives are at offsetting price movements in the underlying exposure.

 

Certain of our forward coal purchase and sales contracts that are considered derivative instruments do not qualify under the “normal purchase and normal sales” exception under SFAS 133. Transactions that do not qualify for this exception are required to be marked to market and currently do not qualify for hedge accounting. Accordingly, changes in fair value for these forward sales and forward purchase contracts have been recorded in the income statement and are reflected in (increase) decrease in fair value of derivatives instruments, net.  During 2008, we had a net decrease in the fair value of these derivative instruments of $9.3 million consisting of a decrease in fair value of forward purchase coal contracts in the amount of $14.3 million, partially offset by an increase in fair value of forward sale coal contracts of $5.0 million.

 

We use significant quantities of diesel fuel in our operations and are also exposed to risk in the market price for diesel fuel. We have entered into swap agreements and diesel fuel put options to reduce the volatility in the price of diesel fuel for our operations.  These diesel fuel swap agreements and put options are not designated as a hedge for accounting purposes and therefore the changes in the fair value for these derivative instrument contracts are required to be marked to market and recorded in cost of sales, which may also result in earnings volatility. During 2008, we entered into diesel fuel swaps and put options each for approximately 15.6 million gallons or 50% of the Company's anticipated 2009 diesel fuel usage.  These diesel fuel swaps and put options use the NYMEX New York Harbor #2 heating oil as the underlying commodity reference price.  During 2008, we had a net decrease of $38.0 million in the fair value of these diesel fuel derivative instruments consisting of a decrease of $38.0 million in the fair value of swap agreements, an increase in the fair value of purchased put options of $3.9 million, and a decrease in the fair value of sold put options of 3.9 million. 

 

 

 

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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 in recent years 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.  For example, certain shipments of our coal to customers were delayed by hurricanes in the Gulf Coast in 2005.  Decreased performance levels over longer periods of time could cause our customers to look to other sources for their coal needs, negatively affecting our revenues and profitability.

 

In 2008, 58% 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 future 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.  In addition, our coal is transported from our mines to our loading facilities by trucks owned and operated by third parties.  The states of West Virginia and Kentucky enforce weight limits on coal trucks on their public roads. It is possible that other states in which our coal is transported by our contract carriers 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 our revenues and earnings.

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. 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.

Furthermore, global financial markets have been experiencing extreme disruption in recent months, including, among other things, severely diminished liquidity and credit availability.  We continue to monitor these developments and the resulting impact on our business and our suppliers and customers closely. A continuation or worsening of the current economic conditions, a prolonged global, national or regional economic recession or other similar events, is likely to significantly impact the creditworthiness of our customers and could increase the risk we bear on payment default.

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, 2008, we owned or leased 599.7 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 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 conditions 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 impractical, possibly precluding the continuance of ongoing operations or the development of future mining operations. The public, including special interest groups and individuals, have certain rights under various statutes to comment upon, submit objections to, and otherwise engage in the permitting process, including bringing citizens’ lawsuits to challenge such permits or mining activities.  Accordingly, required permits may not be issued or renewed in a timely fashion (or at all), or permits issued or renewed may be conditioned in a manner that may restrict our ability to efficiently conduct our mining activities.  Such inefficiencies would likely reduce our production, cash flow, and profitability.

In particular, certain of our activities involving valley fills, ponds or impoundments, road building, placement of excess material, and other mine development activities require a Section 404 dredge and fill permit from the Army Corps of Engineers (“COE”) and a Section 401 certification or its equivalent from the state in which the mining activities are proposed.  In recent years, the Section 404 permitting process has faced a series of court challenges that have resulted in increased costs and delays in the permitting process.  Future challenges or changes to the permitting process could cause additional increases in the costs, time, and difficulty associated with obtaining and complying with the permits, and could, as a result, adversely affect our coal production.

 

 

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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. 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.

In addition, due to the current instability and volatility of the financial markets, our current surety bond providers may experience difficulties in providing new surety bonds to us, maintaining existing surety bonds, or satisfying liquidity requirements under existing surety bond contracts.  In that event, we would be required to find alternative sources of funding to satisfy our payment obligations, which may require greater use of our credit facility.

 

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 (“SMCRA”) establishes operational, reclamation and closure standards for all aspects of surface mining as well as deep mining. We accrue for the costs of current mine disturbance and 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.

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 from time to time we generate limited quantities of hazardous wastes. Our Predecessor and acquired companies also utilized certain hazardous materials and generated similar wastes. We may be subject to claims under federal or state statutes 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, sediments, groundwater, and other natural resources. Such claims may arise 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 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, causing extensive damage to the environment and natural resources, as well as liability for related personal injuries and property damages. 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. The recent failure of the fly ash impoundment at the Tennessee Valley Authority’s Kingston Power Plant, which is not regulated in the same manner as our slurry impoundments, could result in additional scrutiny of our impoundments.

These and other unforeseen environmental impacts that our operations may have, 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 our business.

Also, see Item 1, “Environmental and Other Regulatory Matters” for discussion related to “Superfund,” and “RCRA.”

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 actual or alleged 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 on that property, which could adversely affect our profitability.

     

 

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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.

When we acquired the assets of our Predecessor and acquired companies, those 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, 2008, included $61.3 million of postretirement medical obligations and $11.3 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 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. The inability of the sellers of our Predecessor and acquired companies to fulfill their indemnification obligations to us under our acquisition agreements could increase our liabilities and adversely affect our results of operations. Moreover, under certain acquisition agreements, we agreed to permit responsibility for black lung claims related to the sellers' former employees who are employed by us for less than one year after the acquisition to be determined in accordance with law (rather than specifically assigned to one party or the other in the agreements). We believe that the sellers remain liable as a matter of law for black lung benefits for their former employees who work for us for less than one year; however, an adverse ruling on this issue could increase our exposure to black lung benefit liabilities.

 

Our significant 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, 2008, we had $539.1 million of indebtedness outstanding, representing 43% of our total capitalization. This indebtedness consisted of $287.5 million principal of our convertible senior notes, a $233.1 million term loan under our current credit facility and $18.5 million of other indebtedness, including $0.2 million of capital lease obligations extending through March 2009, and $18.3 million payable to an insurance premium finance company. In addition, under our current credit facility, we had $82.6 million of letters of credit outstanding at December 31, 2008.

 

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

·

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;

·

increase our vulnerability to general adverse economic and industry conditions and limit our flexibility in planning for, or reacting to, changes in our business and in the coal industry;

·

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; and

·

place us at a competitive disadvantage compared to less leveraged competitors.

     

If our cash flows and capital resources are insufficient to fund our debt service obligations or our requirements under our other long-term liabilities, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations or our requirements under our other long term liabilities. In the absence of sufficient cash flows 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 current credit facility restricts our ability to sell assets and use the proceeds from the sales. We may not be able to consummate any such 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.

 

We may also be able to incur substantially more debt which could further exacerbate the risks associated with our significant indebtedness.

We may be able to incur substantial additional indebtedness in the future under the terms of our credit facility. Our current credit facility provides for a revolving line of credit of up to $375.0 million, of which $292.4 million was available as of December 31, 2008. 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.

 

 

 

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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, 2008, we had $82.6 million of letters of credit in place, of which $73.0 million served as collateral for reclamation surety bonds and $9.6 million secured miscellaneous obligations. Our credit facility provides for revolving commitments of up to $375.0 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.

 

The terms of our credit facility limit our and our subsidiaries’ ability to take certain actions, which may adversely affect our business.

     

Our credit facility contains a number of significant restrictions and covenants that limit our ability and our subsidiaries' ability to, among other things, incur additional indebtedness, 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 this agreement would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able to 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.

 

Certain terms of our convertible notes may adversely impact our liquidity.

Upon conversion of our convertible notes, we will be required to pay in cash the lesser of the principal amount of the converted notes and the sum of a calculated daily conversion value over an averaging period. As a result, the conversion of the convertible notes may significantly reduce our liquidity.

Sales of additional shares of our common stock, the exercise or granting of additional stock options or conversion of our convertible notes could cause the price of our common stock to decline.

Sales of substantial amounts of our common stock in the open market and the availability of those shares for sale could adversely affect the price of our common stock. In addition, future issuances of equity securities, including pursuant to outstanding options or the conversion of our convertible bonds, could dilute the interests of our existing stockholders and could cause the market price for our common stock to decline. We may issue equity securities in the future for a number of reasons, including to finance our operations and business strategy, to adjust our ratio of debt to equity, to satisfy our obligations upon the exercise of outstanding warrants or options or for other reasons.

As of December 31, 2008, there were:

·

519,984 shares of common stock issuable upon the exercise of stock options with a weighted-average exercise price of 17.87;

·

17,056 restricted share units issued to directors to be converted to common stock upon separation of service;

·

35,492 shares to be issued to recipients of performance share awards (based on actual results) at the end of a performance period which ended on December 31, 2008;

·

292,551 shares to be issued to recipients of performance share awards (assuming performance at a target level) at the end of a performance period which ends on December 31, 2009; and

·

122,657 shares to be issued to recipients of performance share awards (assuming performance at a target level) at the end of a performance period which ends on December 31, 2010.

The price of our common stock could also be affected by hedging or arbitrage trading activity that may exist or develop involving our common stock and our convertible notes.

 

 

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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 and Progress 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.

Our inability to continue or expand the Nicewonder existing road construction and coal recovery business could adversely affect the expected benefits from the Nicewonder acquisition.

     

Our subsidiary, Nicewonder Contracting, Inc. (“NCI”), operates a road construction business under a contract with the State of West Virginia. Pursuant to the contract, NCI is building approximately 11 miles of rough grade highway in West Virginia over the next one to two years and, in exchange, NCI will be compensated by West Virginia based on the number of cubic yards of material excavated 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.

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 one to two years, we are uncertain whether the state will fund any similar projects in the future.

The Affiliated Construction Trades Foundation brought an action against the West Virginia Department of Transportation, Division of Highways (“WVDOH”) and NCI in the United States District Court in the Southern District of West Virginia. The plaintiff sought a declaration that the contract between NCI and the State of West Virginia related to NCI's road construction project was illegal as a violation of applicable West Virginia and federal competitive bidding and prevailing wage laws. The plaintiff also sought an injunction prohibiting performance of the contract but has not sought monetary damages.

On September 5, 2007, the Court ruled that the WVDOH and the Federal Highway Administration (who is now a party to the suit) could not, under the circumstances of this case, enter into a contract not requiring the contractor to pay the prevailing wages as required by the Davis-Bacon Act.  Although the Court has not yet decided what remedy it will impose, regarding the prevailing wage issue, we expect a ruling before the end of the first quarter of 2010.  We anticipate that the most likely remedy would be a directive that the contract be renegotiated for such payment. If that renegotiation occurs, the WVDOH has contractually committed to agree and NCI has a contractual right to insist, that such additional costs resulting from such an order will be reimbursed by the WVDOH.  Accordingly, we do not believe that we will have any monetary expense as a result of this ruling. As of December 31, 2008, the Company recorded a $7.9 million long-term receivable for the recovery of these costs from the WVDOH and a $7.9 million long-term liability for the obligations under the ruling.

If the plaintiff is successful, in its challenge, the resulting judgment could make completing the remainder of the road construction project considerably less advantageous to NCI or restrict or prohibit NCI from completing the project, which could adversely affect our results.

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

 

A large percentage of our road construction revenues and contract backlog is 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.  Also, if we do not recover the amounts of coal estimated on our construction projects, profitability on our construction contracts could be less than projected. 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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Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations.

     

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition, and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may materially adversely affect our operations and those of our customers. As a result, there could be delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

 

Provisions in our certificate of incorporation and bylaws and the indenture for our convertible notes may discourage a takeover attempt even if doing so might be beneficial to our stockholders.

Provisions contained in our certificate of incorporation and bylaws could impose impediments to the ability of a third party to acquire us even if a change of control would be beneficial to our stockholders. Provisions of our certificate of incorporation and bylaws impose various procedural and other requirements, which could make it more difficult for stockholders to effect certain corporate actions. For example, our certificate of incorporation authorizes our board of directors to determine the rights, preferences, privileges and restrictions of unissued series of preferred stock, without any vote or action by our stockholders. Thus, our board of directors can authorize and issue shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of our common stock. These provisions may have the effect of delaying or deterring a change of control of our Company, and could limit the price that certain investors might be willing to pay in the future for shares of our common stock.

If a “fundamental change” (as defined in the indenture for our convertible notes) occurs, holders of the convertible notes will have the right, at their option, either to convert their convertible notes or require us to repurchase all or a portion of their convertible notes. In the event of a “make-whole fundamental change” (as defined in the indenture for the convertible notes), we also may be required to increase the conversion rate applicable to any convertible notes surrendered for conversion. In addition, the indenture for the convertible notes prohibits us from engaging in certain mergers or acquisitions unless, among other things, the surviving entity is a U.S. entity that assumes our obligations under the convertible notes. Our credit facility imposes similar restrictions on us, including with respect to mergers or consolidations with other companies and the sale of substantially all of our assets. These provisions could prevent or deter a third party from acquiring us even where the acquisition could be beneficial to our stockholders.

We do not intend to pay cash dividends on our common stock in the foreseeable future.

We have never declared or paid a cash dividend, and we currently do not anticipate paying any cash dividends in the foreseeable future.  If we were to decide in the future to pay dividends, our ability to do so would be dependent on the ability of our subsidiaries to make cash available to us, by dividend, debt repayment or otherwise.  The ability of our subsidiaries to make cash available to us is limited by restrictions in our credit facility.

 

 

Item 1B.

Unresolved Staff Comments

None.

 

 

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Item 2.

Properties

 

Coal Reserves

     

We estimate that, as of December 31, 2008, we owned or leased total proven and probable coal reserves of approximately 599.7 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 the reserved area lies within 1,320 feet of a reliable data point. Probable reserves are those for which the reserved area lies between 1,320 feet and 3,960 feet from a reliable data point. 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.  Prior to our initial public offering, we retained a third party consultant to perform reserve estimates in November 2004.  We have also retained a consultant to verify reserves for all the major acquisitions since November 2004, which include the Callaway, Progress Fuels, and Mingo Logan Ben’s Creek Complex acquisitions.  These reviews include 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. Circular 891.  Reserve estimates were developed using criteria to assure that the basic geologic characteristics of the reserve (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 operation capabilities on our properties.

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. Of our reserve holdings, 1.4% 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 $4.04 per ton in 2008, representing 4.0% of our 2008 coal revenue.

 

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

 

 

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The following table provides the “quality” (sulfur content and average Btu content per pound) of our coal reserves as of December 31, 2008.

 

			Recoverable Reserves Proven & Probable (1)		Sulfur Content						Average BTU
Regional Business Unit	State				<1%		1.0%-1.5%		>1.5%		>12,500		<12,500
Paramont/Alpha Land and Reserves (2)	Virginia		188.0		140.7		38.5		8.8		178.0		10.0
Dickenson-Russell	Virginia		41.3		41.3		0.0		0.0		41.3		0.0
Kingwood (3)	West Virginia		12.3		0.0		1.0		11.3		12.3		0.0
Brooks Run North	West Virginia		40.6		18.7		21.9		0.0		33.2		7.4
Brooks Run South (4)	West Virginia		85.2		83.7		1.5		0.0		85.2		0.0
AMFIRE	Pennsylvania		69.4		9.5		31.5		28.4		45.6		23.8
Enterprise/Enterprise Land & Reserve, Inc (5)	Kentucky		142.7		44.9		47.0		50.8		121.3		21.4
Callaway/Cobra (6)	West Virginia and Virginia		20.2		20.2		0.0		0.0		12.7		7.5
Totals			599.7		359.0		141.4		99.3		529.6		70.1
Percentages					60	%	23	%	17	%	88	%	12	%

	(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 approximately 6.5%. This moisture factor represents the average moisture present on our delivered coal, which varies depending on rank of coal and processing requirements.
	(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	)	On December 3, 2008, we announced the permanent closure of Kingwood and the mine stopped producing coal in early January 2009.  Unmineable reserves were written off at December 31, 2008.
	(4	)	Includes proven and probable reserve in West Virginia controlled by our subsidiaries Brooks Run South and Riverside Mining Company.
	(5	)	Includes proven and probable reserves in Kentucky controlled by our subsidiary Enterprise Land & Reserve Inc obtained from the Progress Energy acquisition.
	(6	)	Includes proven and probable reserves controlled in West Virginia by Cobra Natural Resource obtained from the Mingo Logan Ben’s Creek Complex 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, 2008.

 

			Recoverable Reserves Proven & Probable (1)		Total Tons						Total Tons
Regional Business Unit	State				Assigned (2)			Unassigned (2)			Owned			Leased		Coal Type (3)
			(In millions of tons)
Paramont/Alpha Land and Reserves (4)	Virginia		188.0		59.9			128.1			0.0			188.0		Steam and Metallurgical
Dickenson-Russell	Virginia		41.3		41.1			0.2			0.0			41.3		Steam and Metallurgical
Kingwood (5)	West Virginia		12.3		1.0			11.3			0.0			12.3		Steam and Metallurgical
Brooks Run North	West Virginia		40.6		24.0			16.6			2.3			38.3		Steam and Metallurgical
Brooks Run South (6)	West Virginia		85.2		38.4			46.8			1.0			84.2		Steam and Metallurgical
AMFIRE	Pennsylvania		69.4		50.0			19.4			3.5			65.9		Steam and Metallurgical
Enterprise/Enterprise Land & Reserve, Inc (7)	Kentucky		142.7		64.3			78.4			1.7			141.0		Steam
Callaway/Cobra (8)	West Virginia and Virginia		20.2		16.3			3.9			0.0			20.2		Steam and Metallurgical
Totals			599.7		295.0			304.7			8.5			591.2
Percentages					49	%		51	%		1	%		99	%

(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 approximately 6.5%. This moisture factor represents the average moisture present on our delivered coal, which varies depending on rank of coal and processing requirements.

             

(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	)	On December 3, 2008, we announced the permanent closure of Kingwood, and the mine stopped producing coal in early January 2009.  Unmineable reserves were written off at December 31, 2008.
	(6	)	Includes proven and probable reserve in West Virginia controlled by our subsidiaries Brooks Run South and Riverside Mining Company
	(7	)	Includes proven and probable reserves in Kentucky controlled by our subsidiary Enterprise Land & Reserve Inc obtained from the Progress Energy acquisition.
	(8	)	Includes proven and probable reserves controlled by Cobra Natural Resource obtained from the Mingo Logan Ben’s Creek Complex acquisition.

           

 

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The following map shows the locations of Alpha's properties as of December 31, 2008 for each of our eight regional business units:

 

           See Item 1, “Business”, for additional information regarding our coal operations and properties.

 

 

 

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Item 3.

Legal Proceedings

      

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.

Nicewonder Litigation

In December 2004, prior to our Nicewonder Acquisition in October 2005, the Affiliated Construction Trades Foundation brought an action against the WVDOH and NCI, which became our wholly-owned indirect subsidiary as a result of the Nicewonder Acquisition, in the United States District Court in the Southern District of West Virginia. The plaintiff sought a declaration that the contract between NCI and the State of West Virginia related to NCI's road construction project was illegal as a violation of applicable West Virginia and federal competitive bidding and prevailing wage laws. The plaintiff also sought an injunction prohibiting performance of the contract but has not sought monetary damages. 

On September 5, 2007, the Court ruled that the WVDOH and the Federal Highway Administration (which is now a party to the suit) could not, under the circumstances of this case, enter into a contract that did not require the contractor to pay the prevailing wages as required by the Davis-Bacon Act. Although the Court has not yet decided what remedy it will impose, we expect a ruling before the end of the first quarter of 2010.  We anticipate that the most likely remedy is a directive that the contract be renegotiated for such payment. If that renegotiation occurs, the WVDOH has committed to agree, and NCI has a contractual right to insist, that additional costs resulting from the order will be reimbursed by the WVDOH.  Accordingly, we do not believe that we will incur any monetary expense as a result of this ruling. As of December 31, 2008, we have a $7.9 million long-term receivable for the recovery of these costs from the WVDOH and a $7.9 million long-term liability for the potential obligations under the ruling.

Cliffs Proposed Acquisition

On July 15, 2008, we entered into a definitive merger agreement pursuant to which, and subject to the terms and conditions thereof, Cliffs would acquire all of our outstanding shares.  Under the terms of the agreement, for each share of our common stock, stockholders would receive 0.95 Cliffs' common shares and $22.23 in cash.  The proposed merger required approval of each company’s stockholders, for which special meetings were scheduled to take place on November 21, 2008.  On November 3, 2008, we commenced litigation against Cliffs by filing an action in the Delaware Court of Chancery to obtain an order to require Cliffs to hold its meeting as scheduled.  Later in November, each company’s Board of Directors, after considering various issues, including the then current macroeconomic environment, uncertainty in the steel industry, shareholder dynamics and risks and costs of potential litigation, determined that settlement of the litigation and termination of the merger agreement was in the best interests of its equity holders.  As a result, on November 17, 2008, we and Cliffs mutually terminated the merger agreement and settled the litigation.  The terms of the settlement agreement included a $70.0 million payment from Cliffs to us which, net of transaction costs, resulted in a gain of $56.3 million.

Item 4.

Submission of Matters to a Vote of Security Holders

     

There were no matters submitted to a vote of security holders through a solicitation of proxies or otherwise during the fourth quarter ended December 31, 2008.

 

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PART II

 

Item 5.

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

     

The initial public offering of our common stock occurred 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.

 

2008		High			Low
First Quarter		$	43.48		$	24.11
Second Quarter			104.29			41.29
Third Quarter			104.93			43.41
Fourth Quarter			47.69			14.68
2007		High			Low
First Quarter		$	15.66		$	12.45
Second Quarter			20.79			15.61
Third Quarter			23.23			16.52
Fourth Quarter			33.84			23.68

As of December 31, 2008, there were approximately 2,437 registered holders of record of our common stock, including 210 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, and we currently do not anticipate paying any dividends in the foreseeable future.

  

 

 

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Stock Performance Graph

The following stock performance graph compares the cumulative total return to stockholders on a quarterly basis on our common stock with the cumulative total return to stockholders on a quarterly basis on two indices, the Russell 3000 Index and the Russell 3000 Coal Index. The graph assumes that:

·

you invested $100 in our common stock and in each index at the closing price on February 15, 2005;

·

all dividends were reinvested; and

·

you continued to hold your investment through December 31, 2008.

You are cautioned against drawing any conclusions from the data contained in this graph, as past results are not necessarily indicative of future performance.  The indices used are included for comparative purposes only and do not indicate an opinion of management that such indices are necessarily an appropriate measure of the relative performance of our stock.

 

 

Company Name		2/15/2005	Mar-05	Jun-05	Sep-05	Dec-05	Mar-06	Jun-06	Sep-06	Dec-06	Mar-07	Jun-07	Sep-07	Dec-07	Mar-08	Jun-08	Sep-08	Dec-08
ANR		100.00	126.36	105.25	132.40	84.66	101.99	86.47	69.46	62.71	68.88	91.63	102.38	143.15	191.45	459.63	226.66	71.35
Russell 3000		100.00	97.93	100.13	104.15	106.29	111.98	109.79	114.88	123.08	124.68	131.89	133.92	129.46	117.15	115.20	105.16	81.21
Russell 3000 Coal		100.00	107.24	118.35	171.33	159.53	177.61	199.53	132.57	140.33	148.87	176.40	172.69	240.01	222.73	413.76	184.22	88.53

 

 

 

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Item 6.

Selected Financial Data

The following table presents selected financial and other data about us for the most recent five fiscal periods. The selected financial data as of December 31, 2008, 2007, 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, which are 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.

		Alpha Natural Resources, Inc and Subsidiaries																ANR FUND IX Holdings, L.P. and Alpha NR Holding, Inc. and Subsidiaries
		Year Ended December 31, 2008				Year Ended December 31, 2007				Year Ended December 31, 2006				Year Ended December 31, 2005				Year Ended December 31, 2004
		(In thousands, except per share and per ton amount)
Statement of Operations Data:
Revenues:
Coal revenues		$	2,219,291			$	1,647,505	*		$	1,681,434	*		$	1,413,174			$	1,079,981
Freight and handling revenues			279,853				205,086				188,366				185,555				141,100
Other revenues			54,980				33,241	**			34,743				27,926				28,347
Total revenues			2,554,124				1,885,832				1,904,543				1,626,655				1,249,428
Costs and expenses:
Cost of coal sales (exclusive of items shown seperately below)			1,729,281				1,371,519	*			1,346,733	*			1,184,092				920,359
Gain on sale of coal reserve			(12,936	)			-				-				-				-
(Increase) decrease in fair value of derivative instruments, net