UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

FOR ANNUAL AND TRANSITION REPORTS

PURSUANT TO SECTIONS 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2006

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period From to

Commission File Number 333-12979-49

Foundation Coal Corporation

(Exact Name of Registrant as Specified in Its Charter)

Delaware

26-0085077

(State or Other Jurisdiction of

Incorporation or Organization)

(I.R.S. Employer

Identification No.)

999 Corporate Boulevard, Suite 300

Linthicum Heights, Maryland

21090

(Address of Principal Executive Offices)

(Zip Code)

Registrant’s telephone number, including area code) (410) 689-7500

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


Title of Each Class		Name of Each Exchange on Which Registered
None		None

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

None

Registrant meets the conditions set forth in the General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form with the reduced disclosure format.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The Registrant’s common equity is not publicly traded. The common stock of Foundation Coal Holdings, Inc., the Registrant’s public parent, began trading on the New York Stock Exchange on December 9, 2004. There were 45,109,690 shares of Foundation Coal Holdings, Inc. common stock outstanding on February 23, 2007. There were 100 shares of Foundation Coal Corporation common stock outstanding on February 23, 2007, all held by its parent, FC 2 Corp., which are not publicly traded.

TABLE OF CONTENTS


		Page
	PART I

ITEM 1.	BUSINESS	4

ITEM 1A.	RISK FACTORS	25

ITEM 1B.	UNRESOLVED STAFF COMMENTS	35

ITEM 2.	PROPERTIES	35

ITEM 3.	LEGAL PROCEEDINGS	36

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	36

	PART II

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS	37

ITEM 6.	SELECTED FINANCIAL DATA	37

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION	42

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	71

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	72

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	126

ITEM 9A.	CONTROLS AND PROCEDURES	126

ITEM 9B.	OTHER INFORMATION	126

	PART III

ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	127

ITEM 11.	EXECUTIVE COMPENSATION	127

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	127

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	127

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	127

	PART IV

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	128

EXHIBITS INDEX		130

SIGNATURES		134

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-K contains forward-looking statements that are not statements of historical fact and may involve a number of risks and uncertainties. These statements relate to analyses and other information that are based on forecasts of future results and estimates of amounts not yet determinable. These statements may also relate to our future prospects, developments and business strategies.

We have used the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project” and similar terms and phrases, including references to assumptions, in this Form 10-K to identify forward-looking statements. These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those matters expressed in or implied by these forward-looking statements. The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

•

market demand for coal, electricity and steel;

•

future economic or capital market conditions;

•

weather conditions or catastrophic weather-related damage;

•

our ability to produce coal at existing and planned future operations;

•

the consummation of financing, acquisition or disposition transactions and the effect thereof on our business;

•

our plans and objectives for future operations and expansion or consolidation;

•

our relationships with, and other conditions affecting, our customers;

•

timing of reductions or increases in customer coal inventories;

•

long-term coal supply arrangements;

•

risks in coal mining;

•

environmental laws, including those directly affecting our coal mining and production, and those affecting our customers’ coal usage;

•

competition;

•

railroad, barge, trucking and other transportation performance and costs;

•

our assumptions concerning economically recoverable coal reserve estimates;

•

employee workforce factors;

•

regulatory and court decisions;

•

future legislation and changes in regulations or governmental policies or changes in interpretations thereof;

•

changes in postretirement benefit and pension obligations;

•

our liquidity, results of operations and financial condition;

•

disruptions in delivery or changes in pricing from third party vendors of goods and services which are necessary for our operations, such as fuel, steel products, explosives and tires;

•

continuation of other revenues from fees received from synthetic fuel (“synfuel”) processors; and

•

other factors, including those discussed in “Risk Factors” “ITEM 1A.”

You should keep in mind that any forward-looking statement made by us in this Form 10-K or elsewhere speaks only as of the date on which we make it. New risks and uncertainties come up from time to time, and it is impossible for us to predict these events or how they may affect us. We have no duty to, and do not intend to, update or revise the forward-looking statements in this Form 10-K after the date of this Form 10-K, except as may be required by law. In light of these risks and uncertainties, you should keep in mind that any forward-looking statement made in this Form 10-K or elsewhere might not occur.

PART I

To aid readers unfamiliar with the terms commonly used in the coal industry, a glossary of selected terms is provided at the end of “ITEM 1. BUSINESS.”

Unless the context otherwise indicates, as used in this Annual Report on Form 10-K (“10-K”) the terms the “Company” “we” “our” “us” and similar terms refer to Foundation Coal Corporation and its consolidated subsidiaries. For purposes of all financial disclosure contained herein, Foundation Coal Corporation is an indirect wholly owned subsidiary of Foundation Coal Holdings, Inc. which is the “Successor” to RAG American Coal Holding, Inc. (the “Predecessor”). We were formed to acquire the North American coal mining assets of RAG Coal International AG, which acquisition closed on July 30, 2004 (the “Acquisition”). All references to Foundation Coal Corporation or Foundation Coal Holdings, Inc., including the business description, operating data and financial data, excludes RAG Coal International AG’s former Colorado operations, which were sold to a third party on April 15, 2004 and are accounted for herein as discontinued operations. Certain statements in this 10-K are forward-looking statements. To facilitate trend analysis we compare the historical financial data of Foundation Coal Corporation for the year ended December 31, 2005 with the “Non-GAAP Combined” financial data for the year ended December 31, 2004 which was determined by adding the historical amounts of the Predecessor for the period from January 1, 2004 through July 29, 2004 with the corresponding amounts of the Successor for the five month operating period ended December 31, 2004. Non-GAAP Combined amounts for the year ended December 31, 2004 are not recognized measures under GAAP and do not purport to be alternatives to GAAP operating measures. Non-GAAP Combined amounts are not indicative of the operating results of Foundation Coal Corporation because of the significant difference in basis between the Successor and Predecessor caused by the Acquisition and its impact on income from operations. Management believes that the discussion of Non-GAAP Combined operating results is important to the readers of the financial statements to understand key operating trends over the normal operating cycle years 2006, 2005 and 2004. Non-GAAP Combined amounts are reconciled to the underlying historical GAAP basis financial statements in ITEM 7.

ITEM 1.

BUSINESS.

Overview

We are the fourth largest coal producer in the United States. We operate a diverse group of fourteen mines located in Wyoming, Pennsylvania, West Virginia and Illinois. For the year ended December 31, 2006, we sold 73.9 million tons of coal, including 71.6 million tons that were produced and processed at our operations. As of December 31, 2006, we had approximately 1.6 billion tons of proven and probable coal reserves. We are also involved in marketing coal produced by others to supplement our own production and, through blending, provide our customers with coal qualities beyond those available from our own production. We purchased and resold 1.9 million tons of coal in 2006.

We are primarily a supplier of steam coal to U.S. utilities for use in generating electricity. We also sell steam coal to industrial plants. Steam coal sales accounted for 97% of our coal sales volume and 91% of our coal sales revenue in 2006. We also sell metallurgical coal to steel producers; metallurgical sales accounted for 3% of our coal sales volume and 9% of our coal sales revenue in 2006.

Competitive Strengths

We believe that the following competitive strengths enhance our prominent market position in the United States:

We are the fourth largest coal producer in the United States and have significant coal reserves. Based on 2006 production of 71.6 million tons, we are the fourth largest coal producer in the United States. As of December 31, 2006, we controlled approximately 1.6 billion tons of proven and probable coal reserves. Based on these reserve estimates and our actual rate of production during the year ended December 31, 2006, we have a total reserve life of approximately 23 years.

We have a diverse portfolio of coal-mining operations and reserves. We operate a total of 14 mines in the Powder River Basin, Northern Appalachia, Central Appalachia and the Illinois Basin, selling coal to dozens of domestic and foreign electric utilities, steel producers and industrial users. We are the only producer with significant operations and major reserve blocks in both the Powder River Basin and Northern Appalachia, two U.S. coal production regions for which future demand is expected to increase. We believe that this geographic diversity provides us with a significant competitive advantage, allowing us to source coal from multiple regions to meet the needs of our customers and reduce their transportation costs.

We operate highly productive mines and have had strong EBITDA margins. We believe our focus on productivity has helped contribute to our strong EBITDA margins for fiscal years ended 2004, 2005 and 2006. Our strategic investment in equipment and technology has increased the efficiency of our operations, which we believe reduces our costs and provides us with a competitive advantage. Maintaining our low-cost position enables us to maximize our profitability in all coal pricing environments.

We are a recognized industry leader in safety and environmental performance. Our focus on safety and environmental performance results in a lower likelihood of disruption of production at our mines, which leads to higher productivity and improved financial performance. We operate some of the nation’s safest mines, with 2006 injury incident rates, as tracked by the Mine Safety and Health Administration (“MSHA”), below industry averages.

We have long-standing relationships and long-term contracts with many of the largest coal-burning utilities in the United States. We supply coal to numerous power plants operated by a diverse group of electricity generators across the country. We believe we have a reputation for reliability and superior customer service that has enabled us to solidify our customer relationships.

Our management team has a track record of success during our long operating history. Our management team has a proven record of generating free cash flow, increasing productivity, reducing costs, developing and maintaining long-standing customer relationships and effectively positioning us for future growth and profitability. We operated as a stand-alone subsidiary of privately held RAG Coal International AG from 1999 until becoming an independent company on July 30, 2004. Our senior executives have an average of approximately 26 years of experience in the coal industry, including an average of 17 years of experience operating our assets when owned by us and our predecessors.

Business Strategy

Our objective is to increase shareholder value through sustained earnings and cash flow growth. Our key strategies to achieve this objective are described below:

Maintaining our commitment to operational excellence as a low-cost producer. We seek to maintain our productivity leadership with an emphasis on lowering costs by continuing to invest selectively in new equipment and advanced technologies, such as our previous investments in underground diesel, increased longwall face widths and a larger shield system. We will continue to focus on profitability and efficiency by leveraging our significant economies of scale, large fleet of mining equipment, information technology systems and coordinated purchasing and land management functions. In addition, we continue to focus on productivity through our culture of workforce involvement by leveraging our strong base of experienced, well-trained employees.

Capitalizing on favorable industry dynamics through a balanced approach to selling our coal. The fundamentals of the current U.S. coal market are among the strongest in the past decade resulting in a favorable coal pricing environment which, based on current coal forward prices, we believe will continue for the foreseeable future. We employ a balanced approach to selling our coal, including the use of long-term sales commitments for a portion of our future production while maintaining uncommitted planned production to capitalize on favorable future pricing environments.

Selectively expanding our production and reserves. Given our broad scope of operations and expertise in mining in each of the major coal-producing regions in the United States, we believe that we are well-situated to capitalize on the expected continued growth in U.S. and international coal consumption by evaluating growth opportunities, including (i) expansion of production capacity at our existing mining operations, (ii) further development of existing significant reserve blocks in Northern Appalachia and Central Appalachia, and (iii) potential strategic acquisition opportunities that arise in the United States or internationally. We will prudently act to expand our reserves when appropriate. For example, we currently plan to seek to increase our reserve position by obtaining mining rights to federal coal reserves adjoining our current operations in Wyoming through the Lease By Application (“LBA”) process.

Continuing to provide a mix of coal types and qualities to satisfy our customers’ needs. By having operations and reserves in the four major coal producing regions, we are able to source coal from multiple mines to meet the needs of our domestic and international customers. Our broad geographic scope and mix of coal qualities provide us with the opportunity to work with many leading electricity generators, steel companies and other industrial customers across the country.

Continuing to focus on excellence in safety and environmental stewardship. We intend to maintain our recognized leadership in operating some of the safest mines in the United States and in achieving environmental excellence. Our ability to minimize lost-time injuries and environmental violations improves our operating efficiency, which directly improves our cost structure and financial performance.

History

Amoco Minerals Company was incorporated in Delaware on September 2, 1969, as a subsidiary of Amoco Corporation. The name was changed to Cyprus Minerals Company on May 24, 1985 and then spun-off from Amoco Corporation in July of 1985.

Cyprus Minerals Company merged with and into AMAX, Inc., a New York corporation, on November 15, 1993, with Cyprus Minerals Company being the surviving corporation under the name Cyprus Amax Minerals Company. The combined coal mining businesses were consolidated under Cyprus Amax Coal Company at the time of the 1993 merger.

On June 30, 1999, Cyprus Amax Minerals Company and its subsidiary, Amax Energy Inc., sold the stock of Cyprus Amax Coal Company and all of its subsidiaries consisting of its remaining coal properties to RAG International Mining GmbH (now RAG Coal International AG (“RAG”)). After the closing of this transaction in 1999, our parent holding company was RAG American Coal Holding, Inc.

Foundation Coal Holdings, LLC (“LLC”) was formed on February 9, 2004, by a group of investors for the purpose of acquiring the United States coal properties owned by RAG Coal International AG. A Stock Purchase Agreement was signed on May 24, 2004.

On April 23, 2004, the Company was formed as a wholly owned subsidiary of LLC. The Company issued 100 shares of common stock with a par value of $0.01 to LLC. LLC was formed as a Delaware limited liability company, which, as described below, later contributed its shares of the Company and merged into Foundation Coal Holdings, Inc.

LLC through its subsidiary, Foundation Coal Corporation, and pursuant to the Stock Purchase Agreement, completed the Acquisition of 100% of the outstanding common shares of RAG American Coal Holding, Inc. and its subsidiaries from RAG Coal International AG, on July 30, 2004 (the “Transaction”).

LLC merged on August 17, 2004 into its subsidiary, Foundation Coal Holdings, Inc., a Delaware corporation that was formed on July 19, 2004. Foundation Coal Holdings, Inc. was the surviving entity in this merger. Accordingly, the Company became an indirect wholly owned subsidiary of Foundation Coal Holdings, Inc. On December 9, 2004, Foundation Coal Holdings, Inc. completed an initial public offering of 24,121,900 shares of common stock and became the entity we refer to herein as the “Public Parent.”

The Company, through its operating subsidiaries, engages in the extraction, cleaning and selling of coal to electric utilities, steel companies, coal brokers, and industrial users primarily in the United States.

Coal Mining Techniques

We use four different mining techniques to extract coal from the ground: longwall mining, room-and-pillar mining, truck-and-shovel mining and truck and front-end loader mining.

Longwall Mining

We utilize longwall mining techniques at our Cumberland and Emerald mines in Pennsylvania. Longwall mining is the most productive and safest underground mining method used in the United States. A rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the roof of the mine while the drum advances through the coal. Chain conveyors then move the loosened coal to a standard underground mine conveyor system for delivery to the surface. Continuous miners are used to develop access to long rectangular blocks of coal which are then mined with longwall equipment, allowing controlled subsidence behind the advancing machinery. Longwall mining is highly productive and most effective for large blocks of medium to thick coal seams. High capital costs associated with longwall mining demand large, contiguous reserves. Ultimate seam recovery of in-place reserves using longwall mining is much higher than the room-and-pillar mining underground technique. All of the raw coal mined at our longwall mines is washed in preparation plants to remove rock and impurities.

Room-and-Pillar Mining

Our Kingston, Laurel Creek and Rockspring mines in West Virginia and our Wabash mine in Illinois utilize room-and-pillar mining methods. In this type of mining, main airways and transportation entries are developed and maintained while remote-controlled continuous miners extract coal from so-called rooms by removing coal from the seam, leaving pillars to support the roof. Shuttle cars and battery coal haulers are used to transport coal to the conveyor belt for transport to the surface. This method is more flexible and often used to mine smaller coal blocks or thin seams. Ultimate seam recovery of in-place reserves is typically less than that achieved with longwall mining. Much of this production is also washed in preparation plants before it becomes saleable clean coal.

Truck-and-Shovel Mining and Truck and Front-End Loader Mining

We utilize truck-and-shovel mining methods in both of our mines in the Powder River Basin. We utilize the truck and front-end loader method at our surface mines in West Virginia (the “Pioneer mines”). These methods are similar and involve using large, electric or hydraulic-powered shovels or diesel-powered front-end loaders to remove earth and rock (overburden) covering a coal seam which is later used to refill the excavated coal pits after the coal is removed. The loading equipment places the coal into haul trucks for transportation to a preparation plant or loadout area. Ultimate seam recovery of in-place reserves on average exceeds 90%. This surface-mined coal rarely needs to be cleaned in a preparation plant before sale. Productivity depends on overburden and coal thickness (strip ratio), equipment utilized and geologic factors.

Business Environment

Coal is an abundant, efficient and affordable natural resource used primarily to provide fuel for the generation of electric power. World-wide recoverable coal reserves are estimated to be approximately 1.0 trillion tons. The United States is one of the world’s largest producers of coal and has approximately 27% of global coal reserves, representing over 200 years of supply based on current usage rates. According to the U.S. Department of Energy, the energy content of the United States coal reserves exceeds that of all the known oil supplies in the world.

Coal Markets. Coal is primarily consumed by utilities to generate electricity. It is also used by steel companies to make steel products and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. In general, coal is characterized by end use as either steam coal or metallurgical coal. Steam coal is used by electricity generators and by industrial facilities to produce steam, electricity or both. Metallurgical coal is refined into coke, which is used in the production of steel. Over the past quarter century, total annual coal consumption in the United States has nearly doubled to approximately 1.2 billion tons in 2006. The growth in the demand for coal has coincided with an increased demand for coal from electric power generators.


	Actual		Preliminary⁽¹⁾		Projected⁽²⁾		Annual Growth
Consumption by Sector	2003	2004	2005	2006	2010	2025	2005-2010		2010-2025
				(tons in millions)
Electric Generation	1,005	1,016	1,037	1,043	1,104	1,411	1.3	%	1.6	%
Industrial	61	62	60	64	64	63	0.6	%	(0.1	)%
Steel Production	24	24	24	24	22	21	(1.4	)%	(0.3	)%
Coal-to-Liquids Processes	0	0	0	0	0	82	N/A		N/A
Residential/Commercial	4	5	4	4	5	5	2.4	%	0.0	%
Export	43	48	50	46	44	27	0.3	%	(3.2	)%

Total	1,138	1,155	1,176	1,181	1,239	1,609	1.2	%	1.8	%

⁽¹⁾	Preliminary data estimates for 2006 are based on data published in the EIA’s Quarterly Coal Report through the third quarter of 2006 and output from the EIA’s National Energy Modeling System.

⁽²⁾	Projected 2010—2025 Data per EIA Annual Energy Outlook 2007

The nation’s power generation infrastructure is largely coal-fired. As a result, coal has consistently maintained a 49% to 53% market share during the past 10 years, principally because of its relatively low cost, reliability and abundance. Coal is the lowest cost fossil fuel used for base-load electric power generation, being considerably less expensive than natural gas or oil. Coal-fired generation is also competitive with nuclear power generation especially on a total cost per megawatt-hour basis. The production of electricity from existing hydroelectric facilities is inexpensive, but its application is limited both by geography and susceptibility to seasonal and climatic conditions. Non-hydropower renewable power generation accounts for only 2.5% of all the electricity generated in the United States, and wind and solar power—the renewable energy sources that may provide more environmental benefits—represent less than 1% of United States power generation.

Coal consumption patterns are also influenced by the demand for electricity, governmental regulation impacting power generation, technological developments and the location, availability and cost of other fuels such as natural gas, nuclear and hydroelectric power.

Coal’s primary advantages are its relatively low cost and availability compared to other fuels used to generate electricity. Using 2005 Federal Energy Regulatory Commission Form 1 filings as a basis, Global Energy Advisors (“GEA”), a commonly used authoritative resource for industry commodity pricing, has estimated the average total production costs of electricity, using coal and competing generation alternatives in 2006, as follows:


Electrical Generation Type	Cost per Megawatt Hour
Natural Gas	$	81.58
Petroleum	$	80.61
Non-hydro renewables*	$	59.57
Coal	$	21.62
Nuclear	$	17.27
Hydroelectric	$	11.41

*	Includes: electricity generation from solar, wind, agriculture byproducts, biomass, geothermal, landfill gas, wood waste and other waste products.

Coal Production. United States coal production was approximately 1.1 billion tons in 2006. The following table, derived from data prepared by the EIA, sets forth production statistics in each of the four major coal producing regions for the periods indicated (totals may not foot due to rounding).


	Actual		Preliminary⁽¹⁾		Projected⁽²⁾		Annual Growth
Production by Region	2003	2004	2005	2006	2010	2025	2005-2010		2010-2025
				(tons in millions)
Powder River Basin	400	421	430	449	479	694	2.2	%	2.5	%
Central Appalachia	231	233	236	233	190	134	(4.3	)%	(2.3	)%
Northern Appalachia	137	135	140	142	171	197	4.0	%	0.9	%
Illinois Basin	92	94	96	100	117	148	4.0	%	1.6	%
Other	223	228	229	224	232	344	0.2	%	2.7	%

Total	1,083	1,112	1,131	1,149	1,189	1,517	1.0	%	1.6	%

⁽¹⁾	Preliminary data estimates for 2006 are based on data published in the EIA’s Quarterly Coal Report through the third quarter of 2006 and output from the EIA’s National Energy Modeling System.

⁽²⁾	Projected 2010-2025 Data per EIA Annual Energy Outlook 2007.

Coal Regions. Coal is mined from coal fields throughout the United States, with the major production centers located in the Western United States, Northern and Central Appalachia and the Illinois Basin. The quality of coal varies by region. Heat value and sulfur content are two of the most important coal characteristics in measuring quality and determining the best end use of particular coal types.

Competition. The coal industry is intensely competitive. The most important factors on which we compete are coal price at the mine, 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 are influenced by factors beyond our control. Some of these factors include the demand for electricity, which is significantly dependent upon economic activity and summer and winter temperatures in the United States, government regulation, technological developments and the location, availability, quality and price of competing sources of coal, alternative fuels such as natural gas, oil and nuclear, and alternative energy sources such as hydroelectric power.

Transportation Cost. Coal used for domestic consumption is generally sold free on board at the mine, and the purchaser normally bears the transportation costs. Export coal, however, is usually sold at the loading port, and coal producers are responsible for shipment to the export coal-loading facility, with the buyer paying the ocean freight.

Most electric generators arrange long-term shipping contracts with rail or barge companies to assure stable delivered costs. Transportation can be a large component of a purchaser’s total cost. Although the purchaser pays the freight, transportation costs still are important to coal mining companies because the purchaser may choose a supplier largely based on cost of transportation. According to the National Mining Association (“NMA”), railroads account for nearly two-thirds of total United States coal shipments, while river barge movements account for an additional 20%. Trucks and overland conveyors haul coal over shorter distances, while barges, Great Lake carriers and ocean vessels move coal to markets served by water. Most coal mines are served by a single rail company, but some are served by two competing rail carriers. Rail competition is important because rail costs can constitute up to 75% of the delivered cost of coal in various markets.

Coal Characteristics

In general, coal of all geological composition is characterized by end use as either steam coal or metallurgical coal. Heat value and sulfur content are two of the most important variables in the profitable marketing and transportation of steam coal, while ash, sulfur and various coking characteristics are important variables in the profitable marketing and transportation of metallurgical coal. We mine, process, market and transport bituminous and sub-bituminous coal, characteristics of which are described below.

Heat Value

The heat value of coal is commonly measured in British thermal units, or “Btus.” A Btu is the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. Coal found in the eastern and Midwestern regions of the United States tends to have a higher heat value than coal found in the western United States.

Bituminous coal has a heat value that ranges from 10,500 to 14,000 Btu/lb. This coal is located primarily in our mines in Northern and Central Appalachia and in the Illinois Basin, and is the type most commonly used for electric power generation in the United States. Bituminous coal is used for utility and industrial steam purposes, and includes metallurgical coal, a feed stock for coke, which is used in steel production.

Sub-bituminous coal has a heat value that ranges from 7,800 to 9,500 Btu/lb. Our sub-bituminous reserves are located in Wyoming. Sub-bituminous coal is used almost exclusively by electric utilities and some industrial consumers.

Sulfur Content

Sulfur content can vary from seam to seam and sometimes within each seam. When coal is burned, it produces sulfur dioxide, the amount of which varies depending on the chemical composition and the concentration of sulfur in the coal. Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus and complies with the requirements of the Clean Air Act. Low sulfur coal is coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btus.

Sub-bituminous coal typically has a lower sulfur content than bituminous coal, but some of our bituminous coal in West Virginia also has a low sulfur content.

High sulfur coal can be burned in plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions. Plants without scrubbers can burn high sulfur coal by blending it with lower sulfur coal, or by purchasing emission allowances on the open market, which permit the user to emit a ton of sulfur dioxide. More than 15,000 megawatts of coal-based generating capacity has been retrofitted with scrubbers since the beginning of Phase I of the Clean Air Act. Furthermore, utilities have announced plans to scrub an additional 89,000 megawatts by 2010. Additional scrubbing will provide new market opportunities for our noncompliance coals. All new coal-fired generation plants built in the United States are expected to use clean coal-burning technology.

Operations

As of December 31, 2006, we operated a total of 14 mines located in Wyoming, Pennsylvania, West Virginia and Illinois. We currently own most of the equipment utilized in our mining operations.

The following table provides summary information regarding our principal mining complexes as of December 31, 2006.


Mining Complex	Number of Mines	Type of Mine	Mining Technology	Transportation	Tons Sold in 2006
					(In millions)
Wyoming
Belle Ayr	1	Surface	Truck-and-Shovel	BNSF, UP	24.6
Eagle Butte	1	Surface	Truck-and-Shovel	BNSF, Truck	25.3

Pennsylvania
Cumberland	1	Underground	Longwall	Barge	7.6
Emerald	1	Underground	Longwall	CSX, NS	6.2

West Virginia
Kingston	2	Underground	Room-and-Pillar	Barge, CSX, NS	1.1
Laurel Creek	4	Underground	Room-and-Pillar	Barge, CSX	1.5
Rockspring	1	Underground	Room-and-Pillar	NS	2.8
Pioneer	2	Surface	Truck and Front-End Loader	Barge, NS,	1.7
				CSX/RJCC
Purchased and resold coal					1.8

Illinois
Wabash	1	Underground	Room-and-Pillar	NS	1.2

Other
Purchased and resold coal	—				0.1

Total	14				73.9

BNSF	= BNSF Railway

CSX	= CSX Transportation

RJCC	= R.J. Corman Railroad Company

NS	= Norfolk Southern Railway Company

UP	= Union Pacific Railroad Company

Note: The tonnage shown for each mine represents coal mined, processed and shipped from our active operations. Kingston and Pioneer tons sold include a total of 1.5 million tons of metallurgical coal. The tonnage shown in the two categories labeled purchased and resold includes 0.7 million tons of metallurgical coal.

The following map outlines our operations, sales of produced coal, tons sold and reserves as of December 31, 2006:

LOGO

The following provides a description of the operating characteristics of the principal mines and reserves of each of our mining operations.

Wyoming Operations

We control approximately 626.7 million tons of coal reserves in the Powder River Basin, the largest and fastest growing U.S. coal-producing region. Our subsidiaries, Foundation Coal West, Inc. and Foundation Wyoming Land Company, own and manage two sub-bituminous, low sulfur, non-union surface mines that sold 49.9 million tons of coal in 2006, or 63% of our total production volume. The two mines employ approximately 550 salaried and hourly employees. Our Powder River Basin mines have produced over 900 million tons of coal since 1972.

Belle Ayr Mine

The Belle Ayr mine, located approximately 18 miles southeast of Gillette, Wyoming, extracts coal from the Wyodak-Anderson Seam, which averages 75 feet thick, using the truck-and-shovel mining method. Belle Ayr shipped 24.6 million tons of coal in 2006. The mine sells 100% of raw coal mined and no washing is necessary. Belle Ayr has approximately 306.0 million tons of reserves. The reserves at Belle Ayr will sustain projected production for approximately 12 years if market conditions warrant. We plan to apply to lease several hundred million tons of surface mineable, unleased federal coal that adjoins Belle Ayr’s property under the LBA process. If we prevail in the bidding process and obtain these leases we will be able to extend the life of the mine. Belle Ayr has the advantage of shipping its coal on both of the major western railroads, the BNSF Railway and the Union Pacific Railroad.

Eagle Butte Mine

The Eagle Butte mine, located approximately eight miles north of Gillette, Wyoming, extracts coal from the Roland and Smith Seams, which total 100 feet thick, using the truck-and-shovel mining method. Eagle Butte shipped 25.3 million tons of coal in 2006. The mine sells 100% of the raw coal mined and no washing is necessary. Eagle Butte has approximately 320.7 million tons of reserves. The reserves will sustain projected production levels for 13 years if market conditions warrant. We have applied to lease approximately 230 million tons of surface mineable, unleased federal coal adjoining the western boundary of the mine property. The LBA sale is scheduled for October, 2007. If we prevail in the bidding process and obtain this lease, we will be able to extend the mine’s life by approximately an additional 9 years, based on the mine’s 2006 rate of production. Coal from Eagle Butte is shipped on the BNSF Railway to power plants located throughout the Midwest and the South. The mine also ships a small portion by truck.

Pennsylvania Operations

We control approximately 747.3 million tons of contiguous reserves in Northern Appalachia. Approximately 184.1 million tons are assigned to active mines. Approximately 563.2 million tons are unassigned. A portion of these unassigned reserves is accessible through our currently active mines. Our Pennsylvania mines are located in the southwestern part of the state, approximately 60 miles south of Pittsburgh. Both mines operate in the Pittsburgh No. 8 Seam, the dominant coal-producing seam in the region, which is six to eight feet thick on these properties. The Pennsylvania operations consist of the Cumberland and the Emerald mining complexes, which collectively shipped 13.8 million tons in 2006 using longwall mining systems supported by continuous mining methods. The mines sell high Btu, medium sulfur coal primarily to eastern utilities. The hourly work force at each mine is represented by the United Mine Workers of America (“UMWA”).

Cumberland Mine

The Cumberland mining complex, located approximately 12 miles south of Waynesburg, Pennsylvania, was established in 1977. Cumberland shipped 7.6 million tons of coal in 2006. As of December 31, 2006, Cumberland had assigned reserves of 98.0 million tons. All of the coal at Cumberland is processed through a preparation plant before being loaded onto Cumberland’s owned and operated railroad for transportation to the Monongahela River dock site. At the dock site, coal is then loaded into barges for transportation to river-served utilities or to other docks for subsequent rail shipment to non-river-served utilities. The mine can also ship a portion of its production via truck. Cumberland has approximately 650 salaried and hourly employees.

Emerald Mine

The Emerald mining complex, located approximately two miles south of Waynesburg, Pennsylvania, was established in 1977. As of December 31, 2006, Emerald had assigned reserves of approximately 86.1 million tons. Emerald shipped 6.2 million tons of coal in 2006. Emerald has the ability to store clean coal and blend variable sulfur products to meet customer requirements. All of Emerald’s coal is processed through a preparation plant before being loaded into unit trains operated by the Norfolk Southern Railway or CSX Transportation. The mine also has the option to ship a portion of its coal by truck. Approximately 580 salaried and hourly employees work at Emerald.

West Virginia Operations

Our subsidiaries operate four mining facilities located in West Virginia in the Central Appalachia region: Kingston, Laurel Creek, Rockspring and Pioneer. The Kingston, Laurel Creek and Rockspring facilities are all underground mining complexes that use room-and-pillar mining technology to develop and extract coal. The Pioneer mines operate two surface mines utilizing truck/loader systems to extract coal from multiple seams. Our West Virginia operations have approximately 69.5 million tons of reserves that are assigned to current operations and approximately 127.6 million tons of reserves that are unassigned and are being held for future development. Except for the two surface mines, all of the raw coal is processed through preparation plants before transportation to market. Production from the mines is typically low sulfur, high Btu coal. In 2006, our West Virginia mines collectively sold 8.9 million tons of produced and purchased coal. Our West Virginia mines ship coal by either the Norfolk Southern Railway or CSX Transportation or by barge on the Kanawha and Big Sandy Rivers. These operations serve a diversified customer base, including regional and national customers. We also own and operate the Rivereagle loading facility on the Big Sandy River in Boyd County, Kentucky.

Our West Virginia operations have approximately 885 non-union salaried and hourly employees. In November 2003, a UMWA election was held at the Rockspring mining facility, the outcome of which is pending a decision of the National Labor Relations Board (the “NLRB”). If the NLRB finds that the UMWA was properly elected, approximately 290 employees at the Rockspring facility would become UMWA members.

Kingston Mines

The Kingston complex consists of two mines, Kingston #1 and Kingston #2, located in Fayette County and Raleigh County, respectively. Kingston #1 mines the Glen Alum Seam and Kingston #2 mines the Douglas Seam. In 2006, the Kingston complex shipped 1.1 million tons and as of December 31, 2006 had approximately 11.4 million tons of reserves of which approximately 8.2 million tons are assigned and approximately 3.2 million tons are unassigned. Kingston sells coal primarily into the metallurgical market for domestic steel plants. The coal is trucked to the Kanawha River for shipment by barge or delivered via CSX Transportation or the Norfolk Southern Railway for shipment by rail.

Laurel Creek Mines

The Laurel Creek mining complex consists of four underground mines. The #1 and #5 mines operate in the Coalburg Seam. The #4 mine operates in the 5 block seam and the #6 mine operates in the Cedar Grove seam. The preparation plant is located in Logan and Mingo Counties. In 2006, the mines shipped 1.5 million tons and as of December 31, 2006 had approximately 4.7 million tons of assigned reserves and approximately 18.4 million tons of unassigned reserves. The coal is shipped by truck primarily to our Rivereagle dock, other third-party docks or our rail siding on CSX Transportation.

Rockspring Mine

Rockspring Development, Inc. operates a large multiple section mining complex in Wayne County called Camp Creek that produces coal from the Coalburg Seam. The complex shipped 2.8 million tons of coal in 2006. Assigned and unassigned coal reserves totaled approximately 41.0 million tons and 22.7 million tons, respectively. Rockspring has a mine site rail loadout. The coal is transported on the Norfolk Southern Railway, primarily to southeastern utilities. The mine can also ship a portion of its production by truck.

Pioneer Mines

Pioneer Fuel Corporation operates two surface mines, Paynter Branch which is located in Wyoming County and Pax surface mine which is located in Raleigh County. These mines utilize front-end loaders with trucks to mine multiple seams. The Pioneer mines shipped 1.7 million tons of steam and metallurgical coal in 2006. As of December 31, 2006, the mines had assigned reserves of approximately 15.6 million tons with an additional 19.4 million tons of unassigned reserves. Based on 2006 production rates, we expect that the Paynter Branch mine has sufficient reserves to last approximately 11 years. Mine development at the Pax surface mine was completed in 2006. We expect that the Pax mine has sufficient reserves to last approximately 13 years. Coal from Paynter Branch is shipped by truck to a loading facility on the Norfolk Southern Railway and then on to domestic utilities and exported to metallurgical coal customers. Coal from Pax is trucked to the Kanawha River for shipment by barge or may be transported by truck to an on-site loading facility. The Pax mine has an on-site loading facility which allows loading by short line R.J. Corman Railroad for nearby interchange to our rail siding on the CSX Transportation, Inc. railroad.

Illinois Operations

Wabash Mine

The Wabash mine is a room-and-pillar operation, mining in the Illinois No. 5 seam, located in Wabash County, Illinois in the Illinois Basin just east of Keensburg. The mine shipped 1.2 million tons of steam coal in 2006. After cleaning in the preparation plant, the coal is shipped via the Norfolk Southern Railway to power plants located in the Illinois Basin, in particular to the PSI Gibson Station in Owensville, Indiana, one of the largest power plants in the U.S.

The hourly work force at the Wabash mine is represented by the UMWA. Wabash has approximately 290 salaried and hourly employees.

FutureGen Industrial Alliance, Inc.

We are a founding member of the FutureGen Industrial Alliance, Inc. This is a non-profit entity that is partnering with the U.S. Department of Energy to facilitate the design, construction and operation of the world’s first near-zero emission coal-fueled power plant. Government cost share is anticipated to be 74% and the private sector will contribute 26% of project costs. As of January 2007, there were twelve major domestic and international utilities and mining companies joining in this effort. The FutureGen plant cost will be in excess of $1 billion and is intended to demonstrate advanced technologies to gasify coal and generate electricity, and produce hydrogen which has potential to power fuel cells for transportation and other energy needs. The facility also will integrate systems to capture carbon dioxide emissions and sequester them underground permanently. This carbon capture and sequestration technology is expected to help address the issue of climate change as energy demand continues to grow worldwide. The alliance has completed initial conceptual design and narrowed site selection from 12 locations in 7 states to 4 locations in 2 states, two each in Texas and Illinois. Final site selection is scheduled for later in 2007. Construction is currently scheduled to begin in 2009. As this entity is a non-profit, we will not receive any future revenues or income, and will only receive indirect benefits by helping ensure the future use of coal as a clean, low cost source of fuel.

Long-Term Coal Supply Agreements

As of December 31, 2006, we had a total sales backlog of over 311 million tons of coal, and our coal supply agreements have remaining terms ranging from one to 15 years. For 2006, based on sales revenues we sold approximately 76% of our sales volume under long-term coal supply agreements with a duration of twelve months or longer. In 2006, we sold coal to over 100 electricity generating and industrial plants. Our primary customer base is in the United States. We expect to continue selling a significant portion of our coal under long-term supply agreements. Our strategy is to selectively renew, or enter into new, long-term supply contracts when we can do so at prices we believe are favorable. As of January 24, 2007, we had sales and price commitments for approximately 98% of our planned 2007 production, approximately 70% of our planned 2008 production, approximately 48% of our planned 2009 production and approximately 19% of our planned 2010 production. To the extent we do not renew or replace expiring long-term coal supply agreements, our future sales will be exposed to market fluctuations.

The terms of our coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary significantly by customer, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, future regulatory changes, extension options, force majeure, termination and assignment provisions.

Some of our long-term contracts provide for a predetermined adjustment to the stipulated base price at times specified in the agreement or at other periodic intervals to account for changes due to inflation or deflation. In addition, many of our contracts contain provisions to adjust the base price due to new statutes, ordinances or regulations that impact our costs related to performance of the agreement. Additionally, some of our contracts contain provisions that allow for the recovery of costs impacted by modifications or changes in the interpretations or application of any applicable statute by local, state or federal government authorities.

Price reopener provisions are present in some of our long-term contracts. These provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. In a limited number of agreements, if the parties do not agree on a new price, either party has an option to terminate the contract. Under some of our contracts, we have the right to match lower prices offered to our customers by other suppliers.

Quality and volumes for the coal are stipulated in coal supply agreements, and in some instances buyers have the option to vary annual or monthly volumes. Most of our coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash, hardness and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts.

Some of our contracts set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as labor strikes or lockouts, adverse mining conditions, mine closures or serious transportation problems that affect us or unanticipated plant outages that may affect the buyer. More recent contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer. Many of our contracts contain similar clauses covering changes in environmental laws. We often negotiate the right to supply coal that complies with new environmental requirements to avoid contract termination.

In some of our contracts, we have a right of substitution, allowing us to provide coal from different mines as long as the replacement coal meets quality specifications and will be sold at the same delivered cost.

Sales and Marketing

Our sales team has an average of 22 years of experience in the areas of coal sales and procurement, trading, and transportation. Through our sales, trading and marketing entities, we sell coal produced by our diverse portfolio of operations, broker coal sales of other coal producers, both as principal and agent, trade coal and emission allowances and provide transportation-related services. Our sales, marketing, and trading affiliate, Foundation Energy Sales, Inc., employs staff to handle trading, transportation, market research, contract administration and risk/credit management activities.

Transportation

Coal consumed domestically is usually sold at the mine, and transportation costs are normally borne by the purchaser. Export coal is usually sold at the loading port, with purchasers paying ocean freight. Producers usually pay shipping costs from the mine to the port.

We depend upon rail, barge, trucking and other systems to deliver coal to markets. In 2006, our produced coal was transported from the mines and to the customer primarily by rail, with the main rail carriers being CSX Transportation, Norfolk Southern Railway, BNSF Railway, Union Pacific Railroad Company. The majority of our sales volume is shipped by rail, but a portion of our production is shipped by barge and truck. All coal from our Belle Ayr mine in Wyoming is shipped by two competing railroads, the BNSF Railway and the Union Pacific Railroad Company, while rail shipments from our Eagle Butte operation moves via the BNSF Railway. The Wabash mine in Illinois is serviced by the Norfolk Southern Railway. The Pioneer, Kingston, Laurel Creek and Rockspring mines in West Virginia are serviced by a combination of the Norfolk Southern Railway and CSX Transportation, as well as by truck and barge. In Pennsylvania, the Emerald mine is serviced by the Norfolk Southern Railway and CSX Transportation and the Cumberland mine is primarily serviced by barge. We move the coal from the Cumberland mine approximately 17 miles to the river for loading into barges on a captive railroad line we own and operate.

We believe we enjoy good relationships with rail carriers and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation and distribution employees.

Suppliers

We spend more than $400 million per year to procure goods and services in support of our business activities, excluding capital expenditures. Principal commodities include maintenance and repair parts and services, electricity, fuel, roof control and support items, explosives, tires, conveyance structure, ventilation supplies and lubricants. We use suppliers for a significant portion of our equipment rebuilds and repairs both on- and off-site, as well as construction and reclamation activities and to support computer systems.

Each of our regional mining operations has developed its own supplier base consistent with local needs. We have a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods, and to support the business units. The supplier base has been relatively stable for many years, but there has been some consolidation. We are not dependent on any one supplier in any region. We promote competition between suppliers and seek to develop relationships with those suppliers whose focus is on lowering our costs. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

Employees

As of December 31, 2006, we and our subsidiaries had approximately 3,150 employees. As of December 31, 2006, pursuant to three distinct collective bargaining agreements, the UMWA represented approximately 39% of our affiliates’ employees, who produced approximately 21% of our coal sales volume during the fiscal year ended December 31, 2006. Relations with organized labor are important to our success and we believe our relations with our employees are satisfactory. Three mining operations (Cumberland, Emerald and Wabash) are separate signatories to the UMWA collective wage agreement negotiated between the Bituminous Coal Operators Association (the “BCOA”) and the UMWA in 2002. While our affiliated operations are not part of the BCOA, these entities have historically executed collective wage agreements patterned after the industry negotiated collective wage agreement with additional memoranda of understanding to handle different operating cost structures and other local issues. The three separate wage agreements with the UMWA expire at the end of the first quarter 2007, approximately three months after the industry-negotiated collective wage agreement expiration date of December 31, 2006. Because the Wabash mine operates with the room-and-pillar method (as opposed to the lower cost longwall method at Emerald and Cumberland), and operates in a different production basin with different markets and competition, it may require a distinct collective bargaining agreement from those at Cumberland and Emerald in order to stay competitive and to justify capital investments.

ENVIRONMENTAL AND OTHER REGULATORY MATTERS

Federal, state and local authorities regulate the United States coal mining industry with respect to matters such as: employee health and safety; permitting and licensing requirements; emissions to air and discharges to water; plant and wildlife protection; the reclamation and restoration of mining properties after mining has been completed; the storage, treatment and disposal of wastes; remediation of contaminated soil, surface and groundwater; surface subsidence from underground mining; and the effects of mining on surface and groundwater quality and availability, and competing uses of adjacent, overlying or underlying lands such as for oil and gas activity, pipelines, roads and public facilities. These regulations and legislation (and judicial or agency interpretations thereof) have had, and will continue to have, a significant effect on our production costs and our competitive position. New laws and regulations, as well as future interpretations or different enforcement of existing laws, and regulations, may require substantial increases in equipment and operating costs to us and delays, interruptions, or a termination of operations, the extent of which we cannot predict. We intend to respond to these regulatory requirements and interpretations thereof at the appropriate time by implementing necessary modifications to facilities or operating procedures. When appropriate, we may also challenge actions in regulatory or court proceedings. Future legislation, regulations, interpretations or enforcement may also cause coal to become a less attractive fuel source. As a result, future legislation, regulations, interpretations or enforcement may adversely affect our mining operations, cost structure or the ability of our customers to use coal.

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

Mine Safety and Health

The Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act of 1977 impose stringent safety and health standards on all aspects of mining operations.

Also, most of the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. Regulation has a significant effect on our operating costs.

In early 2006, as a result of the Sago mine incident in West Virginia and other incidents in the coal mining industry, legislative and regulatory bodies at the state and federal levels including MSHA have promulgated or proposed various new statutes, regulations and policies relating to mine safety and mine emergency issues. Although some new laws, regulations and policies are in place, these legislative and regulatory efforts are still ongoing. At this time, it is not possible to predict the full effect that the new or proposed statutes, regulations and policies will have on our operating costs, but it will increase our costs and those of our competitors. Some, but not all, of these additional costs can be passed on to customers.

Black Lung

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. This tax is passed on to the purchaser under many of our coal supply agreements.

In December 2000, the Department of Labor amended regulations implementing the federal black lung laws to, among other things, establish a presumption in favor of a claimant’s treating physician and limit a coal operator’s ability to introduce medical evidence regarding the claimant’s medical condition. The number of claimants who are awarded benefits will increase, as will the amounts of those awards.

As of December 31, 2006, all of our various payment obligations for federal black lung benefits to claimants entitled to such benefits are made from a fully funded tax exempt trust established for that purpose. Based on actuarial reports and required funding levels, from time to time we may have to supplement the trust corpus to cover the anticipated liabilities going forward.

Coal Industry Retiree Health Benefit Act of 1992

The Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”) provides for the funding of health benefits for certain UMWA retirees and their spouses or dependants. The Coal Act established the Combined Fund into which employers who are “signatory operators” are obligated to pay annual premiums for beneficiaries. The Combined Fund covers a fixed group of individuals who retired before July, 1 1976, and the average age of the retirees in this fund is approximately 80 years of age. Premiums paid in 2006 for our obligations to the Combined Fund were approximately $1.2 million. The Coal Act also created a second benefit fund, the 1992 Plan, for miners who retired between July 1, 1976 and September 30, 1994, and whose former

employers are no longer in business to provide them retiree medical benefits. Companies with 1992 Plan liabilities also pay premiums into this plan. Premiums paid in 2006 for our obligation to the 1992 Plan were approximately $1.0 million. These per beneficiary premiums for both the Combined Fund and the 1992 Plan are adjusted annually based on various criteria such as the number of beneficiaries and the anticipated health benefit costs.

On December 20, 2006, the Tax Relief and Health Care Act of 2006 became law and will have the impact of reducing or eliminating the premium obligation of companies due to the expanded transfers from the Abandoned Mine Land Fund (“AML”). The additional transfer of funds from AML will eliminate, to the extent the new transfers are adequate, the unassigned beneficiary premium under the Combined Fund effective October 1, 2007. The additional transfers will also reduce incrementally the pre-funding and assigned beneficiary premium to cover the cost of beneficiaries for which no individual company is responsible (“orphans”) under the 1992 Plan beginning January 1, 2008. For the first time, the 1993 Benefit Plan (all of the beneficiaries of which are orphans) will begin receiving a subsidy from a new federal transfer that will ultimately cover the entire cost of the population included in the plan as of December 31, 2006. Under the Combined Fund, the 1992 Plan and the 1993 Plan, if the federal transfers are inadequate to cover the cost of the “orphan” component the 2007 signatories, the UMWA contract will remain liable for any shortfall.

Environmental Laws

We and our customers are subject to various federal, state and local environmental laws. Some of the more material of these laws, discussed below, place stringent requirements on our coal mining operations and our customers. Federal and state regulations require regular monitoring of our mines and other facilities to ensure compliance.

Mining Permits and Necessary Approvals

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

In order to obtain mining permits and approvals from state regulatory authorities we must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior or better condition, productive use or other permitted condition. Typically, we submit our necessary permit applications several months, or even years, before we plan to begin mining a new area. In the past, we have generally obtained our mining permits in time so as to be able to run our operations as planned. However, we cannot be sure that we will not experience difficulty or delays in obtaining mining permits in the future or even denials of permits altogether.

Surface Mining Control and Reclamation Act

The Surface Mining Control and Reclamation Act of 1977 (the “SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement (the “OSM”), establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. Where state regulatory agencies have adopted federal mining programs under the act, the state becomes the regulatory authority with primacy and issues the permits, but OSM maintains oversight. SMCRA stipulates compliance with many other major environmental statutes, including the federal Clean Air Act, Clean Water Act, Resource Conservation and Recovery Act (“RCRA”) and Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”).

SMCRA permit provisions include requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation. The permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural and historical resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology, and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mining and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mining and reclamation plan incorporates the provisions of SMCRA, the state programs, and the complementary environmental programs that affect coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land.

Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine. Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice of the proposed permit is given that also provides for a comment period before a permit can be issued. Some SMCRA mine permits may take several years or even longer to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed prior to 1977 when SMCRA came into effect. The current fee is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. New legislation passed by Congress and signed by the President in December 2006 reduces the fee to $0.315 per ton on surface-mined coal and $0.135 on deep-mined coal from 2008 to 2012, with additional reductions to $0.28 per ton on surface-mined coal and $0.12 per ton on deep-mined coal from 2013 to 2021.

Surety Bonds

Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations including mine closure or reclamation costs, federal and state workers’ compensation costs, obligations under federal coal leases and other miscellaneous obligations. Many of these bonds are renewable on a yearly basis. In recent years, surety bond premium costs have increased and the market terms of surety bonds have generally become more unfavorable. In addition, the number of companies willing to issue surety bonds has decreased. We cannot predict the ability to obtain or the cost of bonds in the future.

Clean Air Act

The Clean Air Act, the Clean Air Act Amendments and the corresponding state laws that regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 10 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, particulates, mercury and other compounds emitted by coal-fueled electricity generating plants. Power plants will likely have to continue to install pollution control technology and upgrades. Power plants may be able to recover the costs for these upgrades in the prices they charge for power, but this is not a certainty and state public utility commissions often control such rate matters. The Clean Air Act provisions and associated regulations are complex, lengthy and often being assessed for revisions or additions. In addition, one or more of the pertinent state or federal regulations issued as final are at this time, and may still continue to be, subject to current and future legal challenges in courts and the actual timing of implementation may remain uncertain. Some of the more material Clean Air Act requirements that may directly or indirectly affect our operations include the following:

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Acid Rain. Title IV of the Clean Air Act required a two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and applies to all coal-fired power plants generating greater than 25 megawatts. The affected electricity generators have sought to meet these requirements mainly by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances. The adoption of the Clean Air Interstate Rule (CAIR) in 2005 created tighter limits for sulfur dioxide and nitrogen oxides for the states covered under CAIR than currently exist under Title IV. (See “Clean Air Interstate Rule” for more information.) The cap-and-trade program under the CAIR utilizes the same allowance allocation policy developed under Title IV of the Clean Air Act. States not governed by the CAIR will continue to be subject to the regulations of Title IV. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years. At this time, we believe that implementation of Phase II has resulted in an upward pressure on the price of lower sulfur eastern coals, and more demand for western coals, as coal-fired power plants continue to comply with the more stringent restrictions of Title IV.

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Fine Particulate Matter and Ozone. The Clean Air Act requires the Environmental Protection Agency (“EPA”) to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for certain pollutants. Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels. In 1997, the EPA revised the NAAQS for particulate matter and ozone. Although previously subject to legal challenge, these revisions were subsequently upheld but implementation was delayed for several years. For ozone, these changes include replacement of the existing one-hour average standard with a more stringent eight-hour average standard in Phase 1 of the Ozone Rule. In April 2004, the EPA announced that counties in 31 states and the District of Columbia failed to meet the new eight-hour standard for ozone. On November 8, 2005, the EPA finalized Phase 2 of the Ozone Rule, which establishes the final compliance requirements and timelines upon which state, local, and tribal government will base their state implementation plans for areas designated as non-attainment. For particulates, the changes include retaining the existing standard for particulate matter with an aerodynamic diameter less than or equal to 10 microns (“PM10”), and adding a new standard for fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns (“PM2.5”). State fine particulate non-attainment designations were finalized in December 2005, and counties in 21 states and the District of

Columbia were classified as non-attainment areas. At the same time, the EPA also proposed changes to the current national air quality monitoring requirements for all criteria pollutants including particulates and revisions to the national air quality standards for fine particulate pollution, proposing more stringent requirements for this pollutant. These newly proposed standards were incorporated into the EPA’s final rule on particulate matter issued in October 2006. These standards also include making new state non-attainment designations in 2010 based on 2007-2009 air quality data; requiring these states to meet the EPA’s new PM standards by 2015. Meeting the new PM2.5 standard may require reductions of nitrogen oxide and sulfur dioxide emissions. A final rulemaking on ozone is expected in December 2007. Future regulation and enforcement of these new ozone and PM2.5 standards will affect many power plants, especially coal-fired plants and all plants in “non-attainment” areas.

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Ozone. Significant additional emissions control expenditures may be required at many coal-fired power plants to meet the current NAAQS for ozone. Nitrogen oxides, which are a by-product of coal combustion, can lead to the creation of ozone. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers may continue to become more demanding in the years ahead.

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NOx SIP Call. The NOx SIP Call program was established by the EPA in October of 1998 to reduce the transport of ozone on prevailing winds from the Midwest and South to states in the Northeast, which said they could not meet federal air quality standards because of migrating pollution. Under Phase I of the program, the EPA is requiring 90,000 tons of nitrogen oxides reductions from power plants in 22 states east of the Mississippi River and the District of Columbia beginning in May 2004. Phase II of the program, which became effective in June 2004, requires a further reduction of about 100,000 tons of nitrogen oxides per year by May 2007. Installation of additional control measures, such as selective catalytic reduction devices, required under the final rules will make it more costly to operate coal-fired electricity generating plants, thereby making coal a less attractive fuel.

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Clean Air Interstate Rule. In January 2004, the EPA proposed new rules for further reducing emissions of sulfur dioxide and nitrogen oxides. The final Clean Air Interstate Rule (CAIR) was issued by the EPA in March 2005. The rule calls for power plants in Texas and 27 states bordering or east of the Mississippi River, and the District of Columbia, to reduce emission levels of sulfur dioxide and nitrous oxide. At full implementation, CAIR is estimated by the EPA to cut regional sulfur dioxide emissions by more than 70% from the 2003 levels, and to cut nitrogen oxide emissions by more then 60% from 2003 levels. States must achieve the required emission reductions using one of two compliance options. The first alternative is for the state to require power plants to participate in an EPA administered “cap-and-trade” system that caps emissions in two stages. This cap and trade approach is similar to the system now in effect under other regulations controlling air pollution. Alternatively, a state can elect to meet a specific state emissions budget through measures of the state’s choosing. These state measures will be at least as stringent as than those imposed by CAIR. The stringency of the caps may require many coal-fired sources to install additional pollution control equipment to comply. This increased sulfur emission removal capability caused by the proposed rule could result in decreased demand for low sulfur coal, potentially driving down prices for low sulfur coal.

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Clean Air Mercury Rule. In January 2004, the EPA also proposed a mercury reduction rule for controlling mercury emissions from power plants. The proposal sought comments on two approaches for reducing mercury currently emitted each year by coal-fired power plants in the United States. EPA issued its final Clean Air Mercury Rule in March 2005. The EPA has rejected one approach which would require coal-fired power plants to install pollution controls known as “maximum achievable control technologies”, or “MACT”, under section 112 of the Clean Air Act. The approach adopted uses other provisions of the Clean Air Act and sets a mandatory, declining cap on the total mercury emissions allowed from coal-fired power plants nationwide. This “cap-and-trade” approach is similar to the approach under the CAIR rule discussed above. This approach, which allows mercury emissions trading, when combined with the CAIR regulations, will reduce mercury emissions by nearly 70% from current levels once facilities reach a final mercury cap which takes effect in 2018. Current mercury emissions from United States power plants are about 48 tons per year. The first phase cap is 38 tons beginning in 2010. EPA estimates that much of this reduction will come as a “co-benefit” of the pollution control devices installed under the CAIR regulations. The final cap is set at 15 tons per year beginning in 2018. Each state has been allocated a budget of mercury emissions and must submit a plan on meeting its budget for mercury reductions. The states are not required to adopt the cap-and-trade approach, but EPA expects most to take that approach. Alternatively, a state can elect to meet a specific state emissions budget through measures of the state’s choosing. The stringency of the caps may require many coal-fired sources to install additional pollution control equipment to comply. This increased mercury emission removal capability caused by the proposed rule could result in decreased demand for certain coals either due to higher mercury levels or more difficulty in removing the inherent mercury. In November 2006, states were required to file their state implementation plans (SIP) with the EPA for mercury compliance but only 21 states submitted plans. This prompted the EPA to designate a federal implementation plan (FIP) to be applied to states that did not file a SIP. The FIP basically requires all states without an EPA approved SIP to participate in the national cap-and-trade program. There remains some uncertainty as to how the various state implementation plans will interact with the FIP as not all the SIP’s allow for trading as does the federal plan.

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Carbon Dioxide. In 2003, certain states sued the EPA seeking a court order requiring the EPA to designate carbon dioxide as a criteria pollutant under the Clean Air Act and to issue a new NAAQS for carbon dioxide. Previously, the EPA had established that carbon dioxide is not a criteria pollutant and therefore cannot be regulated under the Clean Air Act. In 2005, a federal court upheld the EPA’s position that it was not required to regulate carbon dioxide as a pollutant. However, this matter was argued to the United States Supreme Court and a decision is expected in 2007. In addition, there are several new state programs to limit CO2 emissions and others have been proposed. There are also pending before Congress several proposals to limit CO2 emissions and other proposals may be forthcoming. Various House and Senate committees are conducting hearings into the issues surrounding climate change and the effects of CO2 emissions. Congress, or one or more states, may, at some point, regulate the release of carbon dioxide emissions as part of any green house gas initiatives that are proposed in the future. See “Climate Change” for further information.

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Regional Haze. The EPA has initiated a regional haze program designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks. The original regional haze rule required designated facilities meet the EPA’s BART standard, which requires installation of the Best Available Retrofit Technology to reduce emissions that contribute to visibility problems. In December 2006, this rule was modified to allow states the flexibility to evaluate the use of cap-and-trade programs when these programs would result in greater progress toward the EPA’s visibility goals. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could affect the future market for coal.

Climate Change

One major by-product of burning coal is carbon dioxide, which is considered a greenhouse gas and is a major source of concern with respect to global warming. In November 2004, Russia ratified the Kyoto Protocol to the 1992 Framework Convention on Global Climate Change (the “Protocol”), which establishes a binding set of emission targets for greenhouse gases. With Russia’s ratification, the Protocol received sufficient support to become binding on all those countries that have ratified it. Although the targets vary from country to country, if the United States were to ratify the Protocol, the United States would be required to reduce greenhouse gas emissions to 93% of 1990 levels from 2008 to 2012. In 2002, President Bush reaffirmed U.S. support for the Framework Convention but the U.S. Senate did not ratify the Kyoto Protocol because, among other reasons, it did not require emissions reduction from all countries. Many of the countries which did ratify the Protocol are not on target to meet the mandated reductions in carbon dioxide, and as such a new or modified international protocol to regulate carbon dioxide emissions may be proposed in the future.

Future regulation of greenhouse gases in the United States could occur pursuant to future United States treaty obligations, statutory or regulatory changes under the Clean Air Act, or otherwise at the state and federal level. The Bush Administration has proposed a package of voluntary emission reductions for greenhouse gases reduction targets which provide for certain incentives if targets are met. There are also various federal, state and local legislative initiatives aimed at tracking or regulating, both on a mandatory or voluntary basis, the release of carbon dioxide from generating power and other commercial activity. In 2002, the Conference of New England Governors and Eastern Canadian Premiers adopted a Climate Change Action Plan, calling for reduction in regional greenhouse emissions to 1990 levels by 2010, and a further reduction of at least 10% below 1990 levels by 2020. Currently several state groups are working on regional plans to address climate and energy issues. The 110th Congress has been active in promoting greenhouse gas legislation with several separate bills already being presented and others possible. There are a number of uncertainties regarding these and additional initiatives which may be proposed. In addition to the timing for implementing any new legislation, open issues include matters such as the applicable baseline of emissions to be permitted, initial allocations of any emission allowances, required emissions reductions, availability of offsets to emissions such as planting trees, the extent to which additional states will adopt the programs, whether they will be linked with programs in other states or countries. Increased efforts to control greenhouse gas emissions, including the future ratification of the Protocol by the United States could result in reduced demand for coal.

Clean Water Act

The Clean Water Act of 1972 (the “CWA”) and corresponding state laws affect coal mining operations by imposing restrictions on the discharge of certain pollutants into water and on dredging and filling wetlands. The CWA establishes in-stream water quality standards and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, as well as compliance with reporting requirements and performance standards, is preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water.

Permits under Section 404 of the CWA are required for coal companies to conduct dredging or filling activities in jurisdictional waters for the purpose of creating slurry ponds, water impoundments, refuse disposal areas, valley fills or other mining activities. Jurisdictional waters typically include ephemeral, intermittent, and perennial streams and may in certain instances include man-made conveyances that have a hydrologic connection to a stream or wetland. Presently, under the Stream Buffer Zone Rule, mining disturbances are prohibited within 100 feet of streams if negative effects on water quality are expected. OSM has proposed changes to

this rule, which would make exemptions available if mine operators take steps to reduce the amount of waste and its effect on nearby waters. Legislation in Congress has been introduced in the past and may be introduced in the future in an attempt to preclude placing any mining material in streams. Such legislation would have a material adverse impact on future ability to conduct certain types of mining.

The Corps of Engineers (the “COE”) is empowered to issue nationwide permits for specific categories of filling activity that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404. Nationwide Permit 21 authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. On October 23, 2003, several citizens groups sued the COE in the United States District Court for the Southern District of West Virginia seeking to invalidate nationwide permits utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. The plaintiffs sought to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators from additional use of existing nationwide permit approvals until they obtain more detailed individual permits. On July 8, 2004, the court issued an order enjoining the further issuance of Nationwide 21 permits and rescinded certain listed permits where construction of valley fills and surface impoundments had not commenced. On August 13, 2004, the court extended the ruling to all Nationwide 21 permits within the Southern District of West Virginia. The United States Department of Justice appealed the decision to the United States Court of Appeals for the Fourth Circuit. In November 2005, the 4^th Circuit Court of Appeals overturned the July 2004 decision, thereby allowing the continued use of the NWP 21 permitting process. A similar challenge to the Nationwide 21 permit process was filed in Kentucky. Although we have no current operations in Kentucky, similar suits may be filed in other jurisdictions where we do operate. Further uncertainty over the issuance by the COE of Section 404 permits for mining operations was created by the June 2006 decision of the United States Supreme Court in Rapanos v. United States. In this case the court limited the situations over which the COE has authority to regulate impacts on water by narrowing the definition of “waters of the United States” subject to COE jurisdiction. In response to this decision it is not yet certain what, if any, changes to COE permitting procedures will take place.

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

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

Federal and state laws and regulations can also impose measures to be taken to minimize and\or avoid altogether stream impacts caused by both surface and underground mining. Temporary stream impacts from mining are not uncommon, but when such impacts occur there are procedures we follow to remedy any such impacts. These procedures have generally been effective and we work closely with applicable agencies to implement them. Our inability to remedy any temporary stream impacts in the future, and the application of existing or new laws and regulations to disallow any stream impacts, could adversely affect our operating and financial results.

Endangered Species Act

The Federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.

Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act (“RCRA”) affects coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. Certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management.

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

impoundments and landfills and used as mine-fill. The agency also concluded beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. As long as this exemption remains in effect, it is not anticipated that regulation of coal combustion waste will have any material effect on the amount of coal used by electricity generators. Most state hazardous waste laws also exempt coal combustion waste, and instead treat it as either a solid waste or a special waste. Any costs associated with handling or disposal of coal construction wastes as hazardous wastes would increase our customers’ operating costs and potentially reduce their demand for coal. In addition, contamination caused by the past disposal of ash can lead to material liability a consideration which could reduce demand for coal.

Federal and State Superfund Statutes

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

Additional Information

We file annual, quarterly and current reports, amendments to these reports and other information with the United States Securities and Exchange Commission (“SEC”). You may access and read our SEC filings through our website, at www.foundationcoal.com, or the SEC’s website at www.sec.gov. All documents we file are also available at the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549.

GLOSSARY OF SELECTED TERMS

Ash. Impurities consisting of iron, alumina and other incombustible matter that are contained in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the burning characteristics of coal.

Assigned reserves. Coal that has been committed to be mined at operating facilities.

Bituminous coal. A common type of coal with moisture content less than 20% by weight and heating value of 10,500 to 14,000 Btus per pound. It is dense and black and often has well-defined bands of bright and dull material.

British thermal unit, or “Btu”. A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

Central Appalachia. Coal producing area in eastern Kentucky, Virginia, southern West Virginia and a portion of eastern Tennessee.

Clean Air Act Amendments. A comprehensive set of amendments to the federal law governing the nation’s air quality. The Clean Air Act was originally passed in 1970 to address significant air pollution problems in our cities. The 1990 amendments broadened and strengthened the original law to address specific problems such as acid deposition, urban smog, hazardous air pollutants and stratospheric ozone depletion.

Coal seam. Coal deposits occur in layers. Each layer is called a “seam.”

Coke. A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel. Its production results in a number of useful byproducts.

Compliance coal. Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu, as required by Phase II of the Clean Air Act.

Continuous miner. A machine which constantly extracts coal while loading. This is to be distinguished from a conventional mining unit which must stop the extraction process in order for loading to commence.

Continuous mining. Any coal mining process which tears the coal from the face mechanically and loads continuously, thus eliminating the separate cycles of cutting, drilling, shooting and loading. This is to be distinguished from conventional mining, an older process in which these operations are cyclical.

Fossil fuel. Fuel such as coal, petroleum or natural gas formed from the fossil remains of organic material.

High Btu coal. Coal which has an average heat content of 12,500 Btus per pound or greater.

Illinois Basin. Coal producing area in Illinois, Indiana and western Kentucky.

Lignite. The lowest rank of coal with a high moisture content of up to 45% by weight and heating value of 6,500 to 8,300 Btus per pound. It is brownish black and tends to oxidize and disintegrate when exposed to air.

Longwall mining. The most productive underground mining method in the United States. A rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the roof of the mine while it advances through the coal. Chain conveyors then move the loosened coal to a standard underground mine conveyor system for delivery to the surface.

Low Btu coal. Coal which has an average heat content of 9,500 Btus per pound or less.

Low sulfur coal. Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btu.

Medium sulfur coal. Coal which, when burned, emits between 1.6 and 4.5 pounds of sulfur dioxide per million Btu.

Metallurgical coal. The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as “met” coal, its quality depends on four important criteria: volatility, which affects coke yield; the level of impurities including sulfur and ash, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Met coal typically has a particularly high Btu but low ash and sulfur content.

Mid Btu coal. Coal which has an average heat content of between 9,500 and 12,500 Btus per pound.

Nitrogen oxide (NOx). A gas formed in high temperature environments such as coal combustion. It is a harmful pollutant that contributes to smog.

Northern Appalachia. Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.

Overburden. Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

Pillar. An area of coal left to support the overlying strata in a mine; sometimes left permanently to support surface structures.

Powder River Basin. Coal producing area in northeastern Wyoming and southeastern Montana. This is the largest known source of coal reserves and the largest producing region in the United States.

Preparation plant. Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to remove impurities and prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content.

Probable reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven 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 reserves, is high enough to assume continuity between points of observation.

Proven reserves. Reserves for which: (a) 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 (b) 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.

Reclamation. The process of restoring land and the environment to their original state following mining activities. The process commonly includes “recontouring” or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually underway before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law.

Reserve. That part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination.

Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place.

Room-and-Pillar Mining. Method of underground mining in which the mine roof is supported mainly by coal pillars left at regular intervals. Rooms are placed where the coal is mined.

Scrubber (flue gas desulfurization system). Any of several forms of chemical/physical devices which operate to neutralize sulfur compounds formed during coal combustion. These devices combine the sulfur in gaseous emissions with other chemicals to form inert compounds, such as gypsum, that must then be removed for disposal. Although effective in substantially reducing sulfur from combustion gases, scrubbers require about 6% to 7% of a power plant’s electrical output and thousands of gallons of water to operate.

Steam coal. Coal used by power plants and industrial steam boilers to produce electricity, steam or both. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

Sub-bituminous coal. Dull coal that ranks between lignite and bituminous coal. Its moisture content is between 20% and 30% by weight, and its heat content ranges from 7,800 to 9,500 Btus per pound of coal.

Sulfur. One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product of coal combustion.

Surface mine. A mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil (see “Overburden”). About 67% of total U.S. coal production comes from surface mines.

Tons. A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is equal to 2,240 pounds; a “metric” tonne is approximately 2,205 pounds. The short ton is the unit of measure referred to in this document.

Truck-and-Shovel mining and Truck and Front-End Loader Mining. Similar forms of mining where large shovels or front-end loaders are used to remove overburden, which is used to backfill pits after the coal is removed. Smaller shovels load coal in haul trucks for transportation to the preparation plant or rail loadout.

Unassigned reserves. Coal at suspended locations and coal that has not been committed to be mined at operating facilities.

Underground mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car and conveyor to the surface. Underground mines account for about 33% of annual U.S. coal production.

Unit train. A train of 100 or more cars carrying only coal. A typical unit train can carry at least 10,000 tons of coal in a single shipment.

Western Bituminous Region. Coal producing area in western Colorado and eastern Utah.

ITEM 1A.

RISK FACTORS.

RISK FACTORS

Risks Relating to Our Business

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

The prices we charge for coal depend upon factors beyond our control, including, but not limited to:

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the supply of, and demand for, domestic and foreign coal;

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the demand for electricity;

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

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

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domestic and foreign governmental regulations and taxes;

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air emission and other regulatory standards for coal-fired power plants;

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costs of transportation of our coal relative to our competitors;

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regulatory, administrative and court decisions;

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

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the effect of worldwide energy conservation measures; and

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continuation of other revenues from fees received from synthetic fuel (“synfuel”) processors.

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disruptions in delivery or changes in pricing from third party vendors of goods and services which are necessary for our operations, such as fuel, steel products, explosives and tires.

Our results of operations are dependent upon the prices we charge for our coal as well as our ability to improve productivity and control costs. Any decreased demand would cause spot prices to decline and require us to increase productivity and decrease costs in order to maintain our margins. If we are not able to maintain our margins, our operating results could be adversely affected. Therefore, price declines may adversely affect operating results for future periods and our ability to generate cash flows necessary to improve productivity and invest in operations.

Any adverse change in coal consumption patterns by North American electric power generators or steel producers could result in weaker demand and possibly lower prices for our production, which would reduce our revenues.

During 2006, sales of steam coal accounted for approximately 97% of our total coal sales volume and 91% of our coal sales revenue, respectively, and the vast majority of our sales of steam coal were to U.S. electric power generators. Based on preliminary estimates, domestic electric power generation accounted for approximately 92% of all U.S. coal consumption in 2006, according to the EIA. The amount of coal consumed for U.S. electric power generation is affected primarily by the overall demand for electricity, the location, availability, quality and price of competing fuels such as natural gas, nuclear, fuel oil and alternative energy sources such as solar, wind and hydroelectric power, technological developments and environmental and other governmental regulations. Many of the recently constructed electric power sources have been gas-fired, by virtue of lower construction costs and reduced environmental risks. Gas-based generation from existing and newly constructed gas-based facilities has the potential to displace coal-based generation, particularly from older, less efficient coal generators. In addition, the increasingly stringent requirements of the Clean Air Interstate Rule and Clean Air Mercury Rule may result in more electric power generators shifting from coal to natural gas-fired power plants. Any reduction in coal demand from the electric generation and steel sectors could create short-term market imbalances, leading to lower demand for, and price of, our products, thereby reducing our revenue.

Our profitability may decline due to unanticipated mine operating conditions and other factors that are not within our control.

Our mining operations are influenced by changing conditions that can affect production levels and costs at particular mines for varying lengths of time and as a result can diminish our profitability. Weather conditions, equipment and parts availability, replacement or repair, prices and availability for fuel, steel, explosives, tires and other supplies, fires, variations in thickness of the layer, or seam, of coal, amounts of overburden partings, rock and other natural materials, accidental mine water discharges and other geological conditions have had, and can be expected in the future to have, a significant impact on our operating results.

Decreases in our profitability as a result of the factors described above could materially adversely impact our quarterly or annual results. These risks may not be covered by our insurance policies.

MSHA and state regulators may order certain of our mines to be temporarily closed or operations therein modified, which would adversely affect our ability to meet our contracts or projected costs.

MSHA and state regulators may order certain of our mines to be temporarily closed due to an investigation of an accident resulting in property damage or injuries, or due to other incidents such as fires, roof falls, water flow, equipment failure or ventilation concerns. In addition, regulators may order changes to mine plans or operations due to their interpretation or application of existing or new laws or regulations. Any required changes to mine plans or operations may result in temporary idling of production or addition of costs.

Our profitability may be adversely affected by the status of our long-term coal supply contracts, and changes in purchasing patterns in the coal industry may make it difficult for us to extend existing contracts or enter into long-term supply contracts, 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 we define as contracts with a term greater than 12 months. The prices for coal shipped under these contracts are set although sometimes subject to adjustment, and thus may be below the current market price for similar-type coal at any given time, depending on the time frame of contract execution or initiation. As a consequence of the substantial volume of our sales that are subject to these long-term agreements, we have less coal available with which to capitalize on higher coal prices if and when they arise. In addition, in some cases, our ability to realize the higher prices that may be available in the spot market may be restricted when customers elect to purchase higher volumes allowable under some contracts.

When our current contracts with customers expire or are otherwise renegotiated, our customers may decide not to extend or enter into new long-term contracts or, in the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including under different pricing terms. For additional information relating to these contracts, see “Business—Long-Term Coal Supply Agreements”.

As electric utilities adjust to the regulations of the Clean Air Act, the Clean Air Mercury Rule, the Clean Air Interstate Rule, possible regulation of greenhouse gas emissions and the possible deregulation of their industry, they could become increasingly less willing to enter into long-term coal supply contracts and instead may purchase higher percentages of coal under short-term supply contracts. To the extent the industry shifts away from long-term supply contracts, it 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. Furthermore, spot market prices tend to be more volatile than contractual prices, which could result in decreased or less predictable revenues.

Certain provisions in our long-term supply contracts may provide limited protection during adverse economic conditions or may result in economic penalties upon the 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 such contracts. Some of our coal supply contracts contain provisions that allow for the purchase price to be renegotiated at periodic intervals. These 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. 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 our customers for 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, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or, in the extreme, termination of the contracts. With respect to sulfur, the price of S0 ₂ allowances in the market is sometimes used to adjust the price we receive for coal and the market price for these allowances may fluctuate and cause us not to receive the anticipated revenues.

Consequently, due to the risks mentioned above with respect to long-term contracts, we may not achieve the revenue or profit we expect to achieve from these sales commitments. In addition, we may not be able to successfully convert these sales commitments into long-term contracts.

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

We derived 49% of our total coal revenues from sales to our 10 largest customers for the year ended December 31, 2006, with no single customer accounting for more than 10% of our coal revenues for that year. At December 31, 2006, we had 30 coal supply agreements with those 10 customers that expire at various times from 2007 to 2020. Negotiations to extend existing agreements or enter into new long-term agreements with those and other customers may not be successful, and those customers may not continue to purchase coal from us under long-term coal supply agreements, or at all. If any of our top customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our revenues and profitability could suffer materially.

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

In addition to marketing coal that is produced from our controlled reserves, we purchase and resell coal produced by third parties from their controlled reserves to meet customer specifications and, in certain circumstances, we also at times utilize contractors to operate our mines or loading facilities. Disruption in our supply of third-party coal and contractor-produced 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. 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 by contractors for us. Any increase in the prices we pay for third-party coal or contractor-produced coal could increase our costs and therefore lower our earnings. During 2006, less than one percent of the coal we produced was mined by contract miners.

Competition within the coal industry may adversely affect our ability to sell coal.

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

Demand for our high sulfur coal and the price that we can obtain for it is impacted by, among other things, the changing laws with respect to allowable emissions and the price of emission allowances. Significant increases in the price of those allowances could reduce the competitiveness of high sulfur coal at plants not equipped to reduce sulfur dioxide emissions. Competition from low sulfur coal and possibly natural gas could result in a decrease in our high-sulfur coal market share and revenues from those operations.

Overcapacity in the coal industry, both domestically and internationally, may affect the price we receive for our coal. For example, during the 1970s and early 1980s, increased demand for coal and attractive pricing brought new investors to the coal industry and promoted the development of new mines. These factors resulted in added production capacity throughout the industry, which led to increased competition and lower coal prices. Continued coal pricing at relatively high levels, compared to historical levels, could encourage the development of expanded capacity by new or existing coal producers. Any overcapacity could reduce coal prices in the future.

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, ocean freight 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. If foreign demand for U.S. coal were to decline, this decline could cause competition among coal producers in the United States to intensify, potentially resulting in downward pressure on domestic coal prices.

Our enterprise software will cease to properly process information during the second quarter of 2007. We are currently replacing our enterprise software. The failure to timely replace the enterprise software may result in resorting to manual reporting processes that have not been planned, designed or tested.

We are in the process of replacing our enterprise software that we use for financial reporting and controls, equipment maintenance and materials management. The current enterprise software will cease to properly process information during the latter part of the second quarter of 2007. Outside consultants are assisting in the design and implementation of the new enterprise system. The new enterprise system is sold by a company with a large market share and with specific applications in the mining industry. We have completed the overall planning and design and have substantially completed the testing phases. We are well into the training and deployment phases and expect to go live with the new enterprise software during the second quarter of 2007.

An enterprise system failure could cause disruptions in our operations, including among other things, the inability to process orders for supplies and services, make payments to our vendors or engage in similar normal business activities. If the enterprise system replacement is not successfully implemented in a timely manner, the Company will have to resort to manual reporting processes that have not been planned, designed or tested.

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

Our operations are subject to a variety of federal, state and local environmental, health and safety, transportation, labor and other laws and regulations. Examples include those relating to employee health and safety; emissions to air and discharges to water; plant and wildlife protection; the reclamation and restoration of mining properties after mining has been completed; the storage, treatment and disposal of wastes; remediation of contaminated soil, surface and groundwater; surface subsidence from underground mining; and the effects of mining on surface water and groundwater quality and availability. In addition, we are subject to significant legislation mandating certain benefits for current and retired coal miners. We incur substantial costs to comply with government laws and regulations that apply to our operations.

Numerous governmental permits and approvals are required under these laws and regulations for mining operations. Many of our permits are subject to renewal from time to time, and renewed permits may contain more restrictive conditions than our existing permits. Many of our permits governing discharges to or impacts upon surface streams will be subject to new and more stringent conditions to address various new water quality requirements that permitting authorities are now required to address when those permits are renewed over the next several years. Although we have no estimates at this time, our costs to satisfy such conditions could be substantial. We may also be required under certain permits to provide authorities data pertaining to the effect or impact that a proposed exploration for or production of coal may have on the environment. In recent years, the permitting required under the Clean Water Act to address filling streams and other valleys with wastes from mountaintop coal mining operations and preparation plant refuse disposal has been the subject of extensive litigation by environmental groups against coal mining companies and environmental regulatory authorities, as well as regulatory changes by the U.S. legislative initiatives in the U.S. Congress. It is unclear at this time how the issues will ultimately be resolved, but for this as well as other issues that may arise involving permits necessary for coal mining, such requirements could prove costly and time-consuming, and could delay commencing or continuing exploration or production operations. New laws and regulations, as well as future interpretations or different enforcement of existing laws and regulations, may require substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which we cannot predict.

Because of extensive and comprehensive regulatory requirements, violations of laws, regulations and permits during mining operations occur at our operations from time to time and may result in significant costs to us to correct such violations, as well as civil or criminal penalties and limitations or shutdowns of our operations.

Extensive regulation of these matters has had and will continue to have a significant effect on our costs of production and competitive position. Further regulations, legislation or enforcement may also cause our sales or profitability to decline by hindering our ability to continue our mining operations, by increasing our costs or by causing coal to become a less attractive fuel source.

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

We use, and in the past have used, hazardous materials and generate, and in the past have generated, hazardous wastes. In addition, many of the locations that we own or operate were used for coal mining and/or involved hazardous materials usage before we were involved with those locations as well as after. We may be subject to claims under federal and state statutes, and/or common law doctrines, for toxic torts, natural resource damages, and other damages as well as the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of current or former conditions at sites that we own or operate currently, as well as at sites that we or predecessor entities owned or operated in the past, and at contaminated sites that have always been owned or operated by third parties. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share. We have from time to time been subject to claims arising out of contamination at our own and other facilities and may incur such liabilities in the future.

Mining operations can also impact flows and water quality in surface water bodies and remedial measures may be required, such as grouting in lining of stream beds, to prevent or minimize such impacts. We are currently involved with state environmental authorities concerning impacts or alleged impacts of our mining operations on water flows in several surface streams. We are studying, or addressing, those impacts and we have not finally resolved those matters. Many of our mining operations take place in the vicinity of streams, and similar impacts could be asserted or identified at other streams in the future. The costs of our efforts at the streams we are currently addressing, and at any other streams that may be identified in the future, could be significant.

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

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

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

The Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. Such regulations may require significant emissions control expenditures for existing and new coal-fired power plants to attain applicable ambient air quality standards. In addition, state regulatory schemes for electricity pricing are increasingly administered to not permit recovery of investments in emissions control equipment. As a result, these generators may switch to fuels that generate less of these emissions, possibly reducing the likelihood that generators will keep existing coal-fired power plants in service or build new coal-fired power plants. Any of these developments may reduce demand for our coal.

For example, the Clean Air Interstate Rule was issued by the Environmental Protection Agency (the “EPA”) in May 2005 imposing new regulations regarding further reductions of sulfur dioxide and nitrogen oxide emissions from coal-fired power plants. In December 2005, the EPA announced a decision to reconsider specific issues and asked for comments; final decisions on these issues were effective June 27, 2006 and in March 2006 the EPA posted its final decision to allow the Clean Air Interstate Rule to stand as originally written except adding a specific Federal Implementation Plan for those states that do not file State Implementation Plans and adding Delaware and New Jersey to the list of states covered under the fine particulate matter portion of the rule. Installation of additional pollution control equipment required by this rule could result in a decrease in the demand for low sulfur coal, potentially driving down prices for low sulfur coal. Also, in March 2005, the EPA finalized a Clean Air Mercury Rule (originally proposed as the Utility Mercury Reductions Rule) for controlling mercury emissions from power plants by imposing a two-step approach to reducing, between now and 2018, the total mercury emissions allowed from coal-fired power plants nationwide. These standards and future standards imposed by state and federal authorities could have the effect of making coal-fired plants unprofitable, thereby decreasing demand for coal. Some 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. These factors and legislation, if enacted, could have a material adverse effect on our financial condition and results of operations or cash flow.

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

The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which is intended to limit emissions of greenhouse gases, such as carbon dioxide which is a major by-product of burning coal. In December 1997, in Kyoto, Japan, the signatories to the convention agreed to the Kyoto Protocol (the “Protocol”) which is a binding set of emission targets for developed nations. Although the specific emission targets vary from country to country, if the United States were to ratify the Protocol, our nation would be required to reduce emissions to 93% of 1990 levels over a five-year period from 2008 through 2012. The United States has not ratified the Protocol. The Protocol has received sufficient support from enough nations to enter into force and will become binding on all those countries that have ratified it. Although the Protocol is still not binding on the United States, and no comprehensive regulations focusing on greenhouse gas emissions are in place, these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely affect the price and demand for coal. Countries that have to reduce emissions may use less coal affecting demand for United States export coal. There could be pressure on companies in the United States to reduce emissions if they want to trade with countries that are part of the Protocol. From time to time Congress may consider various proposals to tax or otherwise limit greenhouse gas emissions. In addition, some states and municipalities in the United States have adopted or may adopt in the future regulations on greenhouse gas emissions. Some states and municipal entities have commenced litigation in different jurisdictions seeking to have certain utilities, including some of our customers, reduce their emission of carbon dioxide. If successful, there could be limitation on the amount of coal our customers could utilize. Future regulation of greenhouse gas emissions may be implemented as part of or distinct from the Protocol. Any of these measures could affect coal demand at utilities in the United States. See “Business—Environmental and Other Regulatory Matters” for a discussion of environmental and other regulations affecting our business.

Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenues by causing us to reduce our production or impairing our ability to supply coal to our customers.

Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources.

Some of our mines depend on a single transportation carrier or a single mode of transportation. Disruption of any of these transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair our ability to supply coal to our customers. Our transportation providers may face difficulties in the future that may impair our ability to supply coal to our customers, resulting in decreased revenues.

If there are disruptions of the transportation services provided by our primary rail or barge carriers that transport our produced coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

West Virginia legislation, which raised coal truck weight limits, includes provisions supporting enhanced enforcement. The legislation went into effect on October 1, 2003 and implementation began on January 1, 2004. It is possible that other states in which our coal is transported by truck will modify their laws to limit truck weight limits. Such legislation 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 and could adversely affect revenues.

Because our profitability is substantially dependent on the availability of an adequate supply of coal reserves that can be mined at competitive costs, the unavailability of these types of reserves would cause our profitability to decline.

We have not yet applied for all of the permits required, or developed the mines necessary, to use all of our reserves. Furthermore, we may not be able to mine all of our reserves as profitably as we do at our current operations. Our planned development projects and acquisition activities may not result in significant additional reserves and we may not have continuing success developing new mines or expanding existing mines beyond our existing reserves. Most of our mining operations are conducted on properties owned or leased by us. Because title to most of our leased properties and mineral rights is not thoroughly verified until a permit to mine the property is obtained, our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In addition, in order to develop our reserves, we must receive various governmental permits. We may be unable to obtain the permits necessary for us to operate profitably in the future. Some of these permits are becoming increasingly more difficult and expensive to obtain and the review process continues to lengthen.

Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by our customers. 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. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our profitability and financial condition. 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 obtain other reserves through acquisitions in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

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

We base our reserve information on engineering, economic and geological data assembled and analyzed by our staff, which includes various engineers and geologists, and which is periodically reviewed by outside firms. The reserve estimates as to both quantity and quality are annually updated to reflect production of coal from the reserves and new drilling, engineering or other data received. There are numerous uncertainties inherent in estimating 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, such as geological and mining conditions which may not be fully identified by available exploration data or which may differ from experience in current operations, historical production from the area compared with production from other similar producing areas, the assumed effects of regulation and taxes by governmental agencies and assumptions concerning coal prices, operating costs, mining technology improvements, severance and excise tax, development costs and reclamation costs, all of which may vary considerably from actual results.

For these reasons, estimates of the economically recoverable quantities and qualities attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of net cash flows expected from particular reserves prepared by different engineers or by the same engineers at different times may vary substantially. Actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our reserves may vary materially from estimates. These estimates thus may not accurately reflect our actual reserves. Any inaccuracy in our estimates related to our reserves could result in lower than expected revenues, higher than expected costs or decreased profitability.

Defects in title or loss 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. A title defect or the loss of any lease could adversely affect our ability to mine the associated reserves. In addition, from time to time the rights of third parties for competing uses of adjacent, overlying, or underlying lands such as for oil and gas activity, coalbed methane, production, pipelines, roads, easements and public facilities may affect our ability to operate as planned if our title is not superior or arrangements cannot be negotiated. Title to much of our leased properties and fee mineral rights is not usually verified until we make a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. Our right to mine some of our reserves has in the past been, and may again in the future be, adversely affected if defects in title or boundaries exist or competing interests cannot be resolved. In order to obtain leases or other rights to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs or leave un-mined the affected reserves. In addition, we may not be able to successfully purchase or negotiate new leases for properties containing additional reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease.

Acquisitions that we may undertake would involve a number of inherent risks, any of which could cause us not to realize the benefits anticipated to result.

Our strategy includes opportunistically expanding our operations and coal reserves through acquisitions of businesses and assets, mergers, joint ventures or other transactions. Such transactions involve various inherent risks, such as:

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

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

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the inability to achieve identified operating and financial synergies anticipated to result from an acquisition or other transaction;

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

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unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the acquisition or other transaction rationale.

Any one or more of these and other factors could cause us not to realize the benefits anticipated to result from the acquisition of businesses or assets or could result in unexpected liabilities associated with the acquired businesses.

Expenditures for benefits for non-active employees could be materially higher than we have anticipated, which could increase our costs and adversely affect our financial results.

We are responsible for certain long-term liabilities under a variety of benefit plans and other arrangements with active and inactive employees. The unfunded status (the excess of projected benefit obligation over plan assets) of these obligations, as reflected in Note 14 to our consolidated financial statements at December 31, 2006, included $552.7 million of postretirement obligations, $43.6 million of defined benefit pension obligations, $31.8 million of workers’ compensation obligations and $10.9 million of self-insured pneumoconiosis obligations. These obligations have been estimated based on assumptions including actuarial estimates, assumed discount rates, estimates of mine lives, expected returns on pension plan assets and changes in health care costs. We could be required to expend greater amounts than anticipated. In addition, future regulatory and accounting changes relating to these benefits could result in increased obligations or additional costs, which could also have a material adverse affect on our financial results. Several states in which we operate consider changes in workers’ compensation laws from time to time, which, if enacted, could adversely affect us.

The inability of the sellers of companies we have acquired 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 our acquisition and disposition agreements, the respective sellers and buyers, and in some cases, their parent companies, agreed to retain responsibility for and indemnify us against damages resulting from certain third-party claims or other liabilities. These third-party claims and other liabilities include, without limitation, employee liabilities, costs associated with various litigation matters related to the mines involved, and certain environmental liabilities. The failure of any seller or buyer and, if applicable, its parent company, to satisfy its obligations with respect to claims and retained liabilities covered by the relevant agreements could have an adverse effect on our results of operations and financial position because claimants may successfully assert that we are liable for those claims and /or retained liabilities. In addition, certain obligations of the sellers to indemnify us will terminate or have already terminated upon expiration of the applicable indemnification period 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 leverage could harm our business by limiting our available cash and our access to additional capital, and could force us to sell material assets or operations to attempt to meet our debt service obligations.

Our financial performance could be affected by our indebtedness. As of December 31, 2006, our total indebtedness was $626.6 million. In addition, as of December 31, 2006, we had $168.8 million of letters of credit outstanding and additional borrowings available under our new revolving credit facility of $331.2 million. We may also incur additional indebtedness in the future.

The degree to which we are leveraged could have important consequences, including, but not limited to:

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

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

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increasing our vulnerability to general adverse economic and industry conditions;

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requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal of, and interest on, our indebtedness, thereby reducing the availability of the cash flow to fund working capital, capital expenditures, research and development or other general corporate uses;

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

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making it more difficult for us to pay interest and satisfy our debt obligations;

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

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

In addition, our indebtedness subjects us to financial and other restrictive covenants. Failure by us to comply with these covenants could result in an event of default which, if not cured or waived, could have a material adverse effect on us. Furthermore, substantially all of our material assets secure our indebtedness under our Senior Secured Credit Facility.

If our cash flows and capital resources are insufficient to fund our debt service obligations or our requirements under our other long-term liabilities, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations or our requirements under our other long-term liabilities. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our Senior Secured Credit Facility and the indenture under which our 7.25% Senior Notes were issued restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.

If our business does not generate sufficient cash from operations, we may not be able to repay our indebtedness.

Our ability to pay principal and interest on and to refinance our debt depends upon the operating performance of our subsidiaries, which will be affected by, among other things, general economic, financial, competitive, legislative, regulatory and other factors, some of which are beyond our control. In particular, economic conditions could cause the price of coal to fall, our revenue to decline, and hamper our ability to repay our indebtedness.

Our business may not generate sufficient cash flow from operations and future borrowings may not be available to us under our credit facility or otherwise in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms, on terms acceptable to us or at all.

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

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our indebtedness do not prohibit the Company or our subsidiaries from doing so. If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

The covenants in our Senior Secured Credit Facility and our indenture impose restrictions that may limit our operating and financial flexibility.

The Senior Secured Credit Facility, our indenture governing the 7.25% Senior Notes and the instruments governing our other indebtedness contain a number of significant restrictions and covenants that limit the ability of our subsidiaries to enter into certain financial arrangements or engage in specified transactions, including the payment of certain dividends.

Operating results below current levels or other adverse factors, including a significant increase in interest rates, could result in our being unable to comply with our financial covenants contained in our Senior Secured Credit Facility. If we violate these covenants and are unable to obtain waivers from our lenders, our debt under these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are 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. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.

Failure to maintain required surety bonds could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease the coal. Failure to maintain capacity for required letters of credit could limit our available borrowing capacity under our Senior Secured Credit Facility and could negatively impact our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements.

We are required to provide financial assurance to secure our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation benefits, to secure coal lease obligations and to satisfy other miscellaneous obligations. We generally use surety bonds to secure reclamation and coal lease obligations. We generally use letters of credit to assure workers’ compensation benefits, United Mine Workers of America (“UMWA”) retiree medical benefits and as collateral for surety bonds. Miscellaneous obligations are secured using both surety bonds and letters of credit.

As of December 31, 2006, we had outstanding surety bonds of $261.4 million, which includes $237.5 million secured reclamation obligations, $12.6 million secured coal lease obligations $9.6 million secured self-insured workers’ compensation obligations; and $1.7 million secured miscellaneous obligations. The premium rates and terms of the surety bonds are subject to annual renewals. It has become increasingly difficult for us to secure new surety bonds or renew bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. Our failure to maintain, or 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 the coal. That failure could result from a variety of factors including the following:

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

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restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of the indenture or new credit facilities.

In addition, as of December 31, 2006, we had $168.8 million of letters of credit in place for the following purposes: $36.6 million for workers’ compensation, including collateral for workers’ compensation bonds; $23.4 million for UMWA retiree health care obligations; $102.2 million for collateral for reclamation surety bonds; and $6.6 million for other miscellaneous obligations. Obligations secured by letters of credit may increase in the future. Any such increase would limit our available borrowing capacity under the Senior Secured Credit Facility and could negatively impact our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements.

Due to our participation in multi-employer pension plans, we may have exposure under those plans that extend beyond what our obligation would be with respect to our employees.

We contribute to two multi-employer defined benefit pension plans administered by the UMWA. In 2006, our total contributions to these plans and other contractual payments under our UMWA wage agreement were approximately $1.4 million.

In the event of a partial or complete withdrawal by us from any plan which is underfunded, we would be liable for a proportionate share of such plan’s unfunded vested benefits. Based on the limited information available from plan administrators, which we cannot independently validate, we believe that our portion of the contingent liability in the case of a full withdrawal or termination would be material to our financial position and results of operations. In the event that any other contributing employer withdraws from any plan which is underfunded, and such employer (or any member in its controlled group) cannot satisfy its obligations under the plan at the time of withdrawal, then we, along with the other remaining contributing employers, would be liable for our proportionate share of such plan’s unfunded vested benefits.

In addition, if a multi-employer plan fails to satisfy the minimum funding requirements, the Internal Revenue Service, pursuant to Section 4971 of the Internal Revenue Code (the “Code”) will impose an excise tax of 5% on the amount of the accumulated funding deficiency. Under Section 413(c)(5) of the Code, the liability of each contributing employer, including us, will be determined in part by each employer’s respective delinquency in meeting the required employer contributions under the plan. The Code also requires contributing employers to make additional contributions in order to reduce the deficiency to zero, which may, along with the payment of the excise tax, have a material adverse impact on our financial results.

Our pension plans are currently underfunded and we may have to make significant cash payments to the plans, reducing the cash available for our business.

We sponsor pension plans in the United States for salaried and non-union hourly employees. In 2006, we contributed $12.2 million to our pension plans. We currently expect to make contributions in 2007 of approximately $9.7 million. If the performance of the assets in our pension plans does not meet our expectations, or if other actuarial assumptions are modified, our contributions for those years could be higher than we expect.

As of September 30, 2006, our annual measurement date, our pension plans were underfunded by $43.6 million (based on the actuarial assumptions used for Statement of Financial Accounting Standards (“SFAS”) No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS No. 158”). Our pension plans are subject to the Employee Retirement Income Security Act of 1974 (“ERISA”). Under ERISA, the Pension Benefit Guaranty Corporation, or PBGC, has the authority to terminate an underfunded pension plan under limited circumstances. In the event our U.S. pension plans are terminated for any reason while the plans are underfunded, we will incur a liability to the PBGC that may be equal to the entire amount of the underfunding.

Our financial condition could be negatively affected if we fail to maintain satisfactory labor relations.

As of December 31, 2006, the UMWA represented approximately 39% of our affiliate’s employees, who produced approximately 21% of our coal sales volume during the fiscal year ended December 31, 2006. The mines represented by the UMWA include Emerald and Cumberland longwall mines in Pennsylvania and the Wabash room-and-pillar in Illinois. These subsidiaries have distinct collective bargaining agreements. Because of the higher labor costs and the increased risk of strikes and other work-related stoppages that may be associated with union operations in the coal industry, our non-unionized competitors may have a competitive advantage in areas where they compete with unionized operations. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. The three existing collective bargaining agreements with the UMWA expire at the end of the first quarter 2007. If the applicable subsidiaries are unable to reach a mutually acceptable replacement agreement, it could adversely affect their productivity, increase their costs and disrupt shipments, or result in the closure of the mine due to a strike by the workers or a lockout by local management. Because, the Wabash mine operates with the room-and-pillar method as opposed to the lower cost longwall method at Emerald and Cumberland, and operates in a different production basin with different markets and competition, it may require a distinct collective bargaining agreement from those at Cumberland and Emerald in order to stay competitive and to justify capital investments.

In November 2003, the UMWA held an election at our Rockspring mining facility in West Virginia. The UMWA challenged nine unopened ballots as being improperly cast by supervisors. The outcome of the election will depend on the decision of the National Labor Relation Board (the “NLRB”) with respect to the nine challenged ballots, which ballots will not be opened until final resolution of the challenge. On February 5, 2004, the Regional Director of the NLRB ruled that only five of the nine challenged ballots could be counted. Both parties appealed to the full NLRB. In 2006 the NLRB ordered 5 of the 9 ballots to be opened. All were votes against the UMWA. This resulted in a revised tally of 110 for UMWA representation and 108 against the UMWA. The 4 remaining unopened ballots are determinative. By Order dated October 12, 2006, the Regional Director transferred the case back to the NLRB Board for further consideration of the remaining determinative challenged ballots. It is not known when the NLRB may rule on how to handle these 4 unopened ballots. If it is ultimately determined that the UMWA was validly elected, approximately 290 employees, will become UMWA members. In the event the Rockspring mining facility becomes unionized, we will bargain in good faith towards an acceptable collective bargaining agreement. If we are unable to do so, there could be strikes or other work stoppages detrimental to the normal operation of the Rockspring mining facility.

A shortage of skilled labor in the mining industry could pose a risk to achieving improved labor productivity and competitive costs, which 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 the event 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.

Our ability to operate our company effectively could be impaired if we lose key personnel.

We manage our business with a number of key personnel. We do not have “key person” life insurance to cover our executive officers. The loss of certain of these key individuals could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. Key personnel may not continue to be employed by us or we may not be able to attract and retain qualified personnel in the future. Failure to retain or attract key personnel could have a material adverse effect on us.

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

The geological characteristics of Central Appalachia and Northern Appalachia 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 the Powder River Basin, 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 customers’ ability to use coal produced by, our mines in Central Appalachia and Northern Appalachia.

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. These new power plant owners may have credit ratings that are below investment grade. If there is deterioration of the creditworthiness of electric power generator customers or trading counterparties, our business could be adversely affected. 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.

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. 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, or a combination, of these occurrences could have a material adverse effect on our business, financial condition and results of operations.

Provisions in our certificate of incorporation and bylaws may discourage a takeover attempt even if doing so might be beneficial to our shareholders.

Provisions contained in our certificate of incorporation and bylaws could make it more difficult for a third party to acquire us. Provisions of our certificate of incorporation and bylaws impose various procedural and other requirements, which could make it more difficult for shareholders 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 shareholders. 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 rights may have the effect of delaying or deterring a change of control of our company. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock.

ITEM 1B.

UNRESOLVED STAFF COMMENTS.

None.

ITEM 2.

PROPERTIES.

Coal Reserves

Periodically, we retain outside experts to independently verify our coal reserves. The most recent review was completed during the first quarter of 2004 and covered all of our reserves. The results verified our reserve estimates, with minor adjustments, and included an in-depth review of our procedures and controls. In the first quarter of 2006 we retained outside experts to independently verify additional economically viable reserves. “As received” means measuring coal in its natural state and not after it is dried in a laboratory setting. We have recalculated all reserves on an “as received” basis. Our reserves were approximately 1.6 billion tons as of December 31, 2006.

Of the 1.6 billion tons, approximately 0.9 billion tons are assigned reserves that we expect to be mined at operations that were active as of December 31, 2006. Approximately 0.7 billion tons are unassigned reserves that we are holding for future development. All of our reserves in Wyoming are assigned. We have substantial unassigned reserves in Pennsylvania, West Virginia and Illinois.

Approximately 50% of our reserves are classified as high Btu coal (coal delivered with an average heat value of 12,500 Btu per pound or greater) and are located in Pennsylvania and West Virginia. Approximately 42% of our reserves are classified as compliance coal which meets the 1.2 lb SO ₂ /mmBtu standard of Phase II of the Clean Air Act. Our compliance reserves are located in Wyoming and West Virginia.

The table below summarizes the locations, coal reserves in millions of tons and primary ownership of the coal reserves. Tonnage is on an as-received wet basis and the quality figures represent an approximate reserve average.


Operating Segments	Proven and Probable Reserves⁽¹⁾	Assigned Reserves	Unassigned Reserves	Average Btu/lb	Average Sulfur Content (lbs SO2/mmBtu)	Ownership
			(Tons in millions)
Powder River Basin	626.8	626.7	—	8,400	0.8	Primarily Leased
Northern Appalachia	747.3	184.1	563.2	12,825	3.3	Primarily Owned
Central Appalachia	197.1	69.5	127.6	12,900	1.4	Primarily Leased
Other	63.8	26.5	37.4	11,450	3.8	Primarily Leased

Total	1,635.0	906.8	728.2

⁽¹⁾	Proven and probable coal reserves are classified as follows:

Proven reserves—Reserves for which: (i) 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 (ii) 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—Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven 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 reserves, is high enough to assume continuity between points of observation.

We believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our current reserves are one of our strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.

Our reserve estimate is based on geological data assembled and analyzed by our staff of geologists and engineers. Reserve estimates are annually updated to reflect past coal production, new drilling information and other geological or mining data. Acquisitions or sales of coal properties will also change the reserves. Changes in mining methods may increase or decrease the recovery basis for a coal seam as will plant processing efficiency tests. We maintain reserve information in secure computerized data bases, as well as in hard copy. The ability to update and/or modify the reserve database is restricted to a few individuals and the modifications are documented.

Our mines in Wyoming are subject to federal coal leases that are administered by the U.S. Department of Interior under the Federal Coal Leasing Amendment Act of 1976. Each lease requires diligent development of the lease within ten years of the lease award with a required coal extraction of 1.0% of the reserves within that 10-year period. At the end of the 10-year development period, the mines are required to maintain continuous operations, as defined in the applicable leasing regulations. All of our federal leases are in full compliance with these regulations. We pay to the federal government an annual rent of $3.00 per acre and production royalties of 12.5% of gross proceeds on surface mined coal. The federal government remits half of the production royalty payments to Wyoming after deducting administrative expenses.

Certain of our mines in Pennsylvania, West Virginia and Illinois are subject to private coal leases. Private coal leases normally have a stated term and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and saleable coal contained on the relevant site. These private leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many leases also require payment of a lease rental or minimum royalty, payable either at the time of execution of the lease or in periodic installments. The terms of our private leases are normally extended by active production on or near the end of the lease term. Leases containing undeveloped reserves may expire or these leases may be renewed periodically.

Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves.

ITEM 3.

LEGAL PROCEEDINGS.

From time to time, we are involved in legal proceedings arising in the ordinary course of business. We believe we have recorded adequate accruals for these liabilities and that there is no individual case or group of related cases pending that is likely to have a material adverse effect on our financial condition, results of operations or cash flows.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

None.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

None.

ITEM 6.

SELECTED FINANCIAL DATA.

Foundation Coal Corporation does not have any independent external operations, assets or liabilities, other than through its operating subsidiaries. The selected consolidated financial data as of and for the twelve months ended December 31, 2006 and 2005 and as of and for the period from April 23, 2004 (date of incorporation) through December 31, 2004 have been derived from the audited consolidated financial statements of Foundation Coal Corporation. From its incorporation on April 23, 2004 and prior to the acquisition of RAG American Coal Holdings, Inc. on July 30, 2004, Foundation Coal Corporation did not have any assets, liabilities or results of operations. Therefore, the selected historical consolidated financial data for the period from January 1, 2004 through July 29, 2004 and as of and for the twelve months ended December 31, 2003 and 2002 have been derived from the audited consolidated financial statements of RAG American Coal Holding, Inc., the predecessor to Foundation Coal Corporation, which have been audited by Ernst & Young LLP, an independent registered public accounting firm. In the opinion of management, such consolidated financial data reflects all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of the results for those periods. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period. The period from April 23, 2004 to December 31, 2004 reflects preliminary purchase price allocations in preparing the financial data which was finalized during the twelve months ended December 31, 2005. The audited consolidated financial statements as of and for the twelve months ended December 31, 2006 and 2005, as of and for the period from April 23, 2004 through December 31, 2004 and for the seven months ended July 29, 2004 are included elsewhere in this Form 10-K.

The following provides a description of the basis of presentation during all periods presented:

“Successor”—Represents the consolidated financial position of Foundation Coal Corporation and consolidated subsidiaries as of December 31, 2006, 2005 and 2004 and the consolidated results of operations and cash flows for the twelve months ended December 31, 2006, 2005 and for the period from April 23, 2004 (date of incorporation) through December 31, 2004. Foundation Coal Corporation had no significant activities until the acquisition on July 30, 2004. Therefore, the results of operations and cash flows for the period from April 23, 2004 (date of incorporation) through December 31, 2004 reflect only the activity for the five month operating period ended December 31, 2004.

“Predecessor”—Represents the consolidated results of operations and cash flows of RAG American Coal Holdings, Inc. for all periods prior to the acquisition of RAG American Coal Holdings, Inc. on July 30, 2004.

You should read the following data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with the financial information included elsewhere in this 10-K, including the consolidated financial statements and related notes thereto.


	Successor									Predecessor
	Twelve Months Ended December 31, 2006			Twelve Months Ended December 31, 2005			For the Period From April 23, 2004 (date of incorporation) Through December 31, 2004			Seven Months Ended July 29, 2004			Twelve Months Ended December 31, 2003			Twelve Months Ended December 31, 2002
	(In thousands)
Statement of Operations Data:
Revenues:
Coal sales	$	1,440,162		$	1,292,411		$	436,035		$	544,882		$	975,984		$	891,762
Other revenue⁽¹⁾		30,159			24,518			8,561			6,153			18,362			13,016

Total revenues		1,470,321			1,316,929			444,596			551,035			994,346			904,778

Costs and expenses:
Cost of coal sales (excludes depreciation, depletion and amortization)		1,110,922			936,201			345,791			484,457			798,385			699,794
Selling, general and administrative expense (excludes depreciation, depletion and amortization)		50,721			48,437			24,596			27,375			45,268			45,032
Accretion on asset retirement obligations		8,510			8,507			3,300			4,020			6,979			—
Depreciation, depletion and amortization		183,201			211,186			84,843			61,236			99,764			91,581
Amortization of coal supply agreements		(13,122	)		(84,903	)		(67,238	)		8,837			17,913			17,519
Write-down of long-lived assets⁽²⁾		30,782			1,633			—			—			—			—
Asset impairment charges⁽³⁾		—			—			—			—			—			7,042

Income (loss) from operations		99,307			195,868			53,304			(34,890	)		26,037			43,810
Other income (expense):
Interest expense		(64,525	)		(59,495	)		(26,677	)		(18,010	)		(46,903	)		(48,930	)
Loss on termination of hedge accounting for interest rate swaps⁽⁴⁾		—			—			—			(48,854	)		—			—
Contract settlement⁽⁵⁾		—			—			—			(26,015	)		—			—
Loss on early debt extinguishment⁽⁶⁾		—			—			—			(21,724	)		—			—
Mark-to-market (loss) gain on interest rate swaps⁽⁴⁾		(112	)		—			530			5,804			—			—
Interest income		3,010			1,161			507			1,274			3,183			12,263
Litigation settlements⁽⁷⁾		—			—			—			—			43,500			—
Arbitration award⁽⁷⁾		—			—			—			—			—			31,055

Income (loss) from continuing operations before income tax (expense) benefit		37,680			137,534			27,664			(142,415	)		25,817			38,198
Income tax (expense) benefit		(4,106	)		(46,461	)		(13,600	)		51,824			191			(13,113	)

Income (loss) from continuing operations		33,574			91,073			14,064			(90,591	)		26,008			25,085
Income from discontinued operations, net of income tax expense⁽⁸⁾		—			—			—			2,315			10,145			8,056
Gain on disposal of discontinued operations, net of income tax expense⁽⁸⁾		—			—			—			20,750			—			—
Cumulative effect of accounting change, net of tax benefit⁽⁹⁾		—			—			—			—			(3,649	)		—

Net income (loss)	$	33,574		$	91,073		$	14,064		$	(67,526	)	$	32,504		$	33,141


	Successor									Predecessor
	Twelve Months Ended December 31, 2006			Twelve Months Ended December 31, 2005			For the Period From April 23, 2004 (date of incorporation) Through December 31, 2004			Seven Months Ended July 29, 2004			Twelve Months Ended December 31, 2003			Twelve Months Ended December 31, 2002
	(In thousands)
Balance Sheet Data (at period end):
Cash and cash equivalents	$	33,711		$	22,424		$	25,043					$	7,662		$	21,805
Cash on deposit with RAG Coal International AG		—			—			—						233,023			66,547
Cash pledged		—			—			—						20,000			75,048
Total assets		1,949,571			2,008,111			2,099,960						1,864,765			1,861,817
Total debt		626,625			635,000			685,000						616,462			656,762
Stockholder equity	$	297,530		$	339,371		$	255,731					$	523,151		$	487,888
Statement of Cash Flows Data:
Net cash provided by (used in) continuing operations:
Operating activities	$	225,654		$	177,819		$	61,693		$	(8,044	)	$	197,653		$	136,192
Investing activities		(199,868	)		(130,438	)		(934,932	)		(50,646	)		(92,672	)		(105,208	)
Financing activities		(14,499	)		(50,000	)		898,282			(127,821	)		(151,728	)		(44,126	)
Capital expenditures	$	(187,217	)	$	(140,216	)	$	(33,573	)	$	(52,695	)	$	(97,148	)	$	(118,878	)
Other Financial Data:
EBITDA^(10)(11)(12)	$	269,274		$	322,151		$	71,439		$	(55,606	)	$	187,214		$	183,965
Cumberland mine force majeure⁽¹³⁾	$	—		$	—		$	—		$	31,090		$	—		$	—
Ratio of earnings to fixed charges⁽¹⁴⁾		1.6x			3.2x			2.0x			—			1.5x			1.7x

⁽¹⁾	Other revenues include gains on disposition of assets and other non-coal sales revenues. See Note 25 to the consolidated financial statements for additional details of other revenue.

⁽²⁾

Write-down of long-lived assets in 2005 of $1.6 million as a result of a change in mine plan at the Northern Appalachia business unit. In 2006, $1.4 million and $29.4 million were written off related to deferred mining royalties at the Central Appalachia business unit and certain long-lived assets at the Wabash mine, respectively.

⁽³⁾	Asset impairment charges in 2002 consisted of $7.0 million for the write-down of a 55% investment in a Wyoming coal bed methane joint venture; this joint venture is accounted for under the proportional consolidation method.

⁽⁴⁾

In the Predecessor period in 2004, expenses resulting from loss on termination of hedge accounting for interest rate swaps represents a non-cash charge equal to the fair value of our pay-fixed receive-variable interest rate swaps on February 29, 2004, the date the swaps ceased to qualify for hedge accounting as a result of the required repayment of the related notes due to the sale of our Colorado operations. An additional non-cash mark-to-market gain of $5.8 million was incurred in the period February 29 to April 27, 2004. The swap was settled on April 27, 2004. In the Successor period in 2004, a $530 mark-to-market gain was recorded on interest rate swaps not yet designated as cash flow hedges. Expense in 2006 relates to a non-cash mark-to-market loss for the period for which the swaps did not qualify for cash flow hedge accounting. See Note 17 to the consolidated financial statements for additional information.

⁽⁵⁾

Contract settlement consists of a non-cash charge arising from settlement of a guarantee claim with the South Carolina Public Service Authority by means of entering into a multi-year coal supply agreement at prices below the then prevailing market prices for new coal supply agreements of similar duration.

⁽⁶⁾	Consists of cash prepayment penalties in connection with prepayment of substantially all remaining long-term indebtedness of the Predecessor.

⁽⁷⁾	Represents arbitration and litigation settlements recorded in 2002 and 2003.

⁽⁸⁾

On February 29, 2004, RAG Coal International AG, the parent of RAG American Coal Holding, Inc. signed an agreement to sell the active Twentymile mine and certain inactive or closed properties in Colorado and Wyoming to a third party. Accordingly, the results of the Colorado operations are shown as discontinued operations in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. The sale closed on April 15, 2004. Proceeds from the sale were used to repay certain debt and accrued interest and to settle related interest rate swaps.

⁽⁹⁾	Effective January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations.

⁽¹⁰⁾

EBITDA, a measure used by management to measure performance, is defined as income (loss) from continuing operations, plus interest expense, net of interest income, income tax (expense), depreciation, depletion and amortization, and amortization of coal supply agreements. Our management believes EBITDA is useful to investors because it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry. EBITDA is not a recognized term under GAAP and does not purport to be an alternative to net income as a measure of operating performance or to cash flows from operating activities as a measure of liquidity. Because not all companies use identical calculations, this presentation of EBITDA may not be comparable to other similarly titled measures of other companies.

Additionally, EBITDA is not intended to be a measure of cash flow available for management’s discretionary use, as it does not reflect certain cash requirements such as interest payments, tax payments and debt service requirements. The amounts shown for EBITDA as presented herein differ from the amounts calculated under the definition of EBITDA used in our debt instruments. The definition of EBITDA used in our debt instruments is further adjusted for certain cash and non-cash charges and is used to determine compliance with financial covenants and our ability to engage in certain activities such as incurring additional debt and making certain payments. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Covenant Compliance”.

EBITDA is calculated and reconciled to income (loss) from continuing operations in the table below.


	Successor									Predecessor
	Twelve Months Ended December 31, 2006			Twelve Months Ended December 31, 2005			For the Period From April 23, 2004 (date of incorporation) Through December 31, 2004			Seven Months Ended July 29, 2004			Twelve Months Ended December 31, 2003			Twelve Months Ended December 31, 2002
	(In thousands)
Income (loss) from continuing operations	$	33,574		$	91,073		$	14,064		$	(90,591	)	$	26,008		$	25,085
Interest expense		64,525			59,495			26,677			18,010			46,903			48,930
Interest income		(3,010	)		(1,161	)		(507	)		(1,274	)		(3,183	)		(12,263	)
Income tax expense (benefit)		4,106			46,461			13,600			(51,824	)		(191	)		13,113
Depreciation, depletion and amortization		183,201			211,186			84,843			61,236			99,764			91,581
Amortization of coal supply agreements		(13,122	)		(84,903	)		(67,238	)		8,837			17,913			17,519

EBITDA	$	269,274		$	322,151		$	71,439		$	(55,606	)	$	187,214		$	183,965

⁽¹¹⁾	Income (loss) from continuing operations and EBITDA, as defined above, were impacted by the following non-cash charges (income):


	Successor								Predecessor
	Twelve Months Ended December 31, 2006		Twelve Months Ended December 31, 2005			For the Period From April 23, 2004 (date of incorporation) Through December 31, 2004			Seven Months Ended July 29, 2004		Twelve Months Ended December 31, 2003		Twelve Months Ended December 31, 2002
	(In thousands)
Interest rate swaps^a	$	112	$	—		$	(530	)	$	43,050	$	—	$	—
Early debt extinguishment costs		—		—			—			21,724		—		—
Accretion on asset retirement obligations/reclamation expense		8,510		8,507			3,300			4,020		6,979		5,509
Write-down of long-lived assets		30,782		1,633			—			—		—		—
Asset impairment charges		—		—			—			—		—		7,042
Amortization included in employee benefits expenses^b		—		—			—			10,318		11,360		6,053
Profit in inventory^c		—		—			3,753			—		—		—
Overburden removal included in depreciation, depletion and amortization^d		—		(22,624	)		(15,300	)		—		—		—
Stock-based compensation expense^e		2,699		1,509			—			—		—		—

The amount for the Predecessor includes $48.9 million of expense resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps, less $5.8 million mark-to-market adjustment. The amount for the Successor in 2004 includes the mark-to-market gain on interest rate swaps not yet designated as cash flow hedges prior to December 31, 2004. In 2006, the amount includes the mark-to-market loss for the period during which the swaps did not qualify for cash flow hedge accounting. See Note 4 above.

^b	Represents the portion of pension, other postretirement and black lung expense resulting from amortization of unrecognized actuarial losses, prior service costs and transition obligations.

^c	Represents incremental cost of sales recorded in the period arising from the preliminary estimate of profit added to inventory in purchase accounting.

In purchase accounting, the fair value of partially and fully uncovered coal included consideration of the effort spent prior to the purchase date to remove overburden and get the coal to its partially or fully uncovered state. Therefore, the fair value assigned to partially and fully uncovered coal reserves was higher than that assigned to other coal reserves. Depletion of coal reserves, including the incremental fair value related to pre-Acquisition overburden removal efforts is included in Depreciation, depletion and amortization. Subsequent to the Acquisition date and prior to the implementation of Emerging Issues Task Force Issue No. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry on January 1, 2006, the cost associated with removal of overburden to uncover coal reserves was deferred until the related coal is mined and charged to Cost of coal sales when the coal is sold. All partially and fully uncovered coal valued at the Acquisition date was sold by December 31, 2005. For the twelve months ended December 31, 2005 and for the period from April 23, 2004 (date of incorporation) through December 31, 2004, Depreciation, depletion and amortization included the value of overburden removal performed prior to the Acquisition date, which would have been included in Cost of coal sales if incurred subsequent to the Acquisition date.

^e	Represents an accrual for compensation expense attributable to stock options and restricted stock units.

⁽¹²⁾	Income (loss) from continuing operations and EBITDA, as defined above, were also impacted by the following unusual (income) expense:


	Successor							Predecessor
	Twelve Months Ended December 31, 2006			Twelve Months Ended December 31, 2005		For the Period From April 23, 2004 (date of incorporation) Through December 31, 2004		Seven Months Ended July 29, 2004		Twelve Months Ended December 31, 2003			Twelve Months Ended December 31, 2003
	(In thousands)
Litigation/arbitration/contract settlements, net^a	$	(1,010	)	$	—	$	—	$	28,900	$	(41,900	)	$	(24,255	)
Transactions bonus^b		—			—		—		1,826		—			—
Long-term incentive plan expense^c		—			—		—		2,428		3,894			965
Other^d		(140	)		—		3,746		—		—			—

^a	Represents arbitration awards and litigation settlements, net of related legal and tax fees. Legal and tax fees associated with these settlements were $0.5 million in the period January 1, 2004 to July 29, 2004, $1.6 million in 2003, and $6.8 million in 2002.

^b	Represents the cost of a one-time bonus awarded to certain employees in connection with the Acquisition.

^c	Represents the cost of a long-term incentive plan instituted by the Predecessor in 2001 that was terminated prior to closing as required by the change in control provisions in the plan agreement. We have implemented a management equity program that will not result in a cash cost to us.

In 2004, amount represents a $1.8 million bonus paid to senior management related to the Initial Public Offering (“IPO”) of Foundation Coal Holdings, Inc. and a $2.0 million sponsor monitoring fee recorded by the Successor. This latter item was terminated in connection with the IPO. In 2006, amount represents a loss of longwall shields at the Emerald mine due to geological conditions.

⁽¹³⁾	Represents the estimated impact on EBITDA of the temporary idling of our Cumberland mine in the first half of 2004 as a result of a revised interpretation of mine ventilation laws by MSHA.

⁽¹⁴⁾

For purposes of this computation, “earnings” consist of pre-tax income from continuing operations (excluding minority interest and equity in earnings of affiliates) plus fixed charges. “Fixed charges” consist of interest expense on all indebtedness plus amortization of deferred costs of financing and the interest component of lease rental expense. Earnings were insufficient to cover fixed charges by the deficiency of $142.4 million for the seven months ended July 29, 2004.

PART II

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION.

Overview

We are the fourth largest coal producer in the United States, operating nine mining complexes that consist of fourteen individual coal mines. Our mining operations are located in southwest Pennsylvania, southern West Virginia, southern Illinois and the southern Powder River Basin region of Wyoming. Four of our operations are surface mines, two of our operations are underground mines using highly efficient longwall mining technology and the remaining eight operations are underground mines that utilize continuous miners. In addition to mining coal, we also purchase coal from other producers and utilize it with our own production in coal brokering and trading activities.

Our primary product is steam coal, sold primarily to electric power generators located in the United States. Approximately 9% of both our 2006 and 2005 coal sales revenues were made from the sale of metallurgical coal to the domestic and export metallurgical coal markets where it is used to make coke for steel production.

While the majority of our revenues are derived from the sale of coal, we also realize revenues from coal production royalties, override royalty payments from a coal supply agreement now fulfilled by another producer, fees from the processing of our production by a synfuel facility, fees to transload coal through our Rivereagle facility on the Big Sandy River and revenues from the sale of coalbed methane.

From July 1, 1999 through July 29, 2004, we were known as RAG American Coal Holding, Inc. and were a stand-alone wholly owned subsidiary of RAG Coal International AG (“RAG”) headquartered in Essen, Germany. In October 2003, RAG announced its intention to divest its international mining subsidiaries. In addition to RAG American Coal Holding, Inc., these international mining subsidiaries consisted of operations in Australia and Venezuela.

On February 29, 2004, RAG announced the sale of four of our subsidiaries, collectively known as the RAG Colorado Business Unit, to a third party. The subsidiaries comprising the RAG Colorado Business Unit owned an underground longwall mine located in Routt County, Colorado, an idled underground longwall mine located in Moffat County, Colorado and surface lands located in northwest Colorado and southern Wyoming. The transaction closed on April 15, 2004. In the financial statements of the Predecessor for the period from January 1, 2004 through July 29, 2004, the RAG Colorado Business Unit is classified as a discontinued operation.

Foundation Coal Holdings, LLC (“LLC”) was formed on February 9, 2004, by a group of investors for the purpose of acquiring the United States coal properties owned by RAG. A Stock Purchase Agreement was signed on May 24, 2004.

On April 23, 2004, Foundation Coal Corporation was formed as a wholly owned subsidiary of LLC. Foundation Coal Corporation issued 100 shares of common stock with a par value of $0.01 to LLC. LLC was formed as a Delaware limited liability company, which, as described below, later contributed its shares of Foundation Coal Corporation and merged into Foundation Coal Holdings, Inc.

LLC, through its subsidiary, Foundation Coal Corporation (the “Company”), and pursuant to the Stock Purchase Agreement, completed an acquisition of 100% of the outstanding common shares of RAG American Coal Holding, Inc. and its subsidiaries from RAG, on July 30, 2004 (the “Acquisition”).

LLC merged on August 17, 2004 into its subsidiary, Foundation Coal Holdings, Inc., a Delaware corporation that was formed on July 19, 2004. Foundation Coal Holdings, Inc. was the surviving entity in this merger. Accordingly, the Company became an indirect wholly owned subsidiary of Foundation Coal Holdings, Inc. On December 9, 2004, Foundation Coal Holdings, Inc. completed an initial public offering (“IPO”) of 24,121,900 shares of common stock and became the entity we refer to herein as the “Public Parent”.

Results of Operations

Basis of Presentation:

Due to the change in ownership, and the resultant application of purchase accounting, the historical financial statements of the Predecessor and the Successor included in this Form 10-K have been prepared on different bases for the periods presented and are not comparable.

The following describes the basis of presentation for all periods presented:

Successor—Represents the consolidated financial position of the Company as of December 31, 2006 and 2005 and our consolidated results of operations and cash flows for the twelve months ended December 31, 2006 and December 31, 2005 and for the period from April 23, 2004 (date of incorporation) through December 31, 2004. The Company had no significant activities until the Acquisition. Hereinafter, the period from April 23, 2004 (date of incorporation) through December 31, 2004 is referred to as the “Five Month Operating Period Ended December 31, 2004.” Our consolidated financial position at December 31, 2006 and December 31, 2005 and our consolidated results of operations for the twelve months then ended reflect the final purchase price allocation based on appraisals prepared by independent valuation specialists, employee benefit valuations prepared by independent actuaries and other internal analysis. Deferred income taxes have been provided in the Consolidated Balance Sheet based on the tax versus book basis of the assets acquired and liabilities assumed. During the twelve months ended December 31, 2005, we completed the purchase price allocation, and recorded final purchase accounting adjustments that reduced the fair value of the total assets acquired by approximately $105.9 million, or approximately 5%, of the preliminary value assigned to the assets acquired. The most significant component of this decrease related to a revision in deferred income tax liabilities associated with projected postretirement benefit obligations resulting from changes in the assumptions regarding the impact on these obligations of the Medicare Part D prescription drug benefits. The reduction in deferred income tax liabilities resulted in corresponding changes to the values assigned to owned and leased mineral rights and coal supply agreements. The preliminary valuation of deferred income taxes assumed that Medicare Part D would be coordinated with the Company’s health care plans. Additional information obtained and analysis performed prior to the finalization of purchase accounting caused this assumption to change whereby the Company decided to utilize the income tax free subsidy offered under Medicare Part D. Our consolidated financial position at December 31, 2004 reflected our preliminary estimates of purchase price allocation before the final purchase accounting adjustments described above. The application of purchase accounting to the acquired assets of RAG American Coal Holding, Inc. resulted in increases to owned and leased mineral rights, surface lands, coal inventories, and the asset arising from recognition of asset retirement obligations. It resulted in decreases to plant and equipment and current deferred taxes. In addition, the historical cost assigned to deferred overburden in the acquired asset balance sheet was eliminated. The values assigned to uncovered and partially covered coal lands considered the stage of the mining process in which these two groups of coal lands were at the acquisition date. The application of purchase accounting to the acquired liabilities of RAG American Coal Holding, Inc. resulted in increases to postretirement health care obligations, pension obligations, black lung obligations, asset retirement obligations and noncurrent deferred taxes. Separate assets or liabilities were established to reflect the valuation of above or below market coal supply agreements in relation to market price curves. With regard to consolidated results of operations for the Five Month Operating Period Ended December 31, 2004 and the twelve months ended December 31, 2005 and 2006, respectively, the principal effects of the application of purchase accounting, in comparison to reporting for historical periods, were to decrease the cost of coal sold due to lower expenses for postretirement health care and pensions, to decrease net amortization expense for coal supply agreements which is now a net credit because our contracts at acquisition represented a net liability and to increase the cost of depletion expense for owned and leased mineral rights. During the Five Month Operating Period Ended December 31, 2004, cost of coal sold was increased for the increase in value of coal inventories from cost to market at the acquisition date.

Predecessor—Represents the consolidated results of operations and cash flows for RAG American Coal Holding, Inc. for the period from January 1, 2004 through July 29, 2004. These consolidated financial statements are based on the historical assets, liabilities, sales and expenses of the Predecessor for these periods.

Non-GAAP Combined—To facilitate trend analysis, in management’s discussion and analysis for the Successor Period Twelve Months Ended December 31, 2005 compared to the Predecessor Period from January 1, 2004 Through July 29, 2004 and the Successor Period from April 23, 2004 (date of incorporation) Through December 31, 2004 (“Five Month Operating Period Ended December 31, 2004”), we discuss “Non-GAAP Combined” results for the Twelve Months Ended December 31, 2004. Non-GAAP Combined amounts are determined by adding the historical amounts of the Predecessor for the period from January 1, 2004 through July 29, 2004 with the corresponding amounts of the Successor for the Five Month Operating Period Ended December 31, 2004. Non-GAAP Combined amounts are not recognized measures under GAAP and do not purport to be alternatives to GAAP operating measures. Non-GAAP Combined amounts are not indicative of the operating results of the Company because of the significant difference in basis between the Successor and Predecessor caused by the acquisition on July 30, 2004 and its impact on income from operations. Management believes that the discussion of Non-GAAP Combined operating results is important to the readers of the financial statements to understand key operating trends over the normal operating cycle years 2006, 2005 and 2004. Non-GAAP Combined amounts are reconciled to the underlying historical GAAP basis financial statements on page 55.

Twelve Months Ended December 31, 2006 Compared to Twelve Months Ended December 31, 2005

Coal sales realization per ton sold represents the average revenue realized on each ton of coal sold. It is calculated by dividing coal sales revenues by tons sold.

Revenues


	Twelve Months Ended December 31,				Increase
	2006		2005		Amount		Percent
	(In thousands, except per ton data)
Coal sales	$	1,440,162	$	1,292,411	$	147,751	11	%
Other revenue		30,159		24,518		5,641	23	%

Total revenues	$	1,470,321	$	1,316,929	$	153,392	12	%

Tons sold		73,920		68,781		5,139	7	%
Coal sales realization per ton sold	$	19.48	$	18.79	$	0.69	4	%

Coal sales revenues for the twelve months ended December 31, 2006 increased by 11% compared to the coal sales revenues for the twelve months ended December 31, 2005 as a result of a 7% increase in tons sold and a 4% increase in average coal sales realization per ton.

Coal sales revenues in Northern Appalachia for the twelve months ended December 31, 2006 increased by 12% compared to the coal sales revenues for the twelve months ended December 31, 2005 as a result of an 11% increase in average coal sales realization per ton and a 1% increase in tons sold. Revenue realization per ton sold in Northern Appalachia increased in 2006 due to the substitution of higher priced contracts which took effect in late 2005 and early 2006 for lower priced contracts that expired offset by lower coal quality premiums. Coal sales volumes in Northern Appalachia increased by 0.1 million tons (1%) year-over-year mainly as a result of increased shipments and production from the Cumberland mine, partially offset by decreased shipments and production from the Emerald mine due to difficult mining conditions experienced throughout the year. Emerald had two scheduled longwall moves during 2006 compared to one scheduled longwall move during 2005, the result of which contributed to lower year-over-year production and sales. Cumberland had one scheduled longwall move in both 2006 and 2005.

Coal sales revenues in Central Appalachia for the twelve months ended December 31, 2006 increased by 10% compared to the coal sales revenues for the twelve months ended December 31, 2005 as a result of an 11% increase in average coal sales realization per ton offset by a 1% decrease in tons sold. Coal sales realization per ton sold in Central Appalachia increased in 2006 due to a combination of: (a) substitution of higher priced contracts which took effect in late 2005 and early 2006 for lower priced contracts that expired; and (b) higher coal quality premiums. Coal sales volumes in Central Appalachia decreased by 0.1 million tons (1%) year-over-year as a result of decreased shipments and production from all our mining operations with the exception of the Pax surface mine and the Laurel Creek mines. Central Appalachia production and shipments were higher in the first quarter of 2006 compared to 2005 due to shipments of purchased coal utilized on selected steam coal contracts. However, in the remaining three quarters of the year, overall production was lower in 2006 compared to 2005 a result of difficult mining conditions experienced throughout the year, resulting in lower shipments and sales volumes. The Pax surface mine, which replaced the Simmons Fork mine that depleted its reserves in 2004, began production in the fourth quarter of 2004. In 2005 and 2006 Pax produced 0.6 million tons and 0.9 millions tons, respectively. Year-over-year production increases at Pax occurred as mine development progressed to its current state of completion. Pax is expected to produce at an annual rate of approximately 1 million tons per year before the integration of the recently acquired mining assets of Pax South discussed in Significant Property Transactions below.

Coal sales revenues in the Powder River Basin for the twelve months ended December 31, 2006 increased by 29% compared to the coal sales revenues for the twelve months ended December 31, 2005 as a result of a 12% increase in average coal sales realization per ton and a 14% increase in tons sold. Base revenue realization per ton increased by 11% year-over-year while coal quality premium/penalty revenue increased 33% year-over-year. Coal sales realization per ton increased due to the commencement of shipments under higher priced contracts and higher coal quality premiums. Coal sales volumes in the Powder River Basin increased by 6.3 million tons (14%) to a record shipment level of 49.9 million tons primarily due to a 26% increase in both production and shipments from the Belle Ayr mine where annual production capacity was increased by 5.0 million tons effective January 1, 2006. Eagle Butte production and shipments increased 5% year-over-year primarily due to favorable second and third quarter of 2006 operating results.

Coal sales revenues in the Illinois Basin for the twelve months ended December 31, 2006 decreased by 31% compared to the coal sales revenues for the twelve months ended December 31, 2005 as a result of a 31% decrease in tons sold, while average coal sales realization per ton remained consistent between years. Base revenue realization per ton increased slightly year-over-year while coal quality premium/penalty revenue decreased year-over-year. Coal sales volumes from the Illinois Basin decreased by 0.5 million tons (31%), reflecting 32% lower production from the Wabash mine due to the diversion of scheduled operating shifts to maintain the mine’s underground infrastructure and the mine’s compliance with federal and state regulations, coupled with a lower clean coal recovery percentage as compared to the same period in 2005.

Purchased coal activities by our trading group decreased by approximately 0.7 million tons (83%), compared to the same period in 2005, due to decreased trade activities and the timing of purchased coal transactions.

Other revenues for the twelve months ended December 31, 2006 increased by $5.6 million (23%) compared to the twelve months ended December 31, 2005. The increase was primarily due to increased royalty income ($2.4 million) and increased miscellaneous revenues from our Dry Systems Technologies subsidiary ($3.0 million).

Costs and Expenses


	Twelve Months Ended December 31,						Increase (Decrease)
	2006			2005			Amount			Percent
	(In thousands)
Cost of coal sales (excludes depreciation, depletion and amortization)	$	1,110,922		$	936,201		$	174,721		19	%⁽¹⁾
Selling, general and administrative expense (excludes depreciation, depletion and amortization)		50,721			48,437			2,284		5	%
Accretion on asset retirement obligations		8,510			8,507			3		—
Write-down of long-lived assets		30,782			1,633			29,149		1,785	%
Depreciation, depletion and amortization		183,201			211,186			(27,985	)	(13	)%
Amortization of coal supply agreements		(13,122	)		(84,903	)		71,781		85	%

Total costs and expenses	$	1,371,014		$	1,121,061		$	249,953		22	%

⁽¹⁾	Excluding the credit related to deferral of costs associated with overburden removal in the year ended December 31, 2005, cost of coal sales increased approximately 14%.

Cost of coal sales. The cost of coal sales increased $174.7 million for the twelve months ended December 31, 2006 compared to the twelve months ended December 31, 2005 primarily due to: (a) increases in labor costs as a result of both compensation increases and hiring of additional personnel ($34.3 million); (b) increases in repair and maintenance supplies, consumables and commodity supply costs, most notably diesel fuel, and large equipment tires and explosives ($88.9 million); (c) increases in royalties and coal production taxes as a result of higher revenues ($21.8 million); (d) decreases in purchased coal costs as a result of lower purchased coal volumes ($15.7 million); (e) an accounting change, effective January 1, 2006, requiring expensing of overburden removal costs ($42.9 million); (f) an increase to expense from decreased coal inventories in 2006 compared to increased coal inventories in 2005 ($11.0 million); (g) a decrease in longwall move expense ($5.1 million); (h) a decrease in expenses associated with contractor mining ($5.4 million); and (i) increases in other miscellaneous expenses ($2.0 million). Production costs increased partly due to higher year-over-year production. Cost of coal sales per ton was $15.03 for the twelve months ended December 31, 2006 compared to $13.64 per ton for the twelve months ended December 31, 2005. The $13.64 cost of coal sales per ton for the twelve months ended December 31, 2005 includes a $42.9 million credit related to the deferral of cost associated with overburden removal. Subsequent to the Company’s adoption of Emerging Issues Task Force (“EITF”) Issue No. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry (“EITF Issue 04-6”), on January 1, 2006, such costs were no longer deferred. Cost of coal sales per ton was $14.26 after adjusting for the impact of the accounting change for overburden removal costs, an increase of approximately 5%.

Selling, general and administrative expense. Selling, general and administrative expense for the twelve months ended December 31, 2006 was $50.7 million compared to $48.4 million for the twelve months ended December 31, 2005. Year-over-year increases were due to additional expenses incurred for employee expenses ($3.2 million) and outside services ($0.1 million), partially offset by lower insurance expenses and reduced sales commissions (combined $1.0 million).

Accretion on asset retirement obligations. Accretion on asset retirement obligations is a component of accounting for asset retirement obligations under Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). Accretion represents the increase in the asset retirement liability to reflect the change in the liability for the passage of time. Slightly higher accretion expense in 2006 was due to increased asset retirement obligation estimates at closed mines.

Write-down of long-lived assets. In the fourth quarter of 2006, the Company recognized a $30.8 million non-cash asset impairment charge which included $29.4 million to write-down the carrying value of certain impaired assets at its Wabash mine and $1.4 million to write-off a non-recoverable prepaid royalty in Central Appalachia in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-lived Assets (“SFAS No. 144”). In the fourth quarter of 2005, the Company recognized a $1.6 million non-cash asset impairment charge related to development costs that were attributable to expanding certain undeveloped areas of mining districts in the Company’s Northern Appalachia business unit. As a result of a change in the Company’s mine plan, these costs were no longer considered recoverable.

Depreciation, depletion and amortization. DD&A includes depreciation of plant and equipment, cost depletion of amounts assigned to coal lands and mining rights and amortization of mine development costs and leasehold improvements. DD&A expense decreased $28.0 million for the twelve months ended December 31, 2006 compared to the twelve months ended December 31, 2005, primarily due to lower cost depletion partially offset by higher depreciation and amortization. Cost depletion declined by $44.2 million due to a combination of: (a) lack of depletion expense in 2006 pertaining to purchase accounting values assigned to partially and fully uncovered coal at the Powder River Basin surface mines as these assets were fully depleted during 2005; and (b) final purchase accounting adjustments recorded in 2005 that reduced the values assigned to coal lands and mining rights, partly offset by higher production in the Powder River Basin during 2006. Depreciation and amortization increased by $16.2 million in 2006 mainly due to capital additions to plant & equipment during the twelve months ended December 31, 2006.

Amortization of coal supply agreements. Application of purchase accounting resulted in recognition of a significant liability for below market priced coal supply agreements as well as a significant asset for above market priced coal supply agreements, both in relation to market prices at the date of Acquisition. Coal supply agreement amortization decreased $71.8 million for the twelve months ended December 31, 2006 compared to the twelve months ended December 31, 2005. Amortization of the liability for below market priced coal supply agreements during the twelve months ended December 31, 2006 was $33.5 million of credit to expense compared to $109.9 million of credit to expense in the comparable period of the prior year. Amortization of the asset for above market priced coal supply agreements during the twelve months ended December 31, 2006 was $20.4 million of expense compared to $25.0 million of expense in the comparable period of the prior year. During the twelve months ended December 31, 2006, shipments on a number of coal supply agreements valued in purchase accounting were completed.

Segment Analysis

Utilizing data published by Argus Media, the following graph sets forth representative steam coal prices in various U.S. markets summarized for the monthly periods from January 1, 2005 through December 31, 2006. The prices are not necessarily representative of the coal prices actually obtained by the Company. Changes in coal prices have an impact over time on the Company’s average sales realization per ton and, ultimately, its consolidated financial results.

LOGO


	Twelve Months Ended December 31,				Increase (Decrease)
	2006		2005		Tons/$			Percent
	(In thousands, except sales realization per ton)
*Powder River Basin*
Tons sold		49,918		43,612		6,306		14	%
Average sales realization per ton	$	8.39	$	7.47	$	0.92		12	%
Revenues	$	420,264	$	327,595	$	92,669		28	%
Income from operations	$	46,986	$	23,564	$	23,422		99	%

*Northern Appalachia*
Tons sold		13,798		13,678		120		1	%
Average sales realization per ton	$	38.81	$	35.00	$	3.81		11	%
Revenues	$	540,873	$	483,511	$	57,362		12	%
Income from operations	$	143,858	$	174,555	$	(30,697	)	(18	)%

*Central Appalachia*
Tons sold		8,870		8,936		(66	)	(1	)%
Average sales realization per ton	$	50.16	$	45.37	$	4.79		11	%
Revenues	$	455,507	$	416,976	$	38,531		9	%
Income from operations	$	10,584	$	49,624	$	(39,040	)	(79	)%

Powder River Basin—Income from operations increased $23.4 million year-over-year due to increased revenues of $92.7 million, partly offset by increased production costs of $69.3 million. As explained in the revenue section above, the increased revenues resulted from a 14% increase in tons sold from record 2006 shipments and a 12% increase in average sales realization per ton. The increase in tons sold is primarily due to the expansion of annual capacity at the Belle Ayr mine and favorable second and third quarter of 2006 operating results at the Eagle Butte mine which resulted in a total year-over-year increase in production and shipments of 15% and 14%, respectively. Increased production costs were primarily in the following areas: (a) royalties, excise taxes and coal production taxes, which respond to changes in coal sales revenues ($14.5 million); (b) diesel fuel and utilities ($13.3 million); (c) repairs and maintenance ($6.8 million); (d) large equipment tires and other operating supplies ($6.0 million); (e) explosives ($4.7 million); (f) labor and employee benefits ($7.8 million); (g) other supplies and services ($1.4 million); and (h) depreciation and amortization ($6.2 million). Certain production cost increases occurred due to higher year-over-year production. There was a year-over-year $4.6 million reduction in amortization of coal supply agreements as shipments on a number of supply agreements valued in purchase accounting were completed. Production costs in the twelve months ended December 31, 2005 included a $42.9 million credit for overburden removal costs added to work-in-process inventory offset by $31.8 million in higher cost depletion expense in the prior year mainly relating to depletion of partially and fully uncovered coal established in purchase accounting. With the implementation of EITF Issue 04-6, effective January 1, 2006, the Powder River Basin mines are no longer recognizing work-in-process inventory for uncovered coal. Cost of coal sales per ton, after adjusting for the impact of the accounting change for overburden removal costs, increased approximately 6% year-over-year for reasons discussed above.

Northern Appalachia—Despite higher revenue of $57.4 million, income from operations decreased by $30.7 million year-over-year due to increased cost of coal sales of $89.8 offset by $1.7 million of miscellaneous income. Increased revenues resulted from a 1% increase in tons sold and an 11% increase in average sales realization per ton. The increase in sales was primarily due to a 9% increase in shipments from the Cumberland mine as production in all but the third quarter of 2006 increased over 2005 quarters as a result of good mining conditions and strong longwall productivity. The production decline in the third quarter of 2006, compared to 2005, resulted from a scheduled longwall move which shut down longwall mining operations for an approximate two week period during the 2006 quarter. Cumberland had a longwall move in the fourth quarter of 2005. Production from the Emerald mine declined 12% year-over-year, impacted by difficult mining conditions and equipment problems experienced throughout the year which resulted in a 7% decline in shipments. Increased cost of coal sales consisted primarily of $89.8 million of higher production costs, represented by increases in the following areas: (a) labor and employee benefit costs ($10.0 million); (b) repairs and maintenance costs ($7.5 million); (c) other materials, supplies and services ($12.9 million); (d) insurance premiums ($1.2 million); (e) diesel fuel and utilities ($2.0 million); (f) depreciation and amortization ($4.2 million); (g) reduced credit for amortization of coal supply agreements ($48.0 million); (h) operating supplies ($4.9 million); and (i) royalties, excise taxes and coal production taxes, which correspond to changes in coal sales revenues ($1.0 million), partly offset by reduced cost depletion of $8.5 million and lower longwall move costs ($5.1 million). Cost of coal sales per ton increased approximately 14% year-over-year.

Central Appalachia—Income from operations decreased by $39.0 million year-over-year due to increased cost of coal sales of $52.2 million, increased depreciation and amortization expense of $5.4 million, a reduced credit to expense for amortization of coal supply agreements of $23.2 million and a pre-tax charge of $1.4 million to write-down prepaid royalties associated with certain mining leases, partly offset by increased revenues of $38.5 million and reduced cost depletion expense of $3.7 million. The increase in revenues resulted from an 11% increase in average sales realizations per ton resulting from the roll-off of lower priced coal sales agreements from 2005. Tons sold decreased slightly despite increased tons that were purchased and resold and year-over-year 68% and 64% increases in production and shipments, respectively, at the Pax surface mine due to the completion of mine development. Higher cost of coal sales were primarily due to increases in the following areas: (a) labor and fringe benefits ($10.4 million); (b) materials, supplies and services, led by increases for maintenance and repairs, diesel fuel, explosives and contract trucking ($24.2 million); (c) purchased coal ($8.3 million); and (d) royalties and severance taxes ($6.7 million). Cost of coal sales per ton increased approximately 16% year-over-year.

Other—Includes the Company’s Wabash mine, located in the Illinois Basin, expenses associated with closed mines, its coal trading operations and selling general and administrative expenses not charged-out to the Powder River Basin, Northern Appalachia or Central Appalachia mines. During the twelve months ended December 31, 2006, the Other segment reported a loss from operations of $102.1 million compared to a loss from operations of $51.9 million in the twelve months ended December 31, 2005. The increased year-over-year loss from operations of $50.2 million was primarily a result of an increased operating loss at the Wabash mine due to: (a) an approximate 30% decline in production and shipments, as described in the revenue section above; (b) higher cost of coal sales; (c) a $29.4 million write-down of the carrying value of long-lived assets; and (d) a reduced credit to expense from amortization coal supply agreements. The operating losses attributable to closed mines were less by $3.7 million in 2006 compared to 2005. The change in selling, general and administrative expenses not charged out to the other operating segments was de minimis year-over-year.

Interest Expense, Net


	Twelve Months Ended December 31,						Increase (Decrease)
	2006			2005			Amount			Percent
	(In thousands)
Interest expense—debt related	$	(43,469	)	$	(42,580	)	$	889		2	%
Interest expense—amortization of deferred financing costs		(11,653	)		(4,787	)		6,866		243	%
Interest expense—surety bond and letter of credit fees		(6,749	)		(10,153	)		(3,404	)	(34	)%
Interest expense—other		(2,654	)		(1,975	)		679		35	%

Total interest expense		(64,525	)		(59,495	)		5,030		8	%
Interest income		3,010			1,161			1,849		259	%

Interest expense, net	$	(61,515	)	$	(58,334	)	$	3,181		5	%

Interest expense, net for the twelve months ended December 31, 2006 includes a $9.2 million non-cash write-off of unamortized deferred financing costs recorded as a result of the Company’s amendment to its debt agreement as more fully described in the Liquidity and Capital Resources section below. Excluding this charge, interest expense, net for the twelve months ended December 31, 2006, was lower than the twelve months ended December 31, 2005 due primarily to lower surety bond and letter of credit fees and higher interest income resulting from interest on invested cash balances. The reduction in surety bond and letter of credit fees was primarily attributable to fewer letters of credit outstanding. Debt related interest expense for the twelve months ended December 31, 2006 was slightly higher than the debt related interest expense for the twelve months ended December 31, 2005 due to an approximate 125 basis point increase in the interest rate on variable rate debt, partly offset by the impact of repaying $50.0 million of variable rate debt in the second half of 2005.

Income Tax Expense


	Twelve Months Ended December 31,				Income Tax Expense Decrease
	2006		2005		Amount			Percent
	(In thousands)
Income tax expense	$	4,106	$	46,461	$	(42,355	)	(91	)%

For the twelve months ended December 31, 2006, income taxes were provided at an effective rate of approximately 11%. For the twelve months ended December 31, 2005 income taxes were provided at an effective rate of approximately 34%. The reduction in effective income tax rate year-over-year is primarily due to an increase in the percentage depletion at the Cumberland mine due to fully depleting its tax basis in coal reserves late in 2005. Because of excess depletion adjustments for tax purposes above the tax basis of the coal reserves, percentage depletion from Cumberland, which was treated as a temporary difference in the effective income tax rate used during 2005, is treated as a permanent difference in the effective income tax rate for 2006. In addition, the Emerald mine and the Central Appalachia mines generated increased percentage depletion, which is treated as a permanent difference, during 2006.

Expected Coal Production

As of January 24, 2007, uncommitted and unpriced tonnage was 2%, 30%, 52% and 81% of planned production in 2007, 2008, 2009 and 2010, respectively. Eastern coals account for the majority of uncommitted tonnage as 4%, 41%, 73% and 93% of the Company’s planned eastern production remains uncommitted and unpriced in 2007, 2008, 2009 and 2010, respectively.

In 2007 through 2010, Foundation Coal expects coal production within the following ranges (millions of tons):


	2007	2008	2009	2010
East	21.5–23.0	21.5–23.5	21.5–23.5	21.5–23.5
West	49.5–53.0	52.0–56.0	52.0–56.0	52.0–56.0
Total Consolidated	71.0–76.0	73.5–79.5	73.5–79.5	73.5–79.5

Based on its committed and priced planned production as of January 24, 2007, the Company expects its committed and priced production from its Eastern mines, encompassing Northern Appalachia, Central Appalachia and the Illinois Basin, to realize in the range of $43.00 to $45.00 per ton in 2007. The Company also expects its committed and priced production from the Powder River Basin to realize in the range of $9.10 to $9.50 per ton in 2007. These ranges of expected per ton average realizations include forecast sulfur dioxide and btu premiums based on contract terms, projected coal qualities and historical realized premiums. The above tonnages and expected per ton average realizations exclude coal that may be purchased and resold during 2007.

Successor Period Twelve Months Ended December 31, 2005 compared to Predecessor Period from January 1, 2004 Through July 29, 2004 and Successor Period from April 23, 2004 (date of incorporation) Through December 31, 2004 (“Five Month Operating Period Ended December 31, 2004”)

As previously described there are significant differences in the basis of financial reporting between the Successor and Predecessor periods as a result of the purchase of RAG American Coal Holding, Inc. by the Company on July 30, 2004, and the resultant application of purchase accounting to the assets and liabilities acquired. The Successor reported income from continuing operations of $88.9 million and $14.5 million, respectively, for the twelve months ended December 31, 2005 and for the Five Month Operating Period Ended December 31, 2004, whereas the Predecessor reported a loss from continuing operations of $90.6 million for the period from January 1, 2004 through July 29, 2004.

During the period from January 1, 2004 through July 29, 2004 the Predecessor incurred approximately $27.4 million, net of income taxes, of non-cash charges related to termination of hedge accounting for interest rate swaps, partly offset by a net mark-to-market gain on the interest rate swaps. The Predecessor also incurred charges for early extinguishment of debt of $13.8 million, net of income taxes, and a coal contract settlement of $16.5 million, net of income taxes. These one-time charges total $57.7 million, net of income taxes. These charges in combination with below normal coal production from our Northern Appalachia mines were the primary reason for the significant loss from continuing operations.

During the twelve months ended December 31, 2005, the Successor achieved stronger production and tons sold, enjoyed significantly higher per ton sales realizations and received the benefit of a net credit from amortization of coal supply agreements, reflecting amortization of a liability established for below market contracts in purchase accounting. Year-over-year increases in cost of coal sales, selling, general and administrative expenses and depreciation, depletion and amortization were more than absorbed by higher coal sales revenues. The operating trends discussed in the following section, Twelve months ended December 31, 2005 compared to Non-GAAP Combined twelve months ended December 31, 2004, also apply to comparisons of the Successor periods and the Predecessor period from January 1, 2004 through July 29, 2004.

Historical and Non-GAAP Combined

Consolidated Condensed Statements of Operations

(Dollars in thousands)


	Successor						Predecessor			Non-GAAP Combined (Unaudited)
	Twelve Months Ended December 31, 2005			Five Month Operating Period Ended December 31, 2004			Period From January 1 Through July 29, 2004			Twelve Months Ended December 31, 2004
Revenues	$	1,316,929		$	444,596		$	551,035		$	995,631
Cost of coal sales		936,201			345,791			484,457			830,248
Selling, general & administrative expense		48,437			24,596			27,375			51,971
Accretion on asset retirement obligations		8,507			3,300			4,020			7,320
Write-down of long-lived asset		1,633			—			—			—
Depreciation, depletion & amortization		211,186			84,843			61,236			146,079
Amortization of coal supply agreements		(84,903	)		(67,238	)		8,837			(58,401	)

Income (loss) from operations		195,868			53,304			(34,890	)		18,414
Interest expense		(59,495	)		(26,677	)		(18,010	)		(44,687	)
Interest income		1,161			507			1,274			1,781
Loss on termination of hedge accounting for interest rate swaps		—			—			(48,854	)		(48,854	)
Loss on early debt extinguishment		—			—			(21,724	)		(21,724	)
Contract settlement		—			—			(26,015	)		(26,015	)
Mark-to-market gain on interest rate swaps		—			530			5,804			6,334

Income (loss) before income taxes		137,534			27,664			(142,415	)		(114,751	)
Income tax (expense) benefit		(46,461	)		(13,600	)		51,824			38,224

Income (loss) from continuing operations		91,073			14,064			(90,591	)		(76,527	)
Income from discontinued operations, net of income tax expense		—			—			23,065			23,065

Net income (loss)	$	91,073		$	14,064		$	(67,526	)	$	(53,462	)

Twelve Months Ended December 31, 2005 Compared to Non-GAAP Combined Twelve Months Ended December 31, 2004

Coal sales realization per ton sold represents the average revenue realized on each ton of coal sold. It is calculated by dividing coal sales revenues by tons sold.

Revenues


	Successor				Predecessor		Non-GAAP Combined (Unaudited)
	Twelve Months Ended December 31, 2005		Five Month Operating Period Ended December 31, 2004		Period From January 1 Through July 29, 2004		Twelve Months Ended December 31, 2004
	(In thousands, except per ton data)
Coal sales	$	1,292,411	$	436,035	$	554,882	$	980,917
Other revenue		24,518		8,561		6,153		14,714

Total revenues	$	1,316,929	$	444,596	$	551,035	$	995,631

Tons sold		68,781		27,557		35,911		63,468
Coal sales realization per ton sold	$	18.79	$	15.80	$	15.18	$	15.47

Coal sales revenues for the twelve months ended December 31, 2005 increased by $311.5 million (32)% compared to the Non-GAAP Combined coal sales revenues for the twelve months ended December 31, 2004 as a result of an 8% increase in tons sold and a 22% increase in average coal sales realization per ton.

Coal sales volumes in Northern Appalachia increased by 3.0 million tons (28%) as a result of increased shipments from both the Emerald (1.2 million tons) and Cumberland (1.8 million tons) mines. Combined production from the two mines and from Cumberland alone set annual records. Coal sales volumes in Northern Appalachia during 2004 were decreased by interruptions to operations caused by: (a) the idling of the Cumberland mine longwall for approximately eleven weeks as explained below, (b) an extended duration longwall move at the Emerald mine during the first quarter of 2004, and (c) adverse mining conditions at Emerald during the third quarter of 2004. Including the extended duration longwall move mentioned above, Emerald had two longwall moves in 2004 compared with only one in 2005. Cumberland had one longwall move in each year. From February 17 through May 7, 2004, the longwall mining equipment at the Cumberland mine was idled due to alleged violations resulting from a revised interpretation of regulations issued by MSHA regarding the ventilation system at the mine. In response, we revised the ventilation system to minimize any future business disruption and on May 7, 2004 we resumed longwall operations at the Cumberland mine. There were no interruptions of production due to ventilation issues during 2005.

Coal sales volumes in Central Appalachia increased by 1.0 million tons (13%) due to increased sales of purchased coal in 2005 plus higher production at the Kingston and Pioneer/Pax mines, which was partly offset by lower production from the Laurel Creek complex. Production capacity at Kingston was expanded in early 2005 by the addition of a continuous miner unit. Production from the Pioneer/Pax surface mine complex increased in comparison to 2004 as the closure of the Simmons Fork mine was more than offset by production from the developing Pax mine. The Pax mine produced 0.6 million tons during 2005. When fully developed in 2006, it is expected to produce approximately one million tons of coal per year. Coal sales volumes in the Powder River Basin increased by 1.9 million tons (5%), to an annual record level of 43.6 million tons. A higher level of committed sales was partly offset by worse than expected levels of rail service brought on by unusually inclement weather during May and resultant repairs to the rail lines, particularly the UP/BNSF joint line south of Gillette. During the second half of 2005, our Powder River Basin mines shipped at an annualized rate of 45.4 million tons, approximately equal to our expected total year 2005 shipments prior to the disruptions to rail service. Coal sales volumes from the Illinois Basin increased by 0.1 million tons (5%) reflecting shipments made to fulfill new contract obligations. Purchased coal activities by our trading group decreased by approximately 0.7 million tons compared to the prior year due to the timing of purchased coal transactions.

Coal sales realization per ton sold in Northern and Central Appalachia increased by 31% and 29%, respectively, in 2005 due to substitution of higher priced contracts, which took effect in late 2004 and during 2005, for lower priced contracts that rolled off. An additional factor in Northern Appalachia was higher coal quality premiums for sulfur content as a result of record prices for sulfur dioxide allowances and lower sulfur content of shipped coal. In the Powder River Basin, coal sales realizations per ton declined by 2% due to the expiration at the end of 2004 of higher priced contracts signed during the 2001 market increase, partly offset by higher sulfur premiums. The weighted-average coal sales realization per ton sold of $18.79 for 2005 also benefited from a larger proportion of higher priced Northern Appalachia and Central Appalachia tons sold relative to the lower priced tons from the Powder River Basin.

Other revenues for the twelve months ended December 31, 2005 increased by $9.8 million (67%) compared to the Non-GAAP Combined other revenues for the twelve months ended December 31, 2004. The increase was partly due to charges totaling $8.4 million during the 2004 period for settlement of future coal sales commitments compared to $3.6 million of such charges in 2005, combined with higher revenues for synfuel fees ($3.0 million) and higher coal bed methane sales and coal bed methane royalties ($1.9 million) during the 2005 period.

Costs and Expenses


	Successor						Predecessor		Non-GAAP Combined (Unaudited)
	Twelve Months Ended December 31, 2005			Five Month Operating Period Ended December 31, 2004			Period From January 1 Through July 29, 2004		Twelve Months Ended December 31, 2004
	(In thousands)
Cost of coal sales (excludes depreciation, depletion and amortization)	$	936,201		$	345,791		$	484,457	$	830,248
Selling, general and administrative expense (excludes depreciation, depletion and amortization)		48,437			24,596			27,375		51,971
Accretion on asset retirement obligations		8,507			3,300			4,020		7,320
Write-down of long-lived asset		1,633			—			—		—
Depreciation, depletion and amortization		211,186			84,843			61,236		146,079
Amortization of coal supply agreements		(84,903	)		(67,238	)		8,837		(58,401	)

Total costs and expenses	$	1,121,061		$	391,292		$	585,925	$	977,217

Cost of coal sales. The cost of coal sales for the twelve months ended December 31, 2005 increased from the Non-GAAP Combined cost of coal sales for the twelve months ended December 31, 2004 primarily due to: (a) increases in labor costs as a result of both compensation increases and hiring of additional personnel ($38.0 million); (b) increases in many categories of materials and services as a result of significantly higher commodity prices particularly for steel products and diesel fuel ($86.0 million); (c) increases in royalties and coal production taxes as a result of higher revenues ($17.8 million), partly offset by reduced purchased coal costs ($4.9 million); (d) reduced pension and other postretirement net periodic benefit costs due to elimination of amortization of actuarial losses as a result of purchase accounting ($9.9 million); and (e) reduced overburden removal costs reflected in depreciation, depletion and amortization as a result of purchase accounting ($21.4 million). Cost of coal sales per ton were $13.61 for the twelve months ended December 31, 2005 compared to a Non-GAAP Combined figure of $13.08 for the twelve months ended December 31, 2004, an increase of 4%.

Selling, general and administrative expenses. Selling, general and administrative expenses for the twelve months ended December 31, 2005 totaled $48.4 million compared to the Non-GAAP Combined expense of $52.0 million for the twelve months ended December 31, 2004. Year-over-year decreases in 2005 are primarily due to additional expenses incurred in the areas of: (a) directors’ and officers’ insurance premiums ($1.1 million); (b) audit fees, including Sarbanes Oxley 404 compliance ($2.9 million); (c) information technology costs ($0.9 million); (d) salaries and cash incentive compensation ($1.7 million); (e) non-cash stock compensation expense ($0.7 million); and (f) office rent ($0.3 million), offset by lower legal fees ($1.6 million); reduced health care and pension costs ($2.3 million); reduced sales commissions ($0.8 million); elimination of the sponsor monitoring fee in 2005 ($2.0 million); expenses incurred in 2004 by the predecessor representing management incentive plan expenses ($2.4 million); a one-time bonus awarded to certain employees in 2004 in connection with the sale of RAG American Coal Holding, Inc. ($1.8 million); and amortization of actuarial losses on pensions, other postretirement benefits and black lung benefits included in 2004, but not in 2005 as a result of purchase accounting ($0.4 million).

Accretion on asset retirement obligation. Accretion on asset retirement obligation is a component of accounting for asset retirement obligations under SFAS No. 143. Accretion represents the increase in the asset retirement liability to reflect the change in the liability for the passage of time. Higher accretion expense year-over-year is to be expected as the imputed interest factor is applied to an increasing obligation.

Write-down of long-lived assets. In accordance with SFAS No. 144, the Company recognized a $1.6 million non-cash asset impairment charge related to development costs that were attributable to expanding certain undeveloped areas of mining districts in the Company’s Northern Appalachia business unit. As a result of a change in the Company’s mine plan, these costs were no longer considered recoverable.

Depreciation, depletion and amortization. Depreciation, depletion and amortization includes depreciation of plant and equipment, cost depletion of amounts assigned to coal lands and mining rights and amortization of mine development costs and leasehold improvements. Expense increased in the twelve months ended December 31, 2005 compared to the Non-GAAP Combined expense for the year ended December 31, 2004, primarily due to a full year of depreciation, depletion and amortization in 2005 of the increased asset values assigned in purchase accounting, as well as depreciation of capital additions made during 2005.

Coal supply agreement amortization. Application of purchase accounting resulted in recognition of a significant liability for below market priced coal supply agreements as well as a significant asset for above market priced coal supply agreements, both in relation to market prices at the acquisition date. Amortization of the liability for below market priced coal supply agreements during the twelve months ended December 31, 2005 and the Five Month Operating Period Ended December 31, 2004 totaled $109.9 million and $88.2 million of credits to expense, respectively. Amortization of the asset for above market priced coal supply agreements during the same periods totaled $25.0 million and $21.0 million of charges to expense, respectively. The increase in net credit from amortization of coal supply agreements for the year ended December 31, 2005 compared to the Non-GAAP Combined net credit for the twelve months ended December 31, 2004 is due to a full year of post purchase accounting amortization in 2005.

Segment Analysis

Utilizing data published by Argus Media, the following graph sets forth representative steam coal prices in various U.S. markets for the period from January 1, 2004 through December 31, 2005. The prices are not necessarily representative of the coal prices actually obtained by the Company. Changes in coal prices have an impact over time on the Company’s average sales realization per ton and, ultimately, its consolidated financial statements.

LOGO


	Successor				Predecessor			Non-GAAP Combined (Unaudited)
	Twelve Months Ended December 31, 2005		Five Month Operating Period Ended December 31, 2004		Period From January 1 Through July 29, 2004			Twelve Months Ended December 31, 2004
	(In thousands, except per ton data)
*Powder River Basin*
Tons sold		43,612		17,900		23,796			41,696
Average sales realization per ton	$	7.47	$	7.80	$	7.51		$	7.64
Revenues	$	327,595	$	140,237	$	179,758		$	319,995
Income from operations	$	23,564	$	3,454	$	30,748		$	34,202

*Northern Appalachia*
Tons sold		13,678		4,819		5,844			10,663
Average sales realization per ton	$	35.00	$	26.33	$	27.07		$	26.74
Revenues	$	483,511	$	128,072	$	160,562		$	288,633
Income (loss) from operations	$	174,555	$	49,421	$	(10,368	)	$	39,053

*Central Appalachia*
Tons sold		8,936		3,431		4,454			7,885
Average sales realization per ton	$	45.37	$	36.38	$	35.02		$	35.61
Revenues	$	416,976	$	122,050	$	159,004		$	281,054
Income (loss) from operations	$	49,624	$	21,829	$	(9,797	)	$	12,032

Powder River Basin—Income from operations for the twelve months ended December 31, 2005 was $23.6 million compared to Non-GAAP Combined income from operations of $34.2 million for the twelve months ended December 31, 2004. The decrease in operating income is primarily due to higher depreciation, depletion and amortization (“DD&A”) expense of $24.3 million in 2005 as a result of increased values assigned to plant, equipment and owned and leased mineral rights in purchase accounting as of July 30, 2004. The increase in DD&A is partly offset by higher revenues ($7.6 million), reflecting increased coal shipments and higher coal quality premiums partly offset by lower sales realizations per ton, and a lower charge for amortization of coal supply agreements ($7.1 million), reflecting the expiration of several above market coal supply agreements at year end 2004. Cost of coal sales for the twelve months ended December 31, 2005 were comparable to Non-GAAP Combined cost of coal sales for the twelve months ended December 31, 2004. Increases in 2005 in labor costs ($3.3 million), materials, supplies and repair expenses ($14.1 million), mainly due to higher commodity prices, and royalties and production taxes ($2.5 million), due to higher sales revenues, were offset by an increased expense credit for deferral of overburden removal costs into work-in-process inventory ($21.0 million).

Northern Appalachia—Income from operations for the twelve months ended December 31, 2005 was $174.6 million compared to Non-GAAP Combined income from operations of $39.0 million for the twelve months ended December 31, 2004. The significant improvement is primarily due to increased revenues of $194.9 million resulting from a 28% increase in tons sold and a 31% increase in average sales realization per ton. Production from the Cumberland mine increased substantially during 2005. During the first half of 2004, Cumberland’s longwall was idle from February 17 to May 7 for reasons previously described. Production at Emerald also increased year-over-year due to one longwall move in 2005 compared to two longwall moves in 2004 and improved mining conditions in 2005. Higher revenues and a $9.9 million larger credit from amortization of coal supply agreements valued in purchase accounting were partly offset by increases in labor and employee benefit expenses ($16.3 million), materials and supplies ($26.5 million), coal production taxes ($2.2 million), depreciation, depletion and amortization ($22.8 million) and write-off of deferred longwall development costs ($1.6 million) in 2005. These expense increases were due to a combination of higher tons sold and increased prices for labor, fringe benefits and materials and supplies. Cost of coal sales per ton decreased approximately 6% year-over-year.

Central Appalachia—Income from operations for the twelve months ended December 31, 2005 was $49.6 million compared to Non-GAAP Combined income from operations of $12.0 million for the twelve months ended December 31, 2004. Revenues increased by $135.9 million mainly due to a 13% increase in tons sold, driven by higher sales of purchased coal and increased production at the Kingston and Pax mines, and a 29% increase in average sales realizations per ton. The credit for expense from amortization coal supply agreements valued in purchase accounting was $6.7 million higher in 2005. Higher revenues were partly offset by increased expenses for: (a) labor and fringe benefits ($10.4 million); (b) materials and supplies, led by increases for roof control materials and diesel fuel ($24.5 million); (c) purchased coal ($43.3 million); (d) royalties and severance taxes driven by higher sales revenues ($8.0 million); (e) depreciation, depletion and amortization ($17.1 million); and (f) increased other expenses ($1.5 million). Cost of coal sales in both periods included charges of approximately $1.5 million each year for litigation settlements. These expense increases were due to a combination of higher tons sold and increased prices for labor, fringe benefits, materials and supplies and purchase coal. Cost of coal sales per ton increased approximately 22% year-over-year.

Other—Includes the Company’s Wabash mine, located in the Illinois Basin, expenses associated with closed mines, its coal trading operations and selling, general and administrative expenses not charged-out to the Powder River Basin, Northern Appalachia and Central Appalachia mines. During the twelve months ended December 31, 2005, the Other segment reported a loss from operations of $51.9 million compared to a Non-GAAP Combined loss from operations of $66.9 million in the twelve months ended December 31, 2004. The reduced year-over-year loss from operations of $15.0 million was mainly due to a combination of: (a) reduced pension and retiree medical expenses in 2005 as a result of the elimination of amortization of actuarial losses and prior service costs in purchase accounting ($5.5 million); (b) increased tons sold and higher average sales realizations per ton at the Wabash mine in 2005 partly offset by higher cash operating costs and depreciation, depletion and amortization expenses ($0.9 million); increased credit to expense from amortization of coal supply agreements in 2005 ($2.8 million) and reduced selling, general and administrative expenses in 2005 ($3.7 million).

Interest Expense, Net


	Successor						Predecessor			Non-GAAP Combined (Unaudited)
	Twelve Months Ended December 31, 2005			Five Month Operating Period Ended December 31, 2004			Period From January 1 Through July 29, 2004			Twelve Months Ended December 31, 2004
	(In thousands)
Interest expense—debt related	$	(42,580	)	$	(17,894	)	$	(16,214	)	$	(34,108	)
Interest expense—amortization of deferred financing fees		(4,787	)		(4,408	)		—			(4,408	)
Interest expense—surety bond and letter of credit fees		(10,153	)		(4,375	)		(1,796	)		(6,171	)
Interest expense—other		(1,975	)		—			—			—
Total interest expense		(59,495	)		(26,677	)		(18,010	)		(44,687	)
Interest income		1,161			507			1,274			1,781
Interest expense, net	$	(58,334	)	$	(26,170	)	$	(16,736	)	$	(42,906	)

Debt related interest expense for the twelve months ended December 31, 2005 was higher than the Non-GAAP Combined debt related interest expense for twelve months ended December 31, 2004 due to: (a) a larger balance of debt outstanding after July 30, 2004 due to the transaction; (b) imputed interest charges that began in the second half of 2004; and (c) greater utilization of the revolving credit agreement. Non-GAAP Combined amortization of deferred financing fees for the twelve months ended December 30, 2004 includes $3.0 million of accelerated amortization from the repayment of variable rate debt with Public Parent IPO proceeds and cash on hand at year end 2004; there is $1.6 million of accelerated amortization from repayment of variable rate debt in the year ended December 31, 2005. The increase in surety bond and letter of credit fees for the twelve months ended December 31, 2005 compared to the Non-GAAP Combined expense for the twelve months ended December 31, 2004 is due to higher balances of financial assurance instruments from the transaction date forward. The reduction in interest income between the years is primarily due to lower cash balances available for investment in 2005.

Income Tax (Expense)


	Successor						Predecessor		Non-GAAP Combined (Unaudited)
	Twelve Months Ended December 31, 2005			Five Month Operating Period Ended December 31, 2004			Period From January 1 Through July 29, 2004		Twelve Months Ended December 31, 2004
	(In thousands)
Income tax (expense) benefit	$	(46,461	)	$	(13,600	)	$	51,824	$	38,224

For the twelve months ended December 31, 2005, income taxes are provided at an effective rate of approximately 34%. Current tax expense, which represents taxes currently payable on operations, was approximately 14% of pre-tax income. We provided a full valuation allowance against deferred tax assets attributable to alternative minimum tax credits in both successor periods. Management has determined that the Company does not meet the more likely than not criteria with regard to future utilization of these alternative minimum tax credits. For the Five Month Operating Period Ended December 31, 2004, income tax expense was accrued at a blended federal and state income tax rate of approximately 48%. This effective income tax rate exceeds the federal statutory income tax rate of 35% primarily due to the establishment of a valuation allowance against alternative minimum tax credits. In the period from January 1, 2004 through July 29, 2004, a deferred income tax benefit was recognized at a blended federal and state income tax rate of

36%, and substantially all of the net operating losses were realized as a result of the Acquisition. The valuation allowance of $4.6 million previously established against the deferred tax assets associated with certain net operating loss carryforwards was released as a credit to income tax expense in this predecessor period.

Significant Property Transaction

In the third quarter of 2006, Pioneer Fuel Corporation, an indirect wholly owned subsidiary of the Company, purchased mining assets from Appalachian Fuels, LLC for $15.4 million. The purchased assets consisted of approximately 7.3 million tons of reserves, land and mining equipment. The acquired reserves are located adjacent to and will be integrated with the existing Pax surface operations and jointly managed. The acquired mine, referred to as Pax South, is expected to produce up to 720,000 tons per years, after it reaches full capacity, and to provide other synergies to existing properties. In accordance with terms set forth in the asset purchase agreements, $1.0 million of the purchase price was withheld for contingencies, but will be remitted to Appalachian Fuels eighteen months after the acquisition date if no contingencies materialize. The purchase price was allocated to the assets and asset retirement obligation acquired/assumed based upon estimates of fair value. In a separate transaction, coal stockpiles containing an estimated 8,300 tons were also acquired from Appalachian Fuels, LLC for $0.2 million.

Liquidity and Capital Resources

Sources and Uses of Cash

Our primary sources of cash have been sales of our coal production and purchased coal to customers, cash from sales of non-core assets and miscellaneous revenues.

Our primary uses of cash have been our cash costs of coal production, the cash cost of purchased coal, capital expenditures, interest costs, income taxes, cash payments for employee benefit obligations such as defined benefit pensions and retiree health care benefits, cash outlays related to post mining asset retirement obligations and support of working capital requirements such as coal inventories and trade accounts receivable. Our ability to service our debt and acquire new productive assets for use in our operations has been and will be dependent upon our ability to generate cash from our operations. We generally fund all of our capital expenditure requirements with cash generated from operations. Historically, we have engaged in minimal financing of assets such as through operating leases.

The following is a summary of cash provided by or used in each of the indicated categories of activities during the twelve months ended December 31, 2006 and 2005, respectively.


	Twelve Months Ended December 31,
	2006			2005
	(In thousands)
Cash provided by (used in):
Operating activities	$	225,654		$	177,819
Investing activities (primarily capital expenditures)		(199,868	)		(130,438	)
Financing activities—borrowings¹		—			76,000
Financing activities—repayments¹		(8,375	)		(126,000	)
Financing activities—excess tax benefit from stock-based awards		9,486			—
Financing activities—proceeds from interest rate swap termination		2,259			—
Financing activities—capital contribution from Public Parent		7,565			—
Financing activities—dividends to Public Parent		(20,977	)		—
Financing activities—deferred financing costs		(4,457	)		—

Change in cash and cash equivalents	$	11,287		$	(2,619	)

The borrowings during the twelve months ended December 31, 2005 in the amount of $76.0 million represent use of the revolving credit facility to maintain day-to-day liquidity. Repayments during the twelve months ended December 31, 2005 include $76.0 million related to the revolving credit facility and $50.0 million related to the repayment of long-term debt.

Cash provided by operating activities increased in the twelve months ended December 31, 2006 compared to the twelve months ended December 31, 2005 due to lower net income more than offset by increased non-cash adjustments to income and smaller changes in operating working capital, principally trade accounts receivable and inventories.

Cash used in investing activities increased in the twelve months ended December 31, 2006 compared to the twelve months ended December 31, 2005 primarily from an increase in capital expenditures and the acquisition of mining assets. Capital expenditures in the twelve months ended December 31, 2006 totaled $187.2 million, including a total of $99.0 million of expenditures related to the following projects: (a) an overland coal conveyor at the Belle Ayr mine in the Powder River Basin; (b) equipment for and development of the Pax surface mine and related rail loading facility in Central Appalachia; (c) upgrades to the rail loading facility at Emerald; (d) construction of a new slope, overland coal conveyor and related coal handling facilities at the Wabash mine in Illinois; (e) progress payments toward the purchase of a second longwall at the Emerald mine; and (f) the acquisition and implementation of company wide enterprise resource planning (“ERP”) software. Capital expenditures for the twelve months ended December 31, 2005 totaled $140.2 million, including a total of $49.8 million of expenditures related to the following projects: (a) expansion of the Belle Ayr mine in the Powder River Basin; (b) development of the Pax surface mine in Central Appalachia; (c) addition of a continuous mining unit to the Kingston mine in Central Appalachia; (d) the widening of the Emerald mine longwall face to 1,450 feet from 1,250 feet; and (e) upgrades to the rail loading facility at Emerald.

Cash provided by financing activities during the twelve months ended December 31, 2006 consisted of $7.6 million of capital contributions from the Public Parent; $9.5 million in excess income tax benefit from stock-based awards; and $2.3 million in cash proceeds from the settlement of the interest rate swaps, offset by cash dividends to the Public Parent of approximately $21.0 million for the repurchase of common stock and for the payment of ordinary dividends; $8.4 million for the repayment of long-term debt; and $4.5 million for the payment of financing costs related to bank debt refinancing activities in the third quarter. Cash used in financing activities by the Successor for the twelve months ended December 31, 2005 includes a $50.0 million in prepayments of our senior secured term loan B. These payments were voluntary and consistent with the management’s strategy to deleverage the Company as funds are available from cash flows generated by the business.

In the Predecessor periods, cash balances in excess of our day-to-day operating requirements were placed on deposit with RAG where cash balances could be aggregated to earn better investment returns. This cash on deposit was available to us on a one day turn-around. Increases in the cash on deposit with RAG have been classified under financing activities as uses of cash in the consolidated cash flow statements. Decreases in cash on deposit with RAG have been classified under financing activities as cash provided.

The following is a summary of cash provided by or used in each of the indicated categories of activities during the twelve months ended December 31, 2005, Five Month Operating Period Ended December 31, 2004 and for the period from January 1, 2004 through July 29, 2004:


	Successor			Predecessor
	Twelve Months Ended December 31, 2005			Five Month Operating Period Ended December 31, 2004			Period From January 1 Through July 29, 2004
	(In thousands)
Cash provided by (used in):
Operating activities—continuing operations	$	177,819		$	61,693		$	(8,044	)
Operating activities—discontinued operations		—			—			6,973
Investing activities—continuing operations⁽¹⁾		(130,438	)		(934,932	)		(50,646	)
Investing activities—discontinued operations		—			—			184,954
Financing activities—borrowings⁽²⁾		76,000			830,000			306,057
Financing activities—repayments⁽²⁾		(126,000	)		(145,138	)		(686,901	)
Financing activities—capital contribution from Public Parent		—			241,993			—
Financing activities—deferred financing costs		—			(28,573	)		—
Financing activities—pledged cash		—			—			20,000
Financing activities—on deposit with RAG⁽³⁾		—			—			233,023

Change in cash and cash equivalents	$	(2,619	)	$	25,043		$	5,416

¹	Cash used in investing activities by the Successor for the Five Month Operating Period Ended December 31, 2004 include $904.9 million, net of cash acquired to acquire RAG American Coal Holding, Inc. and subsidiaries from RAG Coal International AG.

³	Represents the decrease in the balance of cash on deposit with RAG.

Cash provided by operating activities from continuing operations increased in the twelve months ended December 31, 2005 as compared to the Non-GAAP Combined results of the Successor for the Five Month Operating Period Ended December 31, 2004 and the Predecessor for the period from January 1, 2004 through July 29, 2004, primarily due to higher net income from continuing operations, partly offset by increases in working capital, mainly trade accounts receivable and inventories.

Cash used in investing activities for continuing operations, excluding the purchase of RAG American Coal Holding, Inc., increased in the twelve months ended December 31, 2005 as compared to the Non-GAAP Combined results of the Successor for the Five Month Operating Period Ended December 31, 2004 and the Predecessor for the period from January 1, 2004 through July 29, 2004 due to higher capital expenditures in the 2005 period. Capital expenditures for the twelve months ended December 31, 2005 totaled $140.2 million, including $49.8 million of expenditures related to the expansion of the Belle Ayr mine in the Powder River Basin, development of the Pax surface mine and related rail loading facility in Central Appalachia, addition of a continuous mining unit to the Kingston mine in Central Appalachia, the widening of the Emerald mine longwall face to 1,450 feet from 1,250 feet and upgrades to the rail loading facility at Emerald. Non-GAAP Combined capital expenditures of the Successor for the Five Month Operating Period Ended December 31, 2004 and for the Predecessor for the period from January 1, 2004 through July 29, 2004 of $86.3 million were mainly for replacement of equipment and other expenditures necessary to sustain mine operations.

Cash used in financing activities of the Predecessor for the period from January 1, 2004 through July 29, 2004 represents repayment of all long-term debt of the Predecessor including cash prepayment penalties coupled with the settlement of the Predecessor’s interest rate swaps. These repayments utilized the proceeds from the sale of the RAG Colorado Business Unit, cash previously reported as cash on deposit with Parent, cash pledged and $306.0 million of cash advanced by RAG Coal International AG that the Predecessor repaid from a portion of the cash acquisition price that Foundation Coal paid to RAG.

The cash acquisition price, including transaction costs, of $904.9 million paid by Foundation for RAG American Coal Holding, Inc and subsidiaries, net of cash acquired, was funded by $830.0 million of Successor long-term debt, consisting of $470.0 million of senior secured term Loan B, $300.0 million of senior unsecured long-term notes, $60.0 million of drawings under the $350.0 million revolving credit facility and $196.0 million of cash equity contributed by the shareholders. The $60.0 million of drawings under the revolving credit facility were fully repaid on the first business day after the Acquisition utilizing cash of the acquired subsidiaries. The $34.4 million other cash used in financing activities consists of $28.6 million for costs associated with arranging the long-term debt used to fund the Acquisition, which are accounted for as deferred financing fees and are included in the cash outflows for “Financing activities—deferred financing costs.”

The sale of the RAG Colorado Business Unit to a third party closed on April 15, 2004. The cash proceeds from the sale, prior to final purchase price adjustments, were $182.7 million. Purchase price adjustments totaled $0.5 million. With this receipt, we realized a pre-tax gain on sale of the discontinued operation of $25.7 million. The proceeds were deposited into an escrow account at DZ Bank. In addition, $221.4 million of our cash on deposit with RAG was also deposited into this escrow account. On April 27, 2004, the escrow account balance of $404.2 million, including interest earned on the account of $0.1 million, was used to: (a) repay the Tranche A Notes due to DZ Bank and Dresdner in the combined amount of $358.0 million; (b) pay accrued interest on these notes in the amount of $1.5 million; and (c) settle the pay-fixed, receive-variable interest rate swaps for a payment of $44.7 million as mentioned above.

The remaining Predecessor long-term debt, accrued interest and related prepayment penalties, totaling approximately $305.9 million, were repaid on July 28, 2004 utilizing $306.0 million of cash advanced by RAG. This advance was repaid using a portion of the cash acquisition price that Foundation Coal Corporation paid to RAG.

Liquidity and Long-Term Debt

Our primary source of liquidity will continue to be cash from sales of our coal production and purchased coal to customers. We have availability under our revolving credit facility, subject to certain conditions.

Based on our current levels of operations, we believe that remaining cash on hand, cash flow from operations and available borrowings under the revolving credit portion of our Senior Secured Credit Facility will enable us to meet our working capital, capital expenditure, debt service and other funding requirements for at least the next twelve months.

As of December 31, 2006, we have outstanding $626.6 million in aggregate indebtedness, with an additional $331.2 million of available borrowings under our revolving credit facility after giving effect to $168.8 million of letters of credit outstanding and had $326.6 million outstanding borrowings under the Term Loan A component of the facility as of December 31, 2006. Our liquidity requirements will be significant, primarily due to debt service requirements and projected capital expenditures.

Bank Debt Refinancing

Our Senior Secured Credit Facility consists of a revolving credit facility and a term loan facility.

During 2006, the Company completed an $835.0 million amended and restated Senior Secured Credit Facility (the “facility”) agreement consisting of a five-year $335.0 million Term Loan A and a five-year $500.0 million revolving credit facility. The facility, which matures on July 11, 2011, bears interest at an applicable margin, plus the lenders’ base rate or LIBOR at the Company’s option, and requires the Company to pay a commitment fee to the lenders for the unutilized portion of the commitment under the revolving credit facility based on a quarterly leverage ratio calculation. The revolving credit facility provides for up to $500.0 million for borrowings on same-day notice, referred to as swingline loans, LIBOR loans or letters of credit up to a maximum of the unutilized portion of the revolver. Costs capitalized in connection with the facility were $4.5 million and are being amortized over the term of the related indebtedness of five years, using the effective interest method. The facility replaces the previous Senior Secured Credit Facility and provides more favorable pricing and financial flexibility. The $500.0 million revolving credit facility will be used for general corporate purposes including working capital, capital expenditures, letters of credit and acquisitions.

In the third quarter of 2006, the Company wrote-off $9.2 million of non-cash unamortized deferred financing costs as a result of the replacement of the original Senior Secured Credit Facility which is included in Interest expense in the Statements of Consolidated Operations and Comprehensive Income (Loss). On December 29, 2006, the Company voluntarily prepaid $8.4 million of the outstanding balance of the term loan facility due in 2007 and wrote-off an additional $0.1 million of non-cash unamortized deferred financing cost.

Borrowings under our Senior Secured Credit Facility bear interest at a floating rate plus an applicable margin. The highest applicable margin for borrowings under both the revolving credit facility and the term loan facility is 0.75% with respect to base rate borrowings and 1.75% with respect to LIBOR borrowings. Based on our leverage ratio as of December 31, 2006, the applicable margins on both the revolving credit facility and the term loan facility have been reduced to 0.25% and 1.25%, respectively.

In addition to paying interest on outstanding principal under the Senior Secured Credit Facility, we will be required to pay a commitment fee to the lenders under the revolving credit facility in respect of the unutilized commitments, beginning at a rate equal to 0.375% per annum of the unused commitment. Based on our leverage ratio as of December 31, 2006, our rate has been reduced to 0.25%. We also pay customary letter of credit fees.

The Senior Secured Credit Facility requires us to prepay the outstanding term loan, subject to certain exceptions, in certain situations. Any mandatory prepayments would be applied to the remaining scheduled installments of the term loan facility on a pro rata basis. Optional prepayments would be applied to the term loan facility at our direction. If prepaid, there would be a charge for any breakage costs.

At the inception of the facility, we were required to repay installments on the term loan in quarterly principal amounts of $4.2 million beginning in September 2007, stepping up to $8.4 million in September 2009, with the remaining balance of $242.9 million due on the July 11, 2011 maturity date. Because we prepaid $8.4 million of outstanding principal on December 29, 2006, we are not required to make a quarterly principal payment until March 2008.

Principal amounts outstanding under the revolving credit facility will be due and payable in full at maturity, five years from the date of the closing of the Senior Secured Credit Facility.

The Senior Secured Credit Facility contains a number of covenants that, among other things, restrict, subject to certain exceptions, the ability of certain of our subsidiaries, and the ability of each guarantor under the credit facility to incur additional indebtedness or issue preferred stock, repay other indebtedness (including the 7.25% Senior Notes), pay dividends and distributions or repurchase our capital stock, make investments, loans or advances, make certain acquisitions, engage in mergers or consolidations, enter into sale and leaseback transactions and enter into hedging agreements. Financial covenants include an interest coverage ratio test, a leverage ratio test, a limit on capital expenditures and a limit on dividends.

The indenture governing our outstanding 7.25% Senior Notes limits our ability and the ability of our Public Parent and our restricted subsidiaries to incur additional indebtedness, pay dividends on or make other distributions or repurchase capital stock issued by our Public Parent, make certain investments, limit dividends or other payments by our restricted subsidiaries, and sell certain assets or merge with or into other companies. Our indenture allows for the payment of dividends by Foundation Coal Corporation to our Public Parent. Foundation Coal Corporation will have the ability, subject to certain exceptions as set forth in the indenture, to incur additional indebtedness if it meets certain conditions, including having greater than a 2.0 to 1.0 fixed charge coverage ratio.

Interest Rate Swaps

On September 30, 2004, the Company entered into pay-fixed, receive-variable interest rate swap agreements on a notional amount of $85.0 million. These swap agreements essentially converted $85.0 million of the Company’s variable rate borrowings under the then existing facility to fixed rate borrowings for a three year period that began on September 30, 2004. The maturity date on the swap agreements is September 28, 2007. The Company designated these interest rate swaps as cash flow hedges of the variable interest payments and recorded the quarterly changes in the fair value of the instruments in Other noncurrent assets with an offsetting unrealized gain, net of tax expense, in Accumulated other comprehensive loss.

In connection with the 2006 closing of the amended and restated Senior Secured Credit Facility, the Company terminated the swap agreements. On the date the Company made the decision to terminate the interest rate swaps, the interest rate swaps no longer qualified for cash flow hedge accounting treatment and accordingly, any change in the market value of the interest rate swaps affects net income. On July 11, 2006, the Company monetized the $2.4 million derivative asset included in Other noncurrent assets in the Company’s consolidated financial statements at June 30, 2006 and recognized a $0.1 million mark-to-market loss on the swaps. The $1.8 million unrealized gain from the change in the market value of the interest rate swaps recorded in Accumulated other comprehensive loss will be recognized into income on a prorated basis over the remaining term of the original interest rate swap agreement through September 28, 2007, in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and related amendments.

Other

As a regular part of our business, we review opportunities for, and engage in discussions and negotiations concerning, the acquisition of coal mining assets, including Lease by Application (“LBA”) bids, and acquisitions of, or combinations with, coal mining companies. When we believe that these opportunities are consistent with our growth plans and our acquisition criteria, we will make bids or proposals and/or enter into letters of intent and other similar agreements, which may be binding or nonbinding, that are customarily subject to a variety of conditions and usually permit us to terminate the discussions and any related agreements if, among other things, we are not satisfied with the results of our due diligence investigation. Any acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. There can be no assurance that such additional indebtedness and/or equity capital will be available on terms acceptable to us, if at all.

On July 18, 2006, the Board of Directors authorized a stock repurchase program (the “Repurchase Program”), authorizing the Company’s Public Parent to repurchase shares of its common stock. The Company’s Public Parent may repurchase its common stock from time to time as determined by authorized officers of the Company, up to an aggregate amount of $100.0 million. Through December 31, 2006, the Company expended $11.9 million to repurchase 323,000 shares of its common stock at an average price of $36.81 under the Repurchase Program.

Covenant Compliance

The Company is required to comply with certain financial covenants which are considered material terms of the Senior Secured Credit Facility and the indenture governing the Company’s outstanding 7.25% Senior Notes. Information about the financial covenants is material to an investor’s understanding of the Company’s financial condition and liquidity. The breach of covenants in the Senior Secured Credit Facility that are tied to ratios based on Adjusted EBITDA, as defined below, could result in a default under the Senior Secured Credit Facility and the lenders could elect to declare all amounts borrowed due and payable. Any such acceleration would also result in a default under our indenture. Additionally, under the Senior Secured Credit Facility and indenture, the Company’s ability to engage in activities such as incurring additional indebtedness, making investments and paying dividends is also tied to ratios based on Adjusted EBITDA.

Covenants and required levels as defined by the Senior Secured Credit Facility and the indenture governing the outstanding 7.25% Senior Notes are:


	Covenant Level	December 31 2006 Ratios
		(Unaudited)
Senior Secured Credit Facility¹	2.5x	6.7x
Minimum Adjusted EBITDA to cash interest ratio
Maximum total debt less unrestricted cash to Adjusted EBITDA ratio	4.25x	1.9x
Indenture²
Minimum Adjusted EBITDA to fixed charge ratio required to incur additional debt pursuant to ratio provisions	2.0x	6.7x

The Senior Secured Credit Facility requires us to maintain an Adjusted EBITDA to cash interest ratio at a minimum of 2.5x and a total debt less unrestricted cash to Adjusted EBITDA ratio starting at a maximum of 4.25x in each case for the most recent twelve month period. Failure to satisfy these ratio requirements would constitute a default by us under the Senior Secured Credit Facility. If lenders under the Senior Secured Credit Facility fail to waive any such default, repayment obligations under the Senior Secured Credit Facility could be accelerated, which would also constitute a default under the indenture. Covenants reflect the definition and levels required by the July 7, 2006 amended and restated Senior Secured Credit Facility.

²	Our ability to incur additional debt and make certain restricted payments under our indenture, subject to specified exceptions, is tied to an Adjusted EBITDA to fixed charge ratio of at least 2.0 to 1.

Adjusted EBITDA is defined as EBITDA further adjusted to exclude non-recurring items, non-cash items and other adjustments permitted in calculating covenant compliance under the indenture and the Senior Secured Credit Facility. EBITDA, a measure used by management to evaluate its ongoing operations for internal planning and forecasting purposes, is defined as net income (loss) from operations plus interest expense, net of interest income, income tax expense (benefit), depreciation and amortization and charges for early extinguishment of debt. EBITDA is not a financial measure recognized under United States generally accepted accounting principles and does not purport to be an alternative to net income as a measure of operating performance or to cash flows from operating activities as a measure of liquidity. The amounts shown for EBITDA as presented, may differ from amounts calculated and may not be comparable to other similarly titled measures used by other companies.

As of December 31, 2006, the Company was in compliance with all required financial covenants of the July 7, 2006 amended and restated Senior Secured Credit Facility.


	Twelve Months Ended December 31, 2006		Twelve Months Ended December 31, 2005			Four Quarters Ended December 31, 2004			Five Month Operating Period Ended December 31, 2004			Period From January 1 Through July 29, 2004
	(Unaudited, in thousands)
EBITDA(1)	$	269,274	$	322,151		$	15,833		$	71,439		$	(55,606	)
Non-cash charges (income)(2)		42,103		(10,975	)		70,335			(8,777	)		79,112
Unusual or non-recurring items(3)		1,150		—			36,900			3,746			33,154
Cumberland mine force majeure(4)		—		—			31,090			—			31,090
Other adjustments(5)		1,389		718			(500	)		900			(1,400	)

Adjusted EBITDA	$	313,916	$	311,894		$	153,658		$	67,308		$	86,350

(1)	EBITDA is calculated in the table below:


	Twelve Months Ended December 31, 2006			Twelve Months Ended December 31, 2005			Four Quarters Ended December 31, 2004			Five Month Operating Period Ended December 31, 2004			Period From January 1 Through July 29, 2004
	(Unaudited, in thousands)
Income (loss) from continuing operations	$	33,574		$	91,073		$	(76,527	)	$	14,064		$	(90,591	)
Interest expense		64,525			59,495			44,687			26,677			18,010
Interest income		(3,010	)		(1,161	)		(1,781	)		(507	)		(1,274	)
Income tax expense (benefit)		4,106			46,461			(38,224	)		13,600			(51,824	)
Depreciation, depletion and amortization		183,201			211,186			146,079			84,843			61,236
Amortization of coal supply agreements		(13,122	)		(84,903	)		(58,401	)		(67,238	)		8,837

EBITDA	$	269,274		$	322,151		$	15,833		$	71,439		$	(55,606	)

(2)	We are required to adjust EBITDA, as defined above, for the following non-cash charges (income):


	Twelve Months Ended December 31, 2006		Twelve Months Ended December 31, 2005			Four Quarters Ended December 31, 2004			Five Month Operating Period Ended December 31, 2004			Period From January 1 Through July 29, 2004
	(Unaudited, in thousands)
Interest rate swaps^(a)	$	112	$	—		$	42,520		$	(530	)	$	43,050
Early extinguishment of debt		—		—			21,724			—			21,724
Profit in inventory^(b)		—		—			3,753			3,753			—
Overburden removal included in depreciation, depletion and amortization^(c)		—		(22,624	)		(15,300	)		(15,300	)		—
Accretion on asset retirement obligations		8,510		8,507			7,320			3,300			4,020
Stock-based compensation expense^(d)		2,699		1,509			—			—			—
Write-down of long-lived assets^(e)		30,782		1,633			—			—			—
Amortization included in benefits expense^(f)		—		—			10,318			—			10,318

Total	$	42,103	$	(10,975	)	$	70,335		$	(8,777	)	$	79,112

^(a)

Includes $48.9 million of expense resulting in the period from January 1, 2004 to July 29, 2004 from loss on termination of hedge accounting for interest rate swaps less $5.8 million mark-to-market adjustment. Under the terms of the stock purchase agreement, we did not assume any existing interest rate swaps. For the five month operating period ended December 31, 2004 includes the mark-to-market gain on interest rate swaps not yet designated as cash flow hedges.

^(b)	Represents incremental cost of sales recorded in the period arising from the manufacturing profit added to inventory in purchase accounting.

^(c)

In purchase accounting, the fair value of partially and fully uncovered coal included consideration of the effort spent prior to the purchase date to remove overburden and get the coal to its partially or fully uncovered state. Therefore, the fair value assigned to partially or fully uncovered coal reserves was higher than that assigned to other coal reserves. Depletion of coal reserves, including the incremental fair value related to pre-Acquisition overburden removal efforts, is included in depreciation, depletion and amortization. Subsequent to the Acquisition date, the costs associated with removal of overburden to uncover coal reserves is inventoried as work-in-process until the related coal is mined and the inventoried cost charged to cost of coal sales when the coal is sold. Until coal valued as partially or fully uncovered at the Acquisition date is fully depleted, depreciation, depletion and amortization will include the value of overburden removal performed prior to the Acquisition date; overburden removal, if incurred subsequent to the acquisition date, would have been included in cost of coal sales.

^(d)	Represents compensation expense attributable to restricted stock units and stock options.

^(e)

Represents the write-down of long-lived assets in 2006 of $1.4 million and $29.4 million related to deferred mining royalties at the Central Appalachia business unit and certain long-lived assets at the Wabash mine, respectively, and in 2005 of $1.6 million as a result of a change in the mine plan at the Northern Appalachia business unit.

^(f)

Represents the portion of pension, other postretirement and black lung expense resulting from the amortization of unrecognized actuarial losses, prior service costs and transition obligations. Unrecognized actuarial losses, prior service costs and transition obligations were eliminated when the pension, other postretirement and black lung obligations were fair valued in purchase accounting.

(3)	We are also required to adjust EBITDA, as defined above, for the following unusual (income) expense:


	Twelve Months Ended December 31, 2006		Twelve Months Ended December 31, 2005		Four Quarters Ended December 31, 2004		Five Month Operating Period Ended December 31, 2004		Period From January 1 Through July 29, 2004
	(Unaudited, in thousands)
Litigation/arbitration/contract settlements, net^(a)	$	1,010	$	—	$	28,900	$	—	$	28,900
Transaction bonus^(b)		—		—		1,826		—		1,826
Long-term incentive plan expense^(c)		—		—		2,428		—		2,428
Other^(d)		140		—		3,746		3,746		—

Total	$	1,150	$	—	$	36,900	$	3,746	$	33,154

^(a)	Represents arbitration awards, litigation and contract settlements, net of related legal and tax fees.

^(b)	Represents the cost of a one-time bonus awarded to certain employees in connection with the sale of RAG American Coal Holding, Inc.

^(c)	Represents the cost of a long-term incentive plan instituted by the Seller in 2001 that was terminated prior to closing as required by the change in control provisions in the plan agreement. We have implemented a management equity program that will not result in a cash cost to us.

^(d)

Represents $2.0 million from a sponsor monitoring fee and $1.8 million from a tax allowance related to the IPO of the Public Parent in the period July 30 to December 31, 2004. In addition, other items that are permitted adjustments in calculating covenant compliance under the indenture governing the 7.25% Senior Notes and the Senior Credit Facilities, including directors’ fees, reimbursements of certain union dues by the Seller, black lung settlement charges and costs related to moving our human resources organization from Colorado to Maryland, incurred primarily in the year ended December 31, 2003 and in the period from January 1, 2004 through July 29, 2004, net to an immaterial amount.

(4)

Represents the adjustment required for the estimated impact of the temporary idling of our Cumberland mine in the first half of 2004 as a result of a revised interpretation of mine ventilation laws by MSHA. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information.

(5)	We are also required to make adjustments to EBITDA for items such as incremental insurance costs and franchise taxes not included in income tax expense.

Cash interest for the twelve months ended December 31, 2006 is calculated as follows:


	(Unaudited) (In thousands)
Interest expense	$	64,525
Less: Interest expense as adjusted for debt repayment per the Credit Agreement¹		558
Less: Amortization of deferred financing costs		11,653
Less: Cash interest income		3,010
Less: Other non-cash interest expense		2,655

	$	46,649

¹	Under terms of the Credit Agreement, interest expense is adjusted for all debt incurred or permanently repaid during a reporting period. The interest adjustment is calculated as if the debt had been incurred or repaid at the beginning of the twelve month period.

In future periods, adjustments to EBITDA that could be used to calculate compliance with the debt covenants are: (a) accretion on asset retirement obligations; (b) any non-cash expenses or charges arising as a result of the application of purchase accounting in acquisitions; (c) business optimization expenses or other restructuring charges; (d) non-cash impairment charges resulting from the application of SFAS No. 142, Goodwill and Other Intangible Assets or SFAS No. 144; (e) amortization of intangibles pursuant to SFAS No. 141, Business Combinations; and (f) any long-term incentive plan accruals or any non-cash compensation expense realized from grants of stock appreciation or similar rights, stock options or other rights to officers, directors and employees.

In future periods, cash interest is expected to be calculated by adding back amortization of deferred debt issuance costs and deducting cash interest income from the interest expense reported in the Statement of Consolidated Operations. Other non-cash interest expense above is comprised of: (a) imputed interest expense on an equipment purchase obligation recorded on a present value basis; (b) imputed interest expense on a minimum royalty obligation recorded on a present value basis; and (c) imputed interest expense on a contract settlement liability recorded on a present value basis.

Contractual Obligations

The following is a summary of our significant future contractual obligations by year as of December 31, 2006:


	2007		2008-2009		2010-2011		After 2011		Total
	(Unaudited, in thousands)
Long-term debt	$	—	$	41,875	$	284,750	$	300,000	$	626,625
Cash interest on long-term debt¹		42,115		82,337		68,173		56,188		248,813
Cash payments for asset retirement obligations		2,973		4,569		7,988		198,780		214,310
Unconditional purchase commitments		160,984		26,008		—		—		186,992
Operating leases		3,207		5,256		2,903		4,970		16,336

Total	$	209,279	$	160,045	$	363,814	$	559,938	$	1,293,076

¹	The variable interest rate on debt is 6.23%, reflecting a LIBOR estimate, based on the five year swap rate effective December 28, 2006, plus a margin of 1.25%.

We expect to use cash flows provided by operating activities to invest in the range of $175.0 million to $185.0 million in capital expenditures, excluding the LBA at the Eagle Butte mine, during calendar year 2007 of which $110.0 million to $115.0 million is to maintain production and replace mining equipment. The additional $65.0 million to $70.0 million is expected to be directed toward improvements in productivity and selective expansions of production. Approximately $80.3 million of expected 2007 capital expenditures are included in unconditional purchase commitments shown above. The remaining 2007 unconditional purchase commitments consist of $32.4 million for purchased coal and $47.7 million pertaining to forward contracts to purchase diesel fuel and explosives in normal quantities for use at our surface mines. We expect to contribute approximately $9.7 million to our defined benefit retirement plans and to pay approximately $21.4 million of retiree health care benefits, net of Medicare Part D Subsidies, in calendar year 2007. We also expect to incur approximately $6.5 million per year for surety bond premiums and letters of credit fees. We believe that cash balances plus cash generated by operations will be sufficient to meet these obligations plus fund requirements for working capital and capital expenditures without incurring additional borrowings.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. Liabilities related to these arrangements are not reflected in our Consolidated Balance Sheets. However, the underlying obligations that they secure, such as asset retirement obligations, self-insured workers’ compensation liabilities, royalty obligations and certain retiree medical obligations, are reflected in our Consolidated Balance Sheets.

We are required to provide financial assurance in order to perform the post-mining reclamation required by our mining permits, pay our federal production royalties, pay workers’ compensation claims under self-insured workers’ compensation laws in the various states, pay federal black lung benefits, pay retiree health care benefits to certain retired UMWA employees and perform certain other obligations.

In order to provide the required financial assurance, we generally use surety bonds for post-mining reclamation and royalty payment obligations and bank letters of credit for self-insured workers’ compensation obligations and UMWA retiree health care obligations. Federal black lung benefits are paid from a dedicated trust fund that has sufficient assets to fund these obligations for the next several years. Bank letters of credit are also used to collateralize a portion of the surety bonds.

We had outstanding surety bonds with a total face amount of $261.4 million as of December 31, 2006, of which $237.5 million secured reclamation obligations, $12.6 million secured coal lease obligations, $9.6 million secured self-insured workers’ compensation obligations and $1.7 million secured miscellaneous obligations. In addition, we had $168.8 million of letters of credit in place for the following purposes: $36.6 million for workers’ compensation, including collateral for workers’ compensation bonds; $23.4 million for UMWA retiree health care obligations; $102.2 million for collateral for reclamation surety bonds; and $6.6 million for other miscellaneous obligations. Over the last several years, surety bond costs have increased while the market terms under which surety bonds can be obtained have generally become less favorable to all mining companies. In the event that additional surety bonds become unavailable, we would seek to secure our obligations with letters of credit, cash deposits or other suitable forms of collateral.

Certain Trends and Uncertainties

Our long-term outlook for the coal markets in the United States remains positive. The Energy Information Administration forecasts that coal demand for electrical power generation will increase at an average annual growth rate of 1.4% through 2015. Strong demand for coal and coal-based electricity generation in the U. S. is being driven by the growing economy, expected weather conditions, high prices for and limited supply of alternative fuels for electricity generation, geopolitical risks for global oil and natural gas resources and the abundant steam coal reserves located within the United States.

Approximately 94,000 megawatts of new coal fired electrical generation has been proposed in the United States with the largest percentages of proposed projects located in the Midwest and West. New coal fired generating plants representing capacity of roughly 600 megawatts began operating in 2006 with an additional 1,500 megawatts scheduled to begin operations in 2007. Another 8,500 megawatts are currently under construction and expected to begin operation by the end of 2011. Of the remaining 83,400 megawatts, proposed plants representing approximately 26,000 megawatts are still in the very early stages of development with an additional almost 42,000 megawatts in the proposed stage. But projects representing nearly 15,400 megawatts of this total have moved forward to the stage of obtaining permits, power sales agreements and/or project financing. In addition, there is increasing interest in coal gasification and coal liquefaction projects. The high level of interest in new coal fired electric generating facilities, coal gasification and coal liquefaction is a strong indicator of increasing demand for coal in the United States.

Through the first eleven months of 2006, coal based generation of electricity declined 1.2% from the comparable period of the prior year. During this eleven month period, cooling degree days declined by 3.0% and heating degree days declined by 4.3% compared to the prior year. Lower weather related demand for electricity combined with increased output from nuclear, natural gas and hydro generating plants resulted in decreased demand for coal to generate electricity in 2006.

The ability of the railroads to ship the demanded quantities of coal improved in 2006 in comparison to 2005. Shipments from the southern Powder River Basin increased approximately 10.5% year-over-year, but still fell short of the service levels required to fully satisfy demand for southern Powder River Basin coal, including test burns. The railroads are forecasting to increase deliveries from the southern Powder River Basin by an additional 9% in 2007. The performance of the eastern railroads tends to be more mine specific. In particular, we are reliant on the Norfolk Southern (“NS”) and CSX at our Central Appalachia operations, and on the MGA joint line between the NS and CSX at our Emerald mine in Northern Appalachia.

During 2006, the combination of decreased demand for coal to generate electricity and increased coal production and shipments caused stockpiles at electrical generation plants to grow by over 30% compared to the distressed stockpile levels of late 2005. As a result, coal prices, particularly in the thinly traded spot markets, declined while production and shipping costs continued to increase driven by high prices for commodities and shortages of skilled miners. Since the fourth quarter of 2006, a number of coal producers in Central Appalachia have announced plans to reduce high cost production. Coal producers in Northern Appalachia and the Powder River Basin have announced deferrals of previously announced mine expansion projects. These measures are expected to tighten coal supplies which, in combination with continued economic growth and more normal weather patterns, is expected to improve the balance of coal supply and demand which suggests that long-term fundamentals of the U. S. coal industry remain strong.

Our revenues depend on the price at which we are able to sell our coal. The current pricing environment for U.S. steam coal production is strong in relation to historical pricing levels, but has declined over the last year in response to the factors discussed above. Prices for high quality metallurgical coal, used to manufacture coke for steelmaking, have remained stable in response to increased world-wide demand for steel. As of January 24, 2007, we have committed and priced 98% and 70%, respectively, of the mid-points of our targeted production ranges for 2007 and 2008. In the longer term, decreases in coal prices due to, among other reasons, the supply of domestic and foreign coal, the demand for electricity and the price and availability of alternative fuels for electricity generation could affect our revenues and our ability to generate cash flows. In addition, our results of operations depend on the cost of coal production. We continue to experience increased operating costs for fuel and explosives, steel products, tires, health care, wages, salaries, contract coal haulage services and contract labor. Also, historically low interest rates have had a negative impact on expenses related to our actuarially determined employee-related liabilities.

We may also experience difficult geologic conditions, unforeseen equipment problems and shortages of critical materials such as tires and explosives that may limit our ability to produce at forecasted levels. To the extent upward pressure on costs exceed our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. See the forward looking statements listed at the beginning of this ITEM 2 for additional considerations regarding our outlook.

Critical Accounting Estimates

Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management evaluates its estimates on an on-going basis. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Actual results may differ from the estimates used. Note 3 to the consolidated financial statements provides a description of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity:

Asset Retirement Obligations

Our asset retirement obligations arise from the federal SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines and sealing portals at deep mines. Reclamation activities that are performed outside of the normal mining process are accounted for as asset retirement obligations in accordance with the provisions of SFAS No. 143. We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates and assumptions regarding productivity. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based on historical or third-party costs, both of which are stated at fair value. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. In accordance with the provisions of SFAS No. 143, we determine the fair value of our asset retirement obligations. In order to determine fair value, we must also estimate a discount rate and third-party margin. Each is discussed below:

Discount rate—SFAS No. 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of SFAS No. 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives adjusted for our credit standing.

Third party margin—SFAS No. 143 requires the measurement of an obligation to be based on the amount a third party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin was added to the estimated costs of performing these activities with internal resources. This margin was estimated based upon discussion with contractors that perform reclamation activities. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is settled.

On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revision to cost estimates and productivity assumptions, in each case to reflect current experience.

At December 31, 2006, we had recorded asset retirement obligation liabilities of $125.0 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, we estimate that the aggregate undiscounted cost of final mine closure is approximately $214.3 million at December 31, 2006 payable through 2032.

Employee Benefit Plans

We have two non-contributory defined benefit retirement plans covering certain of our salaried and non-union hourly employees. We also have an unfunded non-qualified Supplemental Executive Retirement Plan (SERP) covering certain of our senior-level salaried employees. Benefits are based on either the employee’s compensation prior to retirement or stated amounts for each year of service with us. Funding of these plans is in accordance with the requirements of the ERISA, which can be deducted for federal income tax purposes. For the twelve months ended December 31, 2006, 2005 and 2004, we contributed $12.2 million, $7.5 million and $18.0 million, respectively, into the plans. We account for our defined benefit retirement plans in accordance with SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS No. 158”) which requires amounts recognized in the financial statements to be determined on an actuarial basis. For the twelve months ended December 31, 2006, we recorded pension expense of $7.2 million. For the twelve months ended December 31, 2005, we recorded pension expense of $5.2 million. For the Five Month Operating Period Ended December 31, 2004, after applying purchase accounting, we recorded pension expense of approximately $2.6 million. For the period from January 1, 2004 through July 29, 2004, we recorded pension expense of $7.1 million.

The calculation of the net periodic benefits costs (pension expense) and benefit obligation (pension liability) associated with our defined benefit pension plans requires the use of a number of assumptions that we deem to be “critical accounting estimates.” These assumptions are used by our independent actuaries to make the underlying calculations. Changes in these assumptions can result in different pension expense and liability amounts, and actual experience can differ from the assumptions.

The expected long-term rate of return on plan assets is an assumption of the rate of return on plan assets reflecting the average rate of earnings expected on the funds invested or to be invested to provide for the benefits included in the projected benefit obligation. We establish the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The pension plan’s investment targets are 60% equity/private equity, 22% fixed income, 8% absolute return funds and 10% real estate mutual funds. Investments are rebalanced on a periodic basis to stay within these targeted guidelines. The long-term rate of return assumption used to determine pension expense was 8.0% for the twelve months ended December 31, 2006, and 8.5% for the twelve months ended December 31, 2005, for the Five Month Operating Period Ended December 31, 2004 and for the period from January 1, 2004 through July 29, 2004. Any difference between the actual experience and the assumed experience is deferred as an unrecognized actuarial gain or loss and amortized into the future.

•

The discount rate represents our estimate of the interest rate at which pension benefits could be effectively settled. Assumed discount rates are used in the measurement of the projected, accumulated and vested benefit obligations and the service and interest cost components of the net periodic pension cost. In estimating that rate, SFAS No. 87, Employers’ Accounting for Pensions, requires rates of return on high quality, fixed income investments. The discount rate used to determine pension expense was 5.60% for the twelve months ended December 31, 2006, 6.00% for the twelve months ended December 31, 2005, 6.25% for the Five Month Operating Period ended December 31, 2004 and for the period from January 1, 2004 through July 29, 2004. The discount rate was increased to 5.90% at the September 30, 2006 measurement date. The differences resulting from actual versus assumed discount rates and returns on plan assets are amortized into pension expense over the remaining average service life of the active plan participants. A one half percentage-point increase in the discount rate would decrease the net periodic pension cost for the twelve months ended December 31, 2006 by approximately $0.2 million and decrease the projected benefit obligation at December 31, 2005 by approximately $11.7 million. The corresponding effects of a one half of one percentage-point decrease in the discount rate would be approximately a $0.8 million increase in the net periodic pension cost and approximately a $12.2 million increase in the projected benefit obligation.

We also currently provide certain postretirement medical and life insurance coverage for eligible employees. These obligations are unfunded. Covered employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. Postretirement medical and life plans for salaried employees and non-represented hourly employees are contributory, with retiree contributions adjusted annually, and contain other cost-sharing features such as deductibles and coinsurance. The postretirement medical plan for members of the UMWA is not contributory. We account for our other postretirement benefits in accordance with SFAS No. 158 which requires amounts recognized in the financial statements to be determined on an actuarial basis. For the twelve months ended December 31, 2006, we recorded postretirement benefit expense of $39.3 million. For the twelve months ended December 31, 2005, we recorded postretirement benefit expense of approximately $37.0 million. In the Successor financial statements for the Five Month Operating Period Ended December 31, 2004, after applying purchase accounting and incorporating Medicare Part D, we recorded postretirement benefit expense of approximately $14.4 million. For the period from January 1, 2004 through July 29, 2004, we recorded postretirement benefit expense of $25.5 million.

Various actuarial assumptions are required to determine the amounts reported as obligations and costs related to the postretirement benefit plan. The differences resulting from actual experience versus actuarial assumptions are deferred as unrecognized actuarial gains or losses and amortized into expense in future periods. These assumptions include the discount rate and the future medical cost trend rate.

The discount rate assumption reflects the rates available on high quality fixed income debt instruments and is calculated in the same manner as discussed above for the defined benefit retirement plans. The discount rate used to calculate the postretirement benefit expense was 5.60% for the twelve months ended December 31, 2006, 6.00% for the twelve months ended December 31, 2005, and 6.25% for the five-month operating period ended December 31, 2004 and for the period from January 1, 2004 through July 29, 2004. The discount rate was increased to 5.90% at the September 30, 2006 measurement date. A one half percentage-point increase in the discount rate would decrease the postretirement benefit expense for the twelve months ended December 31, 2006 by approximately $0.5 million and decrease the accumulated postretirement benefit obligation at December 31, 2005 by approximately $34.8 million. The corresponding effects of a one-half of one percentage-point decrease in the discount rate would be approximately a $3.6 million increase in the postretirement benefit expense and approximately a $37.2 million increase in the accumulated postretirement benefit obligation.

The future health care cost trend rate represents the rate at which health care costs are expected to increase over the life of the plan. The health care cost trend rate assumptions are determined primarily based upon our historical rate of change in retiree health care costs. We have implemented many effective retiree health care cost containment measures that have resulted in actual increases in our retiree health care costs to fall far below the double-digit annual increases experienced by many companies and cited in most external studies. The postretirement expense for the twelve months ended December 31, 2006 and 2005 was based on an assumed health care inflationary rate of 9.00% in 2006 and 2005, respectively, decreasing to 5.00% in 2010, which represents the ultimate health care cost trend rate for the remainder of the plan life. The postretirement expense for the Five Month Operating Period Ended December 31, 2004 was based on a health care inflation rate of 8.00% in 2004 decreasing to 5.00% in 2010. The postretirement expense for the period from January 1, 2004 through July 29, 2004 was based on an assumed health care inflation rate of 5.75% in 2004 decreasing to 4.75% in 2008. A one-percentage point increase in the 5.00% assumed ultimate health care cost trend rate would increase the service and interest cost components of the postretirement benefit expense for the twelve months ended December 31, 2006 by $6.6 million and increase the accumulated postretirement benefit obligation at December 31, 2006 by $79.8 million. A one-percentage point decrease in the 5.00% assumed ultimate health care cost trend rate would decrease the service and interest cost components of the postretirement benefit expense for the twelve months ended December 31, 2006 by $5.3 million and decrease the accumulated postretirement benefit obligation at December 31, 2006 by $65.9 million.

Income Taxes

We account for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes (“SFAS No. 109”), which requires the recognition of deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, we take into account various factors including the expected level of future taxable income and available tax planning strategies. At December 31, 2006 we had a full valuation allowance for deferred tax assets arising from Alternative Minimum Tax (“AMT”) credits and a valuation allowance to reduce the value of our net deferred tax asset to an AMT tax rate. The Company believes that it will continue to be an AMT tax payer for the foreseeable future. If future taxable income is different than expected or if expected tax planning strategies are not available as anticipated, we may record a change to the valuation allowance through income tax expense in the period such determination is made.

Mineral Rights

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves. Many of these uncertainties are beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff and independent third party consultants. Some of the factors and assumptions that impact economically recoverable reserve estimates include:

geological and mining conditions;

historical production from similar areas with similar conditions;

the assumed effects of regulations and taxes by governmental agencies;

assumptions governing future prices;

competing property rights such as surface rights, oil and gas rights, deeper or shallower coal rights and easements;

ability to permit specific reserves for a particular type of mining;

future operating, development and reclamation costs; and

mining technology improvements.

Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows may vary substantially. Actual production, revenue and expenditures with respect to reserves may materially vary from estimates.

Recent Accounting Pronouncements

New Pronouncements

In February 2007, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 159, The Fair Value Option for Financial Assets and Liabilities Including an amendment of FASB Statement No. 115 (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The Company expects to adopt SFAS No. 159 on January 1, 2008 and has not yet determined the impact on the consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company expects to adopt SFAS No. 157 on January 1, 2008. The Company has not yet determined the impact of SFAS No. 157 on the consolidated financial statements.

In September 2006, the FASB issued SFAS No. 158, which requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. SFAS No. 158 requires the Company to initially recognize the funded status of a defined benefit postretirement plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006. Additionally, for fiscal years ending after December 15, 2008, the Company is required to measure plan assets and benefit obligations as of the date of the Company’s fiscal year-end statement of financial position rather than at an interim period. On December 31, 2006, the Company adopted the recognition and disclosure provisions of SFAS No. 158. The effect of adopting SFAS No. 158 on the Company’s financial condition at December 31, 2006 has been included in the accompanying consolidated financial statements. SFAS No. 158 did not have an effect on the Company’s consolidated financial condition at December 31, 2005 or 2004. See Note 14 in ITEM 8 for further discussion of the effect of adopting SFAS No. 158 on the Company’s consolidated financial statements.

In June 2006, the FASB issued FASB Interpretation No. (“FIN”) 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s consolidated financial statements in accordance with SFAS No. 109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires an entity to recognize the financial statement impact of a tax position when it is more-likely-than-not that the position will be sustained upon examination. If the tax position meets the more-likely-than-not recognition threshold, the tax effect is recognized at the largest amount of the benefit that is greater than fifty percent likely of being realized upon ultimate settlement. FIN 48 requires that a liability created for unrecognized tax benefits shall be presented as a liability and not combined with deferred tax liabilities or assets. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company expects to adopt FIN 48 on January 1, 2007. The Company is currently evaluating the impact of its adoption of FIN 48 and has not yet determined the effect on its earnings or financial position.

The Company adopted EITF Issue 04-6 on January 1, 2006. EITF Issue 04-6 addresses the accounting for stripping costs incurred during the production phase of a mine, concluding that these costs are considered variable production costs and under a full absorption costing system are considered a component of inventory to be recognized in cost of coal sales in the same period as the revenue from the sale of the inventory. Capitalization of post-production stripping costs is appropriate only to the extent inventory exists at the end of a reporting period. The guidance requires application through recognition of a cumulative effect adjustment to opening retained earnings in the period of adoption, with no charge to current earnings for prior periods. Accordingly, prior period results have not been restated. At December 31, 2005, stripping costs associated with coal that had not been extracted was $60.4 million which were classified on the Consolidated Balance Sheets as a component of work-in-process inventory referred to as deferred overburden. The effect on the consolidated financial statements upon adoption of EITF Issue 04-6 resulted in a cumulative effect adjustment which reduced opening retained earnings, as of January 1, 2006, by $39.3 million net of tax of $21.1 million, thereby removing the $60.4 million current asset previously classified on the Consolidated Balance Sheets as a component of work-in-process (deferred overburden) inventory.

Prior to January 1, 2006, the Company accounted for its stock-based compensation plans under the recognition and measurement provisions of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”), and related interpretations, as permitted by SFAS No. 123, Accounting for Stock-Based Compensation, (“SFAS No. 123”). Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS No. 123(R)”), using the modified prospective transition method. Under the modified prospective transition method, compensation cost recognized in 2006 includes: (a) compensation cost for all stock-based awards granted prior to but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123; and (b) compensation cost for all stock-based awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R). For all grants, the amount of compensation expense to be recognized is adjusted for an estimated forfeiture rate which is based on historical data. Results for prior periods have not been restated. There were no modifications made to outstanding options prior to the adoption of the standard. There were no changes made by the Company to the terms, quantity or type of instruments used for share-based compensation as a result of the adoption of the new standard.

All stock based awards are made pursuant to the 2004 Stock Incentive Plan (the “Plan”) of our Public Parent as adopted on July 30, 2004 by the Board of Directors of the Public Parent. The Plan permits the Company to grant its key employees, directors and consultant’s non-qualified stock options (“options”), stock appreciation rights, restricted stock or other stock-based awards of our Public Parent. The shares under the Plan may be issued at an exercise price of no less than 100% of the fair market value of the Company’s common stock on the date of grant. The Plan is currently authorized for the issuance of awards for up to 5,978,483 shares of common stock. At December 31, 2006, 2,115,741 shares of common stock of our Public Parent were available for grant under the Plan.

The Company has two types of stock-based awards: restricted stock units and non-qualified stock options (“options”). Total compensation related to the stock-based awards recognized in Selling, general and administrative expense for the twelve months ended December 31, 2006 was $2.8 million, consisting of $1.4 million and $1.4 million for restricted stock units and options, respectively. For the twelve months ended December 31, 2005, compensation expense of approximately $1.5 million was recognized as a component of Selling, general and administrative expense for restricted stock units. No expense related to options was charged against income in the prior periods as the Company elected to apply the provisions of APB No. 25 to those periods as permitted by SFAS No. 123.

Pursuant to the adoption of this new accounting standard, the table below provides a summary of the effect of applying the provisions of SFAS No. 123(R) on the Company’s consolidated financial statements related to stock-based compensation for the twelve months ended December 31, 2006.


	Twelve Months Ended December 31, 2006
	(Unaudited)
Income before income tax expense	$	(1,367	)
Income tax expense		149

Net income	$	(1,218	)

SFAS No. 123(R) also requires that the excess tax benefit from the exercise of options be reflected in the Statements of Consolidated Cash Flows as a cash inflow from financing activities. Prior to the adoption of SFAS No. 123(R), this tax benefit would have been reflected as a cash inflow from operations. The excess tax benefit from the exercise of options was $9.5 million and $0.3 million during the twelve months ended December 31, 2006 and 2005, respectively.

SFAS No. 123(R) also requires that forfeitures be estimated and included in the calculation of compensation cost. Upon adoption of SFAS No. 123(R), the Company quantified the effect related to the estimation of forfeitures for stock-based awards that were not vested at December 31, 2005. The Company’s estimate was based on previous forfeiture activity combined with the Company’s reasonable expectations of forfeitures. The gross adjustment for forfeitures was not material to the consolidated financial statements.

See Note 16 in ITEM 8 for additional disclosures relating to the compensation costs related to nonvested awards not yet recognized and the expected period of recognition and valuation methodologies used in determining the fair value of options.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Commodity Price Risk

We manage our commodity price risk for coal sales through the use of long-term coal supply agreements rather than through the use of derivative instruments. As of January 24, 2007, we had sales commitments for approximately 98% of our planned 2007 production. As of January 24, 2007, uncommitted and unpriced tonnage was 30%, 52% and 81% of planned production in 2008, 2009 and 2010, respectively. Eastern coals account for the majority of uncommitted tonnage as 41%, 73% and 93% of the Company’s planned eastern production remains uncommitted and unpriced in 2008, 2009 and 2010, respectively.

Some of the products used in our mining activities, such as diesel fuel, explosives, large equipment tires, steel products and electricity, are subject to price volatility. Through our suppliers, we utilize forward purchase contracts to manage the exposure related to this volatility. As of December 31, 2006, the Company has entered into forward purchase commitments for approximately 85% of the diesel fuel that it expects to consume during calendar year 2007 at prices ranging from $2.02 per gallon for our Powder River Basin mines to $2.10 per gallon for our Central Appalachian mines. The Company has designated these contracts as normal purchase normal sale contracts, and, therefore, they are not deemed to be derivative financial instruments for financial reporting purposes. During the twelve months ended December 31, 2006 and 2005, the cost of diesel fuel represented approximately 4% and 2.8%, respectively, of the Company’s consolidated cost of coal sales.

Credit Risk

Our credit risk is primarily with electric power generators and, to a lesser extent, steel producers. Most electric power generators to whom we sell have investment grade credit ratings. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor outstanding accounts receivable against established credit limits. When appropriate (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay.

Interest Rate Risk

Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. We have exposure to changes in interest rates through our bank term loan and our revolving credit facility. To achieve risk mitigation objectives, we have in the past managed our interest rate exposure through the use of interest rate swaps.

In connection with the July 7, 2006 closing of the amended and restated Senior Secured Credit Facility, the Company terminated existing swap agreements. On July 11, 2006, the Company monetized a $2.4 million derivative asset included in other noncurrent assets in the Company’s consolidated financial statements at June 30, 2006 and recognized a resulting $0.1 million mark-to-market loss on the swaps. The $1.8 million unrealized gain from the change in the market value of the interest rate swaps recorded in accumulated other comprehensive income (loss) will be recognized into income on a prorated basis over the remaining term of the original interest rate swap agreement through September 28, 2007, in accordance with Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, and related amendments.

As we continue to monitor the interest rate environment in concert with our risk mitigation objectives, consideration is being given to future interest rate risk reduction strategies.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

FOUNDATION COAL CORPORATION AND SUBSIDIARIES

(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF FOUNDATION COAL HOLDINGS, INC.)

CONSOLIDATED FINANCIAL STATEMENTS

INDEX


		Page
Report of Independent Registered Public Accounting Firm—Foundation Coal Corporation (Successor)		73
Report of Independent Registered Public Accounting Firm—RAG American Coal Holding, Inc. (Predecessor)		74
Consolidated Balance Sheets		75
Statements of Consolidated Operations and Comprehensive Income (Loss)		76
Statements of Consolidated Stockholder Equity		77
Statements of Consolidated Cash Flows		78
Notes to Consolidated Financial Statements		80

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholder

Foundation Coal Corporation (an indirect wholly owned subsidiary of Foundation Coal Holdings, Inc., as described in Note 1)

We have audited the accompanying consolidated balance sheets of Foundation Coal Corporation and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations and comprehensive income (loss), stockholder equity, and cash flows for each of the two years in the period ended December 31, 2006 and for the period from April 23, 2004 (date of incorporation) through December 31, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15 (a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Foundation Coal Corporation and subsidiaries at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2006 and for the period from April 23, 2004 (date of incorporation) through December 31, 2004, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 3, on January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004), Share-Based Payment, and the provisions of EITF Issue No. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry. Also, as discussed in Note 3, on December 31, 2006, the Company adopted the provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.

/s/ Ernst & Young LLP

March 16, 2007

Baltimore, Maryland

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholder

RAG American Coal Holding, Inc.

We have audited the accompanying consolidated statement of operations and comprehensive income, stockholder’s equity and cash flows of RAG American Coal Holding, Inc. and subsidiaries (a wholly owned subsidiary of RAG Coal International AG) for the period from January 1, 2004 through July 29, 2004 (date of sale). Our audit also included the financial statement schedule listed in the Index at Item 15 (a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of RAG American Coal Holding, Inc. and subsidiaries for the period from January 1, 2004 through July 29, 2004 (date of sale) in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

March 29, 2005

Baltimore, Maryland

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Consolidated Balance Sheets

(Dollars in thousands, except share data)


	December 31,
	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	33,711		$	22,424
Trade accounts receivable		119,603			110,125
Inventories, net		36,771			96,896
Deferred income taxes		15,525			4,933
Prepaid expenses		30,790			22,447
Other current assets		4,239			2,885

Total current assets		240,639			259,710
Owned surface lands		30,388			27,510
Plant, equipment and mine development costs, net		626,234			567,062
Owned and leased mineral rights, net		1,003,804			1,071,596
Coal supply agreements, net		31,343			53,050
Other noncurrent assets		17,163			29,183

Total assets	$	1,949,571		$	2,008,111

LIABILITIES
Current liabilities:
Trade accounts payable	$	41,584		$	35,384
Accrued expenses and other current liabilities		162,014			181,883

Total current liabilities		203,598			217,267
Long-term debt		626,625			635,000
Deferred income taxes		8,547			67,629
Coal supply agreements, net		24,223			59,013
Postretirement benefits		536,628			464,418
Other noncurrent liabilities		252,420			225,413

Total liabilities		1,652,041			1,668,740

Commitments and contingencies (Note 28)

STOCKHOLDER EQUITY
Common stock, $0.01 par value; 100 shares authorized, issued and outstanding at December 31, 2006 and 2005		—			—
Additional paid-in capital		252,472			235,011
Retained earnings		78,470			105,137
Accumulated other comprehensive loss		(33,412	)		(777	)

Total stockholder equity		297,530			339,371

Total liabilities and stockholder equity	$	1,949,571		$	2,008,111

The accompanying notes are an integral part of these consolidated financial statements.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Statements of Consolidated Operations and Comprehensive Income (Loss)

(Dollars in thousands)


	Successor									Predecessor
	Twelve Months Ended December 31, 2006			Twelve Months Ended December 31, 2005			For the Period From April 23, 2004 (date of incorporation) Through December 31, 2004			Seven Months Ended July 29, 2004
Revenues:
Coal sales	$	1,440,162		$	1,292,411		$	436,035		$	544,882
Other revenue		30,159			24,518			8,561			6,153

Total revenues		1,470,321			1,316,929			444,596			551,035
Costs and expenses:
Cost of coal sales (excludes depreciation, depletion and amortization)		1,110,922			936,201			345,791			484,457
Selling, general and administrative expense (excludes depreciation, depletion and amortization)		50,721			48,437			24,596			27,375
Accretion on asset retirement obligations		8,510			8,507			3,300			4,020
Depreciation, depletion and amortization		183,201			211,186			84,843			61,236
Amortization of coal supply agreements		(13,122	)		(84,903	)		(67,238	)		8,837
Write-down of long-lived assets		30,782			1,633			—			—

Income (loss) from operations		99,307			195,868			53,304			(34,890	)
Other income (expense):
Interest expense		(64,525	)		(59,495	)		(26,677	)		(18,010	)
Loss on termination of hedge accounting for interest rate swaps		—			—			—			(48,854	)
Contract settlement		—			—			—			(26,015	)
Loss on early debt extinguishment		—			—			—			(21,724	)
Mark-to-market (loss) gain on interest rate swaps		(112	)		—			530			5,804
Interest income		3,010			1,161			507			1,274

Income (loss) before income tax (expense) benefit		37,680			137,534			27,664			(142,415	)
Income tax (expense) benefit		(4,106	)		(46,461	)		(13,600	)		51,824

Income (loss) from continuing operations		33,574			91,073			14,064			(90,591	)
Income from discontinued operations, net of income tax expense of $546 for the seven months ended July 29, 2004		—			—			—			2,315
Gain on disposal of discontinued operations, net of income tax expense of $4,913 for the seven months ended July 29, 2004		—			—			—			20,750

Net income (loss)		33,574			91,073			14,064			(67,526	)
Components of comprehensive income (loss):
Change in minimum pension liability, net of income tax (expense) benefit of $(960) in 2006, $933 in 2005 and $192 for the period from April 23, 2004 through December 31, 2004		1,500			(1,415	)		(326	)		—
Unrealized gain on interest rate swaps, net of income tax expense of $90 in 2006, $648 in 2005 and $16,890 for the seven months ended July 29, 2004		139			964			—			28,820
Other		11			—			—			—

Comprehensive income (loss)	$	35,224		$	90,622		$	13,738		$	(38,706	)

The accompanying notes are an integral part of these consolidated financial statements.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Statements of Consolidated Stockholder Equity

(Dollars in thousands, except unit and share data)


	Common Stock			Additional Paid-In Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Loss			Total Stockholder Equity
	Shares	Amount
Predecessor
Balance at December 31, 2003	137,143	$	137	$	518,218		$	62,063		$	(57,267	)	$	523,151
Net loss for the seven months ended July 29, 2004	—		—		—			(67,526	)		—			(67,526	)
Unrealized gain on interest rate swaps, net of tax	—		—		—			—			28,820			28,820

Balance at July 29, 2004, (date of sale)	137,143	$	137	$	518,218		$	(5,463	)	$	(28,447	)	$	484,445

Successor
Balance at April 23, 2004 (date of incorporation)	—	$	—	$	—		$	—		$	—		$	—
Issuance of initial common stock	100		—		—			—			—			—
Cash contributions from parent	—		—		241,993			—			—			241,993
Change in minimum pension liability, net of tax	—		—		—			—			(326	)		(326	)
Net income	—		—		—			14,064			—			14,064

Balance at December 31, 2004	100	$	—	$	241,993		$	14,064		$	(326	)	$	255,731
Return of capital to parent	—		—		(6,982	)		—			—			(6,982	)
Unrealized gain on interest rate swaps, net of tax	—		—		—			—			964			964
Change in minimum pension liability, net of tax	—		—		—			—			(1,415	)		(1,415	)
Net income	—		—		—			91,073			—			91,073

Balance at December 31, 2005	100	$	—	$	235,011		$	105,137		$	(777	)	$	339,371
Cash dividends to parent	—		—		—			(20,977	)		—			(20,977	)
Capital contributions from parent	—		—		17,461			—			—			17,461
Unrealized gain on interest rate swaps, net of tax	—		—		—			—			139			139
Termination of interest rate swaps	—		—		—			—			11			11
Adjustment to initially apply EITF 04-6, net of tax at January 1, 2006	—		—		—			(39,264	)		—			(39,264	)
Change in minimum pension liability, net of tax	—		—		—			—			1,500			1,500
Adjustment to initially apply SFAS No. 158, net of tax, to defined benefit pension and postretirement plans as of December 31, 2006	—		—		—			—			(34,285	)		(34,285	)
Net income	—		—		—			33,574			—			33,574

Balance at December 31, 2006	100	$	—	$	252,472		$	78,470		$	(33,412	)	$	297,530

The accompanying notes are an integral part of these consolidated financial statements.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Statements of Consolidated Cash Flows

(Dollars in thousands)


	Successor									Predecessor
	Twelve Months Ended December 31, 2006			Twelve Months Ended December 31, 2005			For the Period From April 23, 2004 (date of incorporation) Through December 31, 2004			Seven Months Ended July 29, 2004
Operating activities:
Net income (loss)	$	33,574		$	91,073		$	14,064		$	(67,526	)
Income and gain on disposition from discontinued operations		—			—			—			(23,065	)

Income (loss) from continuing operations		33,574			91,073			14,064			(90,591	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Accretion on asset retirement obligations		8,510			8,507			3,300			4,020
Depreciation, depletion and amortization		170,079			126,283			17,605			70,073
Amortization of deferred financing costs		11,653			4,807			4,408			—
(Gain) loss on sale of assets		(876	)		(666	)		405			(960	)
Non-cash stock compensation		2,765			1,509			—			—
Non-cash mark-to-market adjustment for interest rate swaps		112			—			(530	)		(5,804	)
Non-cash expense from termination of hedge accounting for interest rate swap		—			—			—			48,854
Loss on early extinguishment of debt		—			—			—			21,724
Write-down of long-lived assets		30,782			1,633			—			—
Deferred income taxes		(25,382	)		26,745			10,004			(46,399	)
Asset retirement obligations		(2,567	)		(1,962	)		(8,388	)		(5,709	)
Non-cash interest expense and other		1,275			—			—			—
Changes in operating assets and liabilities:
Trade accounts receivable		(9,478	)		(43,641	)		7,485			(9,341	)
Inventories, net		(1,942	)		(57,178	)		(17,098	)		(6,113	)
Prepaid expenses and other current assets		(11,886	)		(6,002	)		(3,055	)		(1,679	)
Other noncurrent assets		1,219			4,181			(2,779	)		2,445
Trade accounts payable		6,200			5,047			1,495			5,572
Accrued expenses and other current liabilities		(21,829	)		21,054			24,363			(25,049	)
Noncurrent liabilities		33,445			(3,571	)		10,414			30,913

Net cash provided by (used in) continuing operations		225,654			177,819			61,693			(8,044	)
Net cash provided by discontinued operations		—			—			—			6,973

Net cash provided by (used in) operating activities		225,654			177,819			61,693			(1,071	)

The accompanying notes are an integral part of these consolidated financial statements.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Statements of Consolidated Cash Flows—(Continued)

(Dollars in thousands)


	Successor									Predecessor
	Twelve Months Ended December 31, 2006			Twelve Months Ended December 31, 2005			For the Period From April 23, 2004 (date of incorporation) Through December 31, 2004			Seven Months Ended July 29, 2004
Investing activities:
Acquisition of RAG American Coal Holding, Inc., net of cash acquired		—			—			(904,910	)		—
Purchases of property, plant, equipment and mine development costs		(187,217	)		(140,216	)		(33,573	)		(52,695	)
Purchases of mining assets		(14,661	)		—			—			—
Proceeds from disposition of property, plant and equipment		2,010			9,778			3,551			2,049

Net cash used in continuing operations		(199,868	)		(130,438	)		(934,932	)		(50,646	)
Net cash provided by discontinued operations		—			—			—			184,954

Net cash (used in) provided by investing activities		(199,868	)		(130,438	)		(934,932	)		134,308

Financing activities:
Capital contribution from Public Parent		7,565			—			241,993			—
Proceeds from Public Parent advance		—			—			—			306,057
Payment of cash dividends to Public Parent		(20,977	)		—			—			—
Excess tax benefit from stock-based awards		9,486			—			—			—
Proceeds from revolving credit facility		—			76,000			60,000			—
Repayment of revolving credit facility		—			(76,000	)		(60,000	)		—
Proceeds from issuance of long-term debt		—			—			770,000			—
Payment of deferred financing costs		(4,457	)		—			(28,573	)		—
Repayment of long-term debt		(8,375	)		(50,000	)		(85,138	)		(614,644	)
Payment of expenses resulting from early debt extinguishment		—			—			—			(21,724	)
Repayment of capital lease obligations		—			—			—			(1,679	)
Interest rate swap termination		2,259			—			—			(48,854	)
Net increase in cash pledged on debt		—			—			—			20,000
Net decrease in cash on deposit with Predecessor		—			—			—			233,023

Net cash (used in) provided by financing activities		(14,499	)		(50,000	)		898,282			(127,821	)

Net increase (decrease) in cash and cash equivalents		11,287			(2,619	)		25,043			5,416
Cash and cash equivalents at beginning of period		22,424			25,043			—			7,649

Cash and cash equivalents at end of period	$	33,711		$	22,424		$	25,043		$	13,065

Supplemental cash flow information:
Cash paid for interest	$	48,611		$	48,015		$	7,695		$	29,615
Cash paid for income taxes	$	17,283		$	33,167		$	157		$	220

The accompanying notes are an integral part of these consolidated financial statements.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Notes to Consolidated Financial Statements

(Dollars in thousands, except per share data)

Note 1. Description of Business and Basis of Presentation

On April 23, 2004, Foundation Coal Corporation (“FCC” or the “Company”) was formed as a wholly owned subsidiary of Foundation Coal Holdings, LLC (“LLC”). The Company issued 100 shares of common stock with a par value of $0.01 to LLC. LLC was formed on February 9, 2004 as a Delaware limited liability company, which, on July 30, 2004, contributed its shares of FCC and merged into Foundation Coal Holdings, Inc. (“FCL” or the “Public Parent”). FCL and its indirect subsidiary, FCC, were formed to acquire the North American coal mining assets of RAG American Coal Holding, Inc., which acquisition closed on July 30, 2004 (“the Acquisition”). FCL through its operating subsidiaries engages in the extraction, cleaning and selling of coal to electric utilities, steel companies, coal brokers, and industrial users primarily in the United States.

RAG American Coal Holding, Inc., a wholly owned subsidiary of RAG Coal International AG (“RAG”), which is an indirect owned subsidiary of RAG Aktiengesellschaft (“RAG AG”), was incorporated in Delaware on October 31, 1974. RAG American Coal Holding, Inc. had two primary operating units: Riverton Coal Production, Inc. and subsidiaries (“RCP”) and RAG American Coal Company and subsidiaries (“RACC”).

On February 29, 2004, RACC signed a definitive Stock Purchase Agreement to sell RAG Coal AG’s Colorado operations which included Twentymile Coal Company, RAG Empire Corporation, RAG Shoshone Coal Corporation and Colorado Yampa Coal Company (collectively referred to as the RAG Colorado Business Unit) to a subsidiary of Peabody Energy Corporation. This transaction closed on April 15, 2004. Accordingly, all references to Foundation Coal Corporation, exclude the RAG Colorado Business Unit which is accounted for and presented in the accompanying consolidated financial statements as discontinued operations. See Note 29.

The consolidated financial statements as of and for the periods ended December 31, 2006, 2005 and 2004 reflect the Acquisition under the purchase method of accounting, in accordance with the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 141, Business Combinations (“SFAS No. 141”), discussed in greater detail in Note 4.

The following provides a description of the basis of presentation during all periods presented:

“Successor”—Represents the consolidated financial position of the Company and consolidated subsidiaries as of December 31, 2006 and 2005 and the consolidated results of operations and cash flows for the twelve months ended December 31, 2006 and 2005 and for the period from April 23, 2004 (date of incorporation) through December 31, 2004. The Company had no significant activities until the Acquisition on July 30, 2004. Therefore, the results of operations and cash flows for the period from April 23, 2004 (date of incorporation) through December 31, 2004 reflect only the activity for the five month operating period ended December 31, 2004. The consolidated results of operations and cash flows for the period from April 23, 2004 (date of incorporation) through December 31, 2004 reflect preliminary purchase accounting for the Acquisition. The financial position and results of operations and cash flows as of and for the years ended December 31, 2006 and 2005 reflect the final purchase accounting for the Acquisition.

“Predecessor”—Represents the consolidated results of operations and cash flows of RAG American Coal Holding, Inc. for the periods in 2004 prior to the Acquisition. This presentation reflects the historical basis of accounting.

Unless otherwise indicated, the “Company” as used throughout the remainder of these Notes to the consolidated financial statements refers to both the Successor and the Predecessor.

At December 31, 2006, union representation accounted for approximately 39% of the Company’s employees who produced approximately 21% of our coal sales volume during the year. Labor contracts for the Pennsylvania mines, Emerald and Cumberland, with the United Mine Workers of America (“UMWA”) were signed in 2002 and expire on April 1, 2007. The UMWA contract for the Wabash mine was signed in March 2003 and expires on April 1, 2007.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Notes to Consolidated Financial Statements (Continued)

(Dollars in thousands, except per share data)

Note 2. Change in Ownership

Formation

LLC was formed on February 9, 2004 by a group of investors for the purpose of acquiring the United States coal properties owned by RAG. The original investors in LLC were First Reserve Fund IX, L.P. and Blackstone Capital Partners IV LP. Each member was granted 50 units in exchange for nominal consideration in the form of management and capital formation advisory services. The purpose of the formation of LLC was to pursue the acquisition of the North American coal mining assets of RAG.

On April 23, 2004, the Company was formed as a wholly owned subsidiary of LLC. The Company issued 100 shares of common stock with a par value of $0.01 to LLC.

On May 24, 2004, the Company signed a Stock Purchase Agreement dated May 24, 2004 (the “Stock Purchase Agreement”) whereby the Company acquired all of the direct and indirect subsidiaries engaged in coal mining in North America then owned by RAG.

Through July 29, 2004, neither LLC, the Company nor FCL, (collectively the “Successor”) had any additional significant activities.

Recapitalization

On July 30, 2004, LLC amended and restated its Limited Liability Operating Agreement. As part of the Amended and Restated Limited Liability Operating Agreement the following members were granted membership interests in exchange for cash capital contributions as follows:


Members	Investment		Percentage of Member Units
Blackstone FCH Capital Partners IV L.P.	$	78,214	39.9	%
Blackstone Family Investment Partnership IV		4,117	2.1	%
First Reserve Fund IX, L.P.		82,331	42.0	%
AMCI Acquisition, LLC		29,058	14.8	%
Management Members		2,280	1.2	%

	$	196,000	100.0	%

The management members were senior managers of RAG American Coal Holding, Inc., the operating company of RAG’s North American Operations. These senior managers continued as senior managers of FCL.

FCL and FC 2 Corp. (“FC 2”) were incorporated in Delaware on July 19, 2004. On July 30, 2004, LLC contributed the shares of its subsidiary FCC to FCL in exchange for 100 shares of common stock of FCL. FCL then contributed the shares of FCC into FC 2 in exchange for 100 shares of common stock of FC 2. Upon the completion of these exchange transactions, FCL, FC 2 and FCC were direct or indirect wholly owned subsidiaries of LLC.

On July 30, 2004, FCC completed the acquisition of the direct and indirect subsidiaries engaged in coal mining in North America then owned by RAG.

On August 10, 2004, FCL effected a 196,000 for one stock split of common stock.

On August 17, 2004, LLC was merged with and into FCL. As a result of the merger, the members of LLC received one share of FCL’s common stock for each unit of membership interest in LLC, and FCL became the successor in interest to LLC.

Acquisition of RAG

On July 30, 2004, FCL, through its indirect wholly owned subsidiary, FCC, and pursuant to the terms of the Stock Purchase Agreement acquired 100% of the outstanding common shares of all of the direct and indirect subsidiaries of RAG engaged in coal mining in North America for a purchase price of approximately $986,918 including associated transaction costs of approximately $19,618. See Note 4.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Notes to Consolidated Financial Statements (Continued)

(Dollars in thousands, except per share data)

Note 3. Summary of Significant Accounting Policies

Unless otherwise indicated, the Successor and the Predecessor follow the same significant accounting policies.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates

The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of the Company’s consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of management estimates and assumptions relate to coal reserves that are the basis for future cash flow estimates and units-of-production depreciation, depletion and amortization calculations; environmental and reclamation obligations; asset impairments; postemployment, postretirement and other employee benefit liabilities; valuation allowances for deferred income taxes; reserves for contingencies and litigation and the fair value and accounting treatment of certain financial instruments. Management bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may differ significantly from these estimates. In addition, different assumptions or conditions could reasonably be expected to yield different results.

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances and highly liquid investments with an original maturity of three months or less. Because of the short maturity of these investments, the carrying amounts approximate their fair value. Cash and cash equivalents are invested in high-quality commercial paper and money market funds.

Inventories and Stripping Costs

Coal inventories acquired in the Acquisition are stated at their fair value at the Acquisition date. As of December 31, 2004, all coal inventory acquired in the Acquisition had been sold, therefore the excess of the fair value of coal inventories over the Predecessor’s historical cost of $3,753 was charged to Cost of coal sales in the period ended December 31, 2004. Coal inventories produced subsequent to the Acquisition are stated at the lower of cost or net realizable value. Net realizable value represents the estimated future sales price of the product based on prevailing and long-term prices, less the estimated preparation and selling costs. Coal inventories are valued at the lower of average cost or market.

Material and supplies inventories are valued at average cost, less an allowance for obsolete and surplus items.

The Company adopted Emerging Issues Task Force (“EITF”) Issue No. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry (“EITF Issue 0-6”) on January 1, 2006. EITF Issue 04-6 addresses the accounting for stripping costs incurred during the production phase of a mine, concluding that these costs are considered variable production costs and under a full absorption costing system are considered a component of inventory to be recognized in cost of coal sales in the same period as the revenue from the sale of the inventory. Capitalization of post-production stripping costs is appropriate only to the extent inventory exists at the end of a reporting period. The guidance requires application through recognition of a cumulative effect adjustment to opening retained earnings in the period of adoption, with no charge to current earnings for prior periods. Accordingly, prior period results have not been restated. At December 31, 2005, stripping costs associated with coal that had not been extracted was $60,406 which were classified on the Consolidated Balance Sheets as a component of work-in-process inventory referred to as deferred overburden. The effect on the consolidated financial statements upon adoption of EITF Issue 04-6 resulted in a cumulative effect adjustment which reduced opening retained earnings, as of January 1, 2006, by $39,264, net of tax of $21,142, thereby removing the $60,406 current asset previously classified on the Consolidated Balance Sheets as a component of work-in-process (deferred overburden) inventory.

Prior to the adoption of EITF Issue 04-6 on January 1, 2006, the cost of removing overburden subsequent to the Acquisition in advance of coal extraction at the Wyoming surface mines was deferred and classified as work-in-process inventory. The overburden removal process is generally 12 months or less in advance of coal extraction. In instances where the overburden removal process was greater than 12 months, the Company classified the deferred costs as a non-current asset.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Notes to Consolidated Financial Statements (Continued)

(Dollars in thousands, except per share data)

Prepaid Expenses

Prepaid expenses consist primarily of deferred longwall move costs, advance mining royalties, prepaid taxes and prepaid insurance premiums. The Company defers the direct costs, including labor and supplies, associated with moving longwall equipment and the related equipment refurbishment costs in Prepaid expenses. These deferred costs are amortized on a units-of-production basis over the life of the subsequent panel of coal mined by the longwall equipment. Deferred costs that are anticipated to be amortized into production within one year are included in current assets. All other deferred costs are included in Other noncurrent assets.

Plant, Equipment and Mine Development Costs

Costs to obtain coal lands and leased mineral rights are capitalized and amortized to operations as depletion expense on the units-of-production method utilizing only proven and probable reserves in the depletion base. Depletion expense is included in depreciation, depletion and amortization on the accompanying Statements of Consolidated Operations and Comprehensive Income (Loss). Costs of developing new mines or significantly expanding the capacity of or extending the lives of existing mines are capitalized and amortized using the units-of-production method over proven and probable reserves directly benefiting from the capital expenditure. The Predecessor principally amortized mine development costs using the straight-line method over the period during which each capitalized expenditure benefited production. The Company and its Predecessor believe that the straight-line method approximates the units-of-production method. Mobile mining equipment and other fixed assets are stated at cost and depreciated on a straight-line basis over the estimated useful lives ranging from 1 to 20 years or on a units-of-production basis. Leasehold improvements are amortized over their estimated useful lives or the term of the lease, whichever is shorter. Major repairs and betterments that significantly extend original useful lives or improve productivity are capitalized and depreciated over the period benefited. Maintenance and repairs are generally expensed as incurred.

The Company capitalizes certain costs incurred in the development of internal-use software, including external direct material and service costs, and employee payroll and payroll-related costs in accordance with the American Institute of Certified Public Accountants’ Statement of Position 98-1, “Accounting for the Costs of Computer Software Developed for or Obtained for Internal Use.” All capitalized internal-use software costs are amortized using the straight-line method over the estimated useful life not to exceed 7 years.

Asset Retirement Obligations

SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”), addresses a uniform methodology for accounting for estimated reclamation and abandonment costs. The Company’s asset retirement obligations consist principally of costs to reclaim acreage disturbed at surface operations and estimated costs to reclaim support acreage and perform other related functions at underground mines. SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which the legal obligation associated with the retirement of the tangible long-lived asset is incurred. When the liability is initially recorded, the offset is capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. To settle the liability, the obligation is paid, and to the extent there is a difference between the liability and the amount of cash paid, a gain or loss upon settlement is incurred. The Company estimates its asset retirement obligation liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of future cash flows required for a third party to perform the necessary reclamation work. The Company annually reviews its estimated future cash flows for its asset retirement obligations.

Coal Supply Agreements

Coal supply agreements represent the fair value assigned at the Acquisition date for acquired sales contracts. These sales contracts are valued at the present value of the difference between the expected contract revenues from the acquired contract, net of royalties and taxes imposed on sales revenues, and the net contract revenues derived from applying market prices at the Acquisition date for new contracts of similar duration and coal qualities. Using this approach to valuation, certain contracts, where the expected contract price is above market at the Acquisition date, have a positive value and are classified as assets. Certain other contracts, where the expected contract price is below market at the Acquisition date, have a negative value and are classified as liabilities. The asset or liability is amortized over the term of the contracts based on the tons of coal shipped under each contract. During 2006, the amortization of coal supply agreements was a ($13,122) net credit, which consisted of a $20,390 expense related to the amortization of contract assets and a ($33,512) credit related to the amortization of contract liabilities. As of December 31, 2006, total accumulated amortization of the contract assets and contract liabilities was $66,342 and $231,605, respectively. As of December 31, 2005, total accumulated amortization of the contract assets and contract liabilities was $45,952 and $198,093, respectively. Based on expected future shipments under these agreements, amortization of the asset for above market contracts is anticipated to be approximately $11,000, $8,000, $7,000 and $5,000 for the years ended December 31, 2007, 2008, 2009 and 2010, respectively. Amortization of the liability for below market contracts is anticipated to be approximately ($15,000), ($6,000), ($2,000) and ($1,000) for the years ended December 31, 2007, 2008, 2009 and 2010, respectively.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Notes to Consolidated Financial Statements (Continued)

(Dollars in thousands, except per share data)

Asset Impairment and Disposal of Long-lived Assets

The Company reviews and evaluates its long-lived assets and certain identifiable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.

Income Taxes

The Company is included in the consolidated income tax return of its Public Parent.

Income taxes are accounted for under the asset and liability method in accordance with SFAS No. 109, Accounting for Income Taxes (“SFAS No. 109”). Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and the respective tax bases for such assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in operations in the period that includes the enactment date.

FCL and the Predecessor filed consolidated United States federal income tax returns including its subsidiaries. No written tax sharing agreements exist between FCL and its subsidiaries. The Predecessor filed its final tax returns for the period ended July 29, 2004. FCL adopted a December 31 tax year and filed tax returns for the period from February 9, 2004 (date of formation) through December 31, 2004. Certain state income tax returns were not impacted by the Acquisition.

A valuation allowance is provided to reduce deferred tax assets if, in management’s judgment, it is more-likely-than-not that some portion of the deferred tax assets will not be realized.

Advance Mining Royalties

Leased mineral rights are often acquired through royalty payments. Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoverable against future production. These advance payments are deferred and charged to operations as the coal reserves are mined. In instances where advance payments are not expected to be recoverable against future production, no asset is recognized and the scheduled future payments are expensed as incurred. Deferred advance mining royalties are recorded in Prepaid expenses and Other noncurrent assets on the Consolidated Balance Sheets.

Revenue Recognition

Revenue is recognized on coal sales when title passes to the customer, in accordance with the terms of the sales agreement, which generally occurs when the coal is loaded into transport carriers for shipment to the customer.

Freight Revenue and Costs

Shipping and handling costs paid to third-party carriers and invoiced to coal customers are recorded and included in Cost of coal sales and Coal sales revenue, respectively.

Workers’ Compensation

The Company is primarily self-insured for workers’ compensation claims in the various states in which it operates. The liability for workers’ compensation claims is an actuarially determined estimate of the undiscounted ultimate losses incurred on known claims plus a provision for incurred but not reported claims. This probable ultimate liability is re-determined semi-annually and resultant adjustments are expensed. These obligations are included in the Consolidated Balance Sheets as Other current liabilities and Other noncurrent liabilities.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Notes to Consolidated Financial Statements (Continued)

(Dollars in thousands, except per share data)

Pension, Other Postretirement Plans and Pneumoconiosis (Black Lung) Benefits

Pension benefits, postretirement benefits and postemployment benefits are reflected in the Company’s consolidated financial statements and accounted for in accordance with SFAS No. 87, Employers’ Accounting for Pensions (“SFAS No. 87”); SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions (“SFAS No. 106”) and SFAS No. 112, Employers’ Accounting for Postemployment Benefits (“SFAS No. 112”), respectively, as amended by SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS No. 158”), in the year that the recognition provisions of SFAS No. 158 are initially applied. The pension and postretirement benefits are accounted for over the estimated service lives of the employees. The cost of providing certain postemployment benefits is generally recognized when the employee becomes entitled to the benefit.

In September 2006, the FASB issued SFAS No. 158, which requires an employer to recognize the overfunded or underfunded status of a defined benefit pension and other postretirement plans (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income. SFAS No. 158 requires the Company to initially recognize the funded status of a defined benefit pension and other postretirement plans and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006. Additionally, for fiscal years ending after December 15, 2008, the Company is required to measure plan assets and benefit obligations as of the date of the Company’s fiscal year-end statement of financial position rather than at an interim period. On December 31, 2006, the Company adopted the recognition and disclosure provisions of SFAS No. 158. The effect of adopting SFAS No. 158 on the Company’s financial condition at December 31, 2006 has been included in the accompanying consolidated financial statements. See Note 14 for further discussion of the effect of adopting SFAS No. 158 on the Company’s consolidated financial statements.

The Company is required by federal and state statutes to provide benefits to employees for awards related to black lung. The Company is largely self-insured for these benefits and funds benefit payments through a Section 501 (c) (21) tax-exempt trust fund. Provisions are made for estimated benefits based on annual evaluations prepared by independent actuaries. The Company follows SFAS No. 106 for purposes of accounting for its black lung liabilities and assets.

Derivative Instruments and Hedging Activities

Derivative instruments and hedging activities are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activity (“SFAS No. 133”) (as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities). SFAS No. 133 establishes accounting and reporting standards for derivative instruments and hedging activities and requires that entities recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value. Those fair value adjustments are to be included either in the determination of net income or as a component of other comprehensive income, depending on the nature of the transaction.

On the date the derivative contract is entered into, the Company generally designates the derivative as either a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), a hedge of a forecasted transaction, or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as fair value or cash flow hedges to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company also formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Company discontinues hedge accounting prospectively and records all changes in fair value in income.

Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a fair value hedge, along with the loss or gain on the hedged asset or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk are recorded in income. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash flow hedge are recorded in other comprehensive income, until income is affected by the variability in cash flows of the designated hedged item.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Notes to Consolidated Financial Statements (Continued)

(Dollars in thousands, except per share data)

Stock-Based Compensation

Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS No. 123(R)”), using the modified prospective transition method. Under the modified prospective transition method, compensation cost recognized includes: (a) compensation cost for all stock-based awards granted prior to but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123; and (b) compensation cost for all stock-based awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R). Results from prior periods have not been restated. For all grants, the amount of compensation expense to be recognized is adjusted for an estimated forfeiture rate which is based on historical data. Compensation expense for awards with cliff vesting provisions is recognized on a straight-line basis from the measurement date through the vesting date. The cumulative effect of adoption of SFAS No. 123(R) as of January 1, 2006 was not material. See Note 16 for further discussion of the effect of adopting SFAS No. 123(R) on the Company’s consolidated financial statements.

Prior to the adoption of SFAS No. 123(R), the Company recorded compensation expense for all employee stock-based compensation plans using the intrinsic value method prescribed by Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”) and related interpretations. Under APB No. 25, compensation expense is recorded over the vesting period to the extent that the fair value of the underlying stock on the date of grant exceeds the exercise or acquisition price of the stock or stock-based award. The Company adopted the disclosure-only provisions of SFAS No. 123, Accounting for Stock-Based Compensation, (“SFAS No. 123”), as amended by SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123 for the periods prior to January 1, 2006. Under APB No. 25, compensation expense for restricted stock performance units was initially based on the fair value of the underlying stock on the date of grant. The amount of unearned compensation was subsequently adjusted each period to reflect changes in the fair value of the underlying stock. Compensation expense for restricted stock performance units is amortized over the vesting period.

Comprehensive Income (Loss)

In addition to net income (loss), comprehensive income (loss) includes all changes in equity during a period, such as adjustments to minimum pension liabilities and the effective portion of changes in fair value of derivative instruments that qualify as cash flow hedges.

Debt Issuance Costs

Costs incurred in connection with the issuance of the certain debt facilities were capitalized and are being amortized over a weighted-average term, reflective of the lives of the related indebtedness ranging between 5 to 10 years, using the effective interest method.

New Pronouncements

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Liabilities Including an amendment of FASB Statement No. 115 (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The Company expects to adopt SFAS No. 159 on January 1, 2008 and has not yet determined the impact on the consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This statement clarifies how to measure fair value as permitted under other accounting pronouncements but does not require any new fair value measurements. However, for some entities, the application of this statement will change current practice. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company expects to adopt SFAS No. 157 on January 1, 2008. The Company has not yet determined the impact of SFAS No. 157 on the consolidated financial statements.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Notes to Consolidated Financial Statements (Continued)

(Dollars in thousands, except per share data)

Reclassifications

Certain amounts in the prior period have been reclassified to conform to the 2006 presentation. The Company reclassified the balance sheet amount for prepaid major repairs from the historical presentation in Other noncurrent assets to Plant, equipment and mine development costs, net. The Company reclassified $22,447 of the balance sheet amount included in Other current assets at December 31, 2005 to Prepaid expenses.

Note 4. Acquisition of RAG

On July 30, 2004, the Company acquired 100% of the outstanding common shares of all of the direct and indirect subsidiaries of RAG engaged in coal mining in North America for a purchase price of $986,918 including associated transaction costs of approximately $19,618. In connection with the Acquisition, the Company’s subsidiary, Foundation PA Coal Company, LLC (“Foundation PA”) issued $300,000 of 7.25% Senior Notes due 2014 (“Notes”) and entered into a Senior Credit Facility (the “original facility”) that consisted of a $470,000 term loan facility and a $350,000 revolving credit facility. The purchase price along with the associated transaction costs were funded by $196,000 of cash from shareholders’ equity contributed to the Company and its subsidiaries FC 2 Corp. and FCC by LLC; $300,000 of cash proceeds from the Notes; and $530,000 of cash proceeds from the Senior Credit Facility, which consisted of the $470,000 term loan and a $60,000 draw from the revolving credit facility. The $60,000 draw was repaid with available cash subsequent to the acquisition. The Company incurred $28,573 of debt issuance costs associated with obtaining the debt financing.

In connection with the Acquisition, Blackstone, First Reserve and AMCI (the “Sponsors”) entered into a transaction fee and monitoring agreement with FCC relating to certain monitoring, advisory and consulting services under the monitoring agreement. In addition, FCC paid a transaction and advisory fee to the Sponsors in an aggregate amount of $11,700 upon the completion of the Acquisition. This payment was included in the direct costs associated with the Acquisition. Under the monitoring agreement, FCC agreed to pay to the Sponsors an aggregate annual monitoring fee of approximately $2,000, and reimbursed the Sponsors for their out-of-pocket expenses. The Company therefore paid the Sponsors $2,000, which is included in selling, general and administrative expenses for the period ended December 31, 2004. As a result of the IPO, the monitoring agreement terminated and the Sponsors received a termination payment equal to $2,000, which was included in the offering expenses and charged to additional paid-in capital during the period ended December 31, 2004. FCC agreed to indemnify the Sponsors and their respective affiliates, directors, officers and representatives for any and all losses relating to the services contemplated by the transaction and monitoring fee agreement and the engagement of the Sponsors pursuant to, and the performance by them of the services contemplated by, the transaction and monitoring fee agreement.

The Acquisition was accounted for using the purchase method of accounting whereby identifiable assets acquired and liabilities assumed were recorded at their fair market values as of the date of acquisition. The allocation of the purchase price for the Acquisition was finalized and recorded in the accompanying consolidated financial statements as of and for the periods subsequent to July 30, 2005.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Notes to Consolidated Financial Statements (Continued)

(Dollars in thousands, except per share data)

The following table summarizes the final purchase price allocation based on the fair values of the assets acquired and liabilities assumed at the date of Acquisition:


Accounts receivable	$	73,969
Materials and supplies inventories		10,636
Coal inventory		11,984
Other current assets		32,918
Owned surface lands		30,054
Plant, equipment, mine development, asset retirement costs		490,794
Owned and leased mineral rights		1,244,504
Coal supply agreements		101,081
Other noncurrent assets		14,115

Total assets acquired		2,010,055

Accounts payable and accrued expenses		(164,764	)
Coal supply agreements		(255,872	)
Other noncurrent liabilities		(684,509	)

Total liabilities assumed		(1,105,145	)

Total purchase price net of cash acquired of $82,008	$	904,910

The purchase price allocation was completed based upon analysis provided by an independent appraisal performed by a reputable consulting firm well known in the industry, actuarial valuations of employee benefits performed by consulting actuaries and other internal analysis. Certain judgments and estimates by the Company regarding future cash flows from individual mine sites, employee benefit assumptions and other plans were integral to the valuations performed by the valuation specialists.

Cash and cash equivalents, accounts receivable, other current assets and accounts payable and accrued expenses were stated at historical carrying values. Given the short-term nature of these assets and liabilities, it was determined that these historical carrying values approximate fair value. The Company’s projected pension, postretirement and postemployment benefit obligations and assets have been reflected in the allocation of purchase price at the projected benefit obligation less plan assets at fair market value, based on independent actuaries engaged by the Company. Deferred income taxes have been provided in the Consolidated Balance Sheet based on the Company’s estimated tax versus book basis of the assets acquired and liabilities assumed, as adjusted to estimated fair values. Owned surface lands, inventory, plant, equipment, mine development costs, owned and leased mineral rights and coal supply agreements have been recorded at estimated fair value based on work performed by the independent valuation specialists as of the date of the Acquisition.

During the twelve months ended December 31, 2005, the Company completed the purchase price allocation and recorded final purchase accounting adjustments that reduced the fair value of total assets acquired and liabilities assumed by $105,892, respectively, or approximately 5% of the fair value assigned in the preliminary purchase price allocation. The most significant component of this decrease related to a revision in deferred income tax liabilities associated with projected postretirement benefit obligations resulting from changes in the assumptions regarding the impact on these obligations of the Medicare Part D prescription drug benefits. The effect of the reduction between the preliminary and final purchase price allocation on assets acquired was a decrease in the fair value assigned to owned and leased mineral rights assets of $92,053, a decrease in coal supply agreement assets of $4,384, a decrease in other current assets of $10,211, offset by an increase in the fair value of owned surface land of $756. The effect of the reduction between the preliminary and final purchase price allocation on assumed liabilities was a decrease in coal supply agreement liabilities of $10,533, a decrease in accounts payable and accrued expenses of $1,042 and a decrease in deferred income taxes included in other noncurrent liabilities of $94,317.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Notes to Consolidated Financial Statements (Continued)

(Dollars in thousands, except per share data)

The following unaudited pro forma financial information reflects the consolidated results of operations for the periods presented as if the Acquisition had taken place on January 1, 2004. The pro forma information incorporates the accounting for the Acquisition based on the preliminary purchase price allocation prepared in 2004 which included but was not limited to, the application of purchase accounting for coal supply agreements, owned and leased mineral rights, employee benefit liabilities and property, plant and equipment. The pro forma financial information does not reflect final purchase accounting adjustments recorded in 2005 and may not necessarily be indicative of actual results.


	Pro forma (Unaudited)
	Twelve Months Ended December 31, 2004
Revenues	$	995,631
Income (loss) from continuing operations	$	(60,922	)
Income (loss) before accounting change	$	(37,857	)
Net income (loss)	$	(37,857	)

Note 5. Write-down of Long-Lived Assets

In the fourth quarter of 2006, the Company recognized an asset impairment charge to write-down the carrying value of assets at its Wabash mine (“Wabash assets”) to their estimated fair value and to write-off a prepaid royalty in Central Appalachia in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-lived Assets. These impairment charges are recorded as Write-down of long-lived assets on the Statements of Consolidated Operations and Comprehensive Income (Loss). At the Wabash mine, the Company wrote down assets included in Inventories, net; Owned surface lands; Plant, equipment and mine development costs, net and Owned and leased mineral rights, net, in the Consolidated Balance Sheets by $1,517, $439, $21,686 and $5,730, respectively. The Company noted impairment indicators with respect to the Wabash assets and the on-going recoverability of the carrying value of the assets in the fourth quarter of 2006 based primarily upon its analysis of recent financial results. Analysis of these financial indicators as well as other non-financial indicators lead to management’s decision, late in the fourth quarter of 2006, to discontinue additional capital expenditures related to an ongoing mine recapitalization and development project. In testing the recoverability of the carrying value of the Wabash assets and in assessing their fair value, the Company utilized a combination of cash flow projections, third party appraisals and other evidence of fair value, including an assessment of the assets’ value in the open market. The Wabash assets are included in the Company’s “Other” segment. See Note 22. In Central Appalachia as a result of a change in the Company’s mine plan, the Company wrote-off $1,410 of prepaid royalties previously recorded in Other noncurrent assets. These royalties were associated with a lease under which future mining was determined to be not probable. This determination was made in the fourth quarter of 2006.

In the fourth quarter of 2005, as a result of a change in the Company’s mine plan, the Company recorded a write-down related to development costs incurred during 2003 through 2004 that were attributable to expanding certain undeveloped areas of mining districts in the Company’s Northern Appalachia business unit. These costs were included in Other noncurrent assets as prepaid longwall development costs. The write-down of $1,633 is included in the Statements of Consolidated Operations and Comprehensive Income (Loss) as Write-Down of long-lived assets.

Note 6. Significant Property Transactions

In the third quarter of 2006, Pioneer Fuel Corporation, an indirect wholly owned subsidiary of the Company, purchased mining assets from Appalachian Fuels, LLC for $15,400. The purchased assets consisted of approximately 7.3 million tons of reserves, land and mining equipment that are recorded in Owned and leased mineral rights, net; Owned surface lands and Plant, equipment and mine development costs, net, respectively, in the Consolidated Balance Sheets. The acquired reserves are located adjacent to and have been integrated with and are jointly managed with the existing Pax surface operations. In accordance with terms set forth in the asset purchase agreement, $1,000 of the purchase price was withheld for contingencies, but will be remitted to Appalachian Fuels eighteen months after the acquisition date if no contingencies materialize. The purchase price was allocated to the assets and asset retirement obligation acquired/assumed based upon estimates of fair value.

In a separate transaction, coal stockpiles containing an estimated 8,300 tons were also acquired from Appalachian Fuels, LLC for $232 was recorded in Inventories, net in the Consolidated Balance Sheets at the date of acquisition.

Foundation Coal Corporation and Subsidiaries

(An Indirect Wholly Owned Subsidiary of Foundation Coal Holdings, Inc.)

Notes to Consolidated Financial Statements (Continued)

(Dollars in thousands, except per share data)

Note 7. Inventories

Inventories consisted of the following at:


	December 31,
	2006			2005
Saleable coal	$	16,052		$	18,820
Raw coal		2,199			2,207
Work-in-process (deferred overburden)		—			60,406
Materials and supplies		23,620			23,501

		41,871			104,934
Less materials and supplies reserve for obsolescence		(5,100	)		(8,038	)

	$	36,771		$	96,896

Saleable coal represents coal stockpiles ready for shipment to a customer. Raw coal represents coal that requires further processing prior to shipment. At December 31, 2005, work-in-process consisted of costs incurred to remove overburden above an unmined coal seam as part of the surface mining process and generally included labor, supplies, operating overhead and equipment costs charged to operations as coal from the seam was sold.

In purchase accounting, the fair value of partially and fully uncovered coal included consideration of the effort spent prior to the purchase date to remove overburden and get the coal to its partially or fully uncovered state. Therefore, the fair value assigned to partially and fully uncovered coal reserves was higher than that assigned to other coal reserves. Depletion of coal reserves, including the incremental fair value related to pre-Acquisition overburden removal efforts is included in Depreciation, depletion and amortization. Subsequent to the Acquisition date and prior to the implementation of EITF Issue 04-6 on January 1, 2006, the cost associated with removal of overburden to uncover coal reserves was deferred until the related coal is mined and charged to Cost of coal sales when the coal is sold. All partially and fully uncovered coal valued at the Acquisition date was sold by December 31, 2005. For the twelve months ended December 31, 2005 and for the period from April 23, 2004 (date of incorporation) through December 31, 2004, Depreciation, depletion and amortization included the value of overburden removal performed prior to the Acquisition date, which would have been included in Cost of coal sales if incurred subsequent to the Acquisition date.

Note 8. Prepaid Expenses

Prepaid expenses consisted of the following at:


	December 31,
	2006		2005
Prepaid royalties	$	1,427	$	2,122
Prepaid longwall move expense		8,628		5,525
Prepaid SO₂ emission allowances		2,052		1,204
Prepaid taxes		6,330		2,573
Prepaid insurance		10,796		10,327
Other		1,557

Foundation Coal CORP 10-K