UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-K

Annual Report
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2006

Commission file number: 333-107569-03

Arch Western Resources, LLC

(Exact name of registrant as specified in its charter)

Delaware		43-1811130
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification Number)

One CityPlace Drive, Ste. 300, St. Louis, Missouri		63141
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code: (314) 994-2700

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

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

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (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 þ      No o

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

Indicate by check mark whether the registrant is a 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 o      Accelerated Filer o      Non-Accelerated Filer þ

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

     At March 26, 2007, the registrant’s common equity consisted solely of undenominated membership interests, 99.5% of which were held by Arch Western Acquisition Corporation and 0.5% of which were held by a subsidiary of BP p.l.c.

 

 

Table of Contents

		Page
Part I			1
Item 1. Business			1
Item 1A. Risk Factors			15
Item 1B. Unresolved Staff Comments			20
Item 2. Properties			20
Item 3. Legal Proceedings			22
Item 4. Submission of Matters to a Vote of Security Holders			22
Part II			22
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			22
Item 6. Selected Financial Data			22
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			30
Item 8. Financial Statements and Supplementary Data			30
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			31
Item 9A. Controls and Procedures			31
Item 9B. Other Information			31
Part III			31
Item 10. Directors, Executive Officers and Corporate Governance			31
Item 11. Executive Compensation			32
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			32
Item 13. Certain Relationships and Related Transactions, and Director Independence			32
Item 14. Principal Accounting Fees and Services			32
Part IV			33
Item 15. Exhibits and Financial Statement Schedules			33
Purchase and Sale Agreement
Subsidiaries of the Registrant
Certification
Certification
Section 1350 Certification
Section 1350 Certification

 i

Cautionary Statements Regarding Forward-Looking Information

     This document contains “forward-looking statements” — that is, statements related to future, not past, events. In this context, forward-looking statements often address our expected future business and financial performance, and often contain words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” or “will.” Forward-looking statements by their nature address matters that are, to different degrees, uncertain. For us, particular uncertainties arise from changes in the demand for our coal by the domestic electric generation industry; from legislation and regulations relating to the Clean Air Act and other environmental initiatives; from operational, geological, permit, labor and weather-related factors; from fluctuations in the amount of cash we generate from operations; from future integration of acquired businesses; and from numerous other matters of national, regional and global scale, including those of a political, economic, business, competitive or regulatory nature. These uncertainties may cause our actual future results to be materially different than those expressed in our forward-looking statements. We do not undertake to update our forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law. For a description of some of the risks and uncertainties that may affect our future results, you should see “Risk Factors” beginning on page 15.

ii

Glossary of Selected Mining Terms

     Certain terms that we use in this Annual Report on Form 10-K are specific to the coal mining industry and may be technical in nature. The following is a list of selected mining terms and the definitions we attribute to them when we use them throughout this document.

Assigned reserves		Recoverable coal reserves designated for mining by a specific operation.
Btu		A measure of the energy required to raise the temperature of one pound of water one degree of Fahrenheit.
Compliance coal		Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu, requiring no blending or other sulfur dioxide reduction technologies in order to comply with the requirements of the Clean Air Act.
Dragline		A large machine used in the surface mining process to remove the overburden, or layers of earth and rock, covering a coal seam. The dragline has a large bucket, suspended by cables from the end of a long boom, which is able to scoop up large amounts of overburden as it is dragged across the excavation area and redeposit the overburden in another area.
Longwall mining		One of two major underground coal mining methods, employing a rotating drum pulled mechanically back and forth across a long face of coal.
Low-sulfur coal		Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btu.
Preparation plant		A facility used for crushing, sizing and washing coal to remove impurities and to prepare it for use by a particular customer.
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.
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 restoration of land and environmental values to a mining site after the coal is extracted. The process commonly includes “recontouring” or shaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers.
Recoverable reserves		The amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods and under current law.
Reserves		That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.
Room-and-pillar mining		One of two major underground coal mining methods, utilizing continuous miners creating a network of “rooms” within a coal seam, leaving behind “pillars” of coal used to support the roof of a mine.
Unassigned reserves		Recoverable coal reserves that have not yet been designated for mining by a specific operation.

 iii

PART I

Item 1. Business.

     Introduction

     We are a subsidiary of Arch Coal, Inc., one of the largest coal producers in the United States. At December 31, 2006, we operated six active mines located in two of the three major low sulfur coal-producing regions of the United States. Federal and state regulations controlling air pollution affect the demand for certain types of coal by limiting the amount of sulfur dioxide which may be emitted as a result of fuel combustion. As a result of these regulations, we believe demand for low sulfur coal exceeds demand for other types of coal and often earns a premium in the marketplace. Consequently, we focus on mining, processing and marketing bituminous and sub-bituminous coal with low sulfur content. At December 31, 2006, we estimate that our proven and probable coal reserves had an average heat value of approximately 9,279 Btus and an average sulfur content of approximately 0.33%. Because of these characteristics, we estimate that approximately 95.1% of our proven and probable coal reserves consists of compliance coal.

     We sell substantially all of our coal to producers of electric power, steel producers and industrial facilities. For the year ended December 31, 2006, we sold approximately 113.7 million tons of coal. The locations of our mines enable us to ship coal to many of the major coal-fired electric generation facilities in the United States. The following table shows the breakdown of our coal production by region for 2006 and 2005, expressed as a percentage of the total tons produced:

		2006				2005
Powder River Basin			83.3	%			84.0	%
Western Bituminous			16.7				16.0
Total			100.0	%			100.0	%

     In 2006, we sold approximately 79% of our coal under long-term supply arrangements with a term of more than one year. At December 31, 2006, the average volume-weighted remaining term of our long-term contracts was approximately 4.5 years, with remaining terms ranging from one to 11 years. At December 31, 2006, we had a sales backlog, including a backlog subject to price reopener or extension provisions, of approximately 424 million tons.

     Despite a slight decline in United States demand for coal in 2006, we expect global and domestic demand for coal to grow over time. Based on industry estimates of future production, we expect demand growth to exert upward pressure on coal pricing in the future. As a result, we have not yet priced a portion of the coal we plan to produce over the next several years in order to take advantage of expected price increases.

     Our History

     We were formed as a joint venture on June 1, 1998 when Arch Coal acquired certain coal assets of Atlantic Richfield Company and combined those operations with Arch Coal’s existing western operations and Atlantic Richfield’s remaining Wyoming operations.

     On July 31, 2004, Arch Coal purchased the 35% interest in Canyon Fuel Company, LLC not previously owned by us. Through July 31, 2004, our interest in Canyon Fuel was accounted for on the equity method as a result of certain super-majority voting rights in the Canyon Fuel joint venture agreement. Upon Arch Coal’s acquisition of the 35% interest, Canyon Fuel’s joint venture agreement was amended to eliminate the super-majority voting rights. As a result, for periods subsequent to July 31, 2004, we consolidated 100% of the results of Canyon Fuel in our financial statements and recorded minority interest for Arch Coal’s 35% interest in Canyon Fuel.

     On August 20, 2004, Arch Coal acquired Vulcan Coal Holdings, L.L.C., which owns all of the common equity of Triton Coal Company, LLC, and all of the preferred units of Triton for a purchase price of $382.1 million, including transaction costs and working capital adjustments. Following the acquisition, Arch Coal contributed the assets and liabilities of Triton’s North Rochelle mine (excluding coal reserves) to us. Following that contribution, we integrated the operations of the North Rochelle mine with our existing Black Thunder mine in the Powder River Basin.

     On December 30, 2005, we sold to Peabody Energy a rail spur, rail loadout and idle office complex located in the Powder River Basin for a purchase price of $79.6 million. In addition, Arch Coal completed a reserve swap with Peabody pursuant to which Arch Coal exchanged 60 million tons of coal reserves near the former North Rochelle mine for a similar block of 60 million tons of coal reserves more strategically positioned relative to our Black Thunder mining complex. Subsequent to the reserve swap, Arch Coal subleased the coal reserves it received from Peabody to us. We believe these coal reserves will provide us with a more efficient mine plan.

     The Coal Industry

     Overview. Coal is a combustible, sedimentary, organic rock formed from vegetation that has been consolidated between other rock strata and altered by the combined effects of pressure and heat over millions of years. The degree of change undergone by coal as it matures from peat to anthracite significantly affects its physical and chemical properties. Initially, peat is converted into lignite, a relatively soft material that can range in color from dark black to various shades of brown. The continuing effects of temperature

and pressure causes lignite to transform into sub-bituminous coal. Lignite and sub-bituminous coal are typically softer, friable materials characterized by high moisture levels and low carbon content. Because of their carbon content, lignite and sub-bituminous coal generally produce less energy than bituminous, or hard, coal, formed by continuing chemical and physical changes. Under the right conditions, continuing organic maturity can result in anthracite, a hard black rock with a high carbon and energy content and a low level of moisture. According to the World Coal Institute, which we refer to as the WCI, sub-bituminous and bituminous coal comprise approximately 82% of the global coal reserves.

     Because of its chemical composition, coal is a major contributor to the global energy supply, providing more than 39% of the world’s electricity, according to the WCI. The United States produces approximately one-fifth of the world’s coal and is the second largest coal producer in the world, exceeded only by China. Coal in the United States represents approximately 95% of the domestic fossil energy reserves with over 250 billion tons of recoverable coal, according to the United States Geological Survey.

     Coal is primarily used to fuel electric power generation in the United States. Based on data from the Energy Information Administration, which we refer to as the EIA, coal-based power plants generated approximately 50% of the electricity produced in the United States in 2006. Coal also represents the lowest cost fossil fuel used for electric power generation. According to the EIA, the average delivered cost of coal to electric power generators during the fourth quarter of 2006 was $1.67/mm Btu, which was $5.67/mm Btu less expensive than residual fuel oil and $5.12/mm Btu less expensive than natural gas.

     Compared to other fuels used for electric power generation, coal is domestically available and reliable. Prices for oil and natural gas in the United States have reached record levels in recent years because of tensions regarding international supply and the impact of hurricane interruptions in the Gulf of Mexico in 2005. Historically high oil and natural gas prices have resulted in renewed interest, not only in adding new coal-based electric power generation, but also in “refining” coal into transportation fuels, such as low-sulfur diesel. According to data from Platts, more than 90 gigawatts of new coal-based generation is now planned in the United States. Additionally, government and private sector interest in coal-gasification and coal-to-liquids technologies has increased.

     We expect coal to continue to grow as a domestic fuel as capital is deployed for mine development and expansion and for increased railroad capacity. During 2006, the two existing rail transportation providers in the Powder River Basin in Wyoming expanded their rail capacity, and a potential third rail transportation provider is advancing with plans to construct additional access to this region. We believe this development further demonstrates the commitment to coal as a future source of fuel for the United States.

     Coal is expected to remain the fuel of choice for domestic power generation through at least 2030, according to the EIA. Through that time, we expect new technologies intended to lower emissions of sulfur dioxide, nitrous oxides, mercury, and particulates will be introduced into the power generation industry. We also expect advances in technologies designed to capture and sequester carbon dioxide emissions. These technologies have garnered greater attention in recent years due to the perceived impact of carbon dioxide on the global climate. We believe these technological advancements will help coal retain its role as a key fuel for electric power generation well into the future.

     U.S. Coal Consumption. Coal produced in the United States is used primarily by electric generation facilities to generate electricity, by steel companies to produce coke for use in blast furnaces and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. Coal consumption in the United States has increased from 398.1 million tons in 1960 to approximately 1.1 billion tons in 2006, based on information provided by EIA.

     According to the EIA, United States coal consumption by sector for 2006 and 2005 is as follows (tons in millions):

		2006								2005
End Use		Tons				%				Tons				%
Electric generation			1,023.3				92.0	%			1,037.5				92.2	%
Industrial			61.5				5.5				60.3				5.3
Steel production			23.3				2.1				23.4				2.1
Residential/Commercial			4.3				0.4				4.2				0.4
Total			1,112.4				100.0	%			1,125.4				100.0	%

Source: EIA

     Coal has long been favored as an electricity generating fuel because of its cost advantage and its availability throughout the United States. According to the EIA, coal accounted for approximately 50% of U.S. electricity generation in 2006 and is projected to account for approximately 57% in 2030, while generation from natural gas is expected to peak in 2020. The largest cost component in electricity generation at natural gas- and coal-fired power plants is fuel. According to the National Mining Association, which we refer to as the NMA, coal is the lowest-cost fossil fuel used for electric power generation, averaging less than one-third of the price of both petroleum and natural gas. According to the EIA, for a new coal-fired power plant built today, fuel costs would represent about one-half of total operating costs, whereas the share for a new natural gas-fired power plant would be almost 90%. Other factors that influence an electric generation facility’s choice of generation method may include facility cost, fuel transportation infrastructure and environmental restrictions.

     Planned new domestic coal-fueled electric generation capacity announcements exceeded 90 gigawatts at December 31, 2006, equating to as much as 300 million tons of additional coal demand annually. We estimate that, at December 31, 2006, approximately 15 gigawatts of generating capacity was under construction or in advanced stages of development with completion expected by 2010, an amount that could translate into as much as 60 million tons of incremental coal demand during that time period. We believe that demand growth from new coal-fueled electric generation facilities represents an important element to the long-term outlook for coal.

     According to the EIA, the breakdown of United States electricity generation by fuel source in 2006 is as follows:

Electricity Generation Mode		%
Coal			50.1	%
Nuclear			20.1
Natural gas			19.0
Hydro			7.3
Petroleum and other			3.5
Total			100.0	%

Source: EIA

     The EIA projects that generators of electricity will increase their demand for coal as demand for electricity increases. The EIA expects coal use for electricity generation to increase by 1.5% per year on average from 2005 to 2030. Coal consumption has generally grown at the pace of electricity growth because coal-fired generation is used in most cases to meet base load requirements. We estimate that coal consumption for power generation declined 0.9% in 2006 as a result of an overall reduction in electricity generation demand. Demand for electricity has historically grown in proportion to the United States economic growth by gross domestic product. In 2006, however, gross domestic product rose by approximately 3.4% according to the U.S. Department of Commerce. According to our estimates, this anomaly of a growing economy and declining coal consumption has occurred only four times since the early 1950s.

     Demand for coal is broadly influenced by weather as evidenced by the decline in coal consumption in 2006 in response to very mild weather patterns throughout much of the United States. Weather patterns requiring greater use of heating or air-conditioning translate into greater demand for coal generation. As a result of the mild weather during 2006, coal stockpiles at electric generation facilities totaled 136.0 million tons near the end of 2006, according to the EIA, representing an approximate 47-day supply. In comparison, coal stockpiles totaled 101.1 million tons, or an approximate 35-day supply at December 31, 2005, according to the EIA. We believe that some electric generation facilities may decide to maintain higher coal supplies in order to alleviate the impact of critically low stockpiles such as those experienced at the end of 2005. Coal consumption patterns are also influenced by governmental regulation impacting coal production and power generation; technological developments; and the location, availability and quality of competing sources of energy, including natural gas, oil and nuclear energy, and alternative energy sources, such as hydroelectric power.

     The other major market for coal is the steel industry. Coal is essential for iron and steel production. According to the WCI, approximately 64% of all steel is produced from iron made in blast furnaces that use coal. The steel industry uses metallurgical coal, which is distinguishable from other types of coal because of its high carbon content, low expansion pressure, low sulfur content and various other chemical attributes. Because of these characteristics, the price offered by steel makers for metallurgical coal is generally higher than the price offered by electric generation facilities for steam coal.

     Historically high oil and gas prices and global energy security concerns have increased interest in converting coal into a liquid fuel, a process known as liquefaction. Liquid fuel produced from coal can be refined further to produce transportation fuels and other oil products, such as plastics and solvents. Public and governmental interest in these and other coal-conversion technologies has increased, particularly with the introduction of several legislative initiatives in early 2007. We believe the advancement of coal-conversion and other technologies represents a positive development for the long-term demand for coal.

     U.S. Coal Production. In 2006, total coal production in the United States as estimated by the U.S. Department of Energy was 1.1 billion tons. Production of coal in the United States has increased from 434 million tons in 1960 to approximately 1.1 billion tons in 2006 based on information provided by EIA. According to the EIA, the breakdown of United States coal production by producing region for 2006 and 2005 is as follows (tons in millions):

		2006								2005
		Tons				%				Tons				%
Western			612.9				52.9	%			585.0				51.7	%
Appalachia			395.2				34.1				397.3				35.1
Interior (1)			151.4				13.0				149.2				13.2
Total			1,159.5				100.0	%			1,131.5				100.0	%

     Western region. The western region includes the Powder River Basin and the Western Bituminous region. The Powder River Basin is located in northeastern Wyoming and southeastern Montana. Coal from this region has a very low sulfur content and a low heat value. The price of Powder River Basin coal is generally less than that of coal produced in other regions because Powder River Basin coal exists in greater abundance, is easier to mine and thus has a lower cost of production. However, Powder River Basin coal is generally lower in heat value, which requires some electric power generation facilities to blend it with higher Btu coal or retrofit existing coal plants to accommodate lower Btu coal. The Western Bituminous region includes western Colorado and eastern Utah. Coal from this region typically has a low sulfur content and varies in heat value. According to the EIA, coal produced in the western United States increased from 408.3 million tons in 1994 to 612.9 million tons in 2006.

     Appalachian region. The Appalachian region is divided into the north, central and southern Appalachian regions. Central Appalachia includes eastern Kentucky, Virginia and southern West Virginia. Coal mined from this region generally has a high heat value and low sulfur content. Northern Appalachia includes Maryland, Ohio, Pennsylvania and northern West Virginia. Coal from this region generally has a high heat value and a high sulfur content. According to the EIA, coal produced in the Appalachian region decreased from 445.4 million tons in 1994 to 395.2 million tons in 2006, primarily as a result of the depletion of economically attractive reserves, permitting issues and increasing costs of production.

     Interior region. The Illinois basin includes Illinois, Indiana and western Kentucky and is the major coal production center in the interior region of the United States. Coal from the Illinois basin varies in heat value and has high sulfur content. Despite its high sulfur content, coal from the Illinois basin can generally be used by some electric power generation facilities that have installed pollution control devices, such as scrubbers, to reduce emissions. Other coal-producing states in the interior region include Arkansas, Kansas, Louisiana, Mississippi, Missouri, North Dakota, Oklahoma and Texas. According to the EIA, coal produced in the interior region decreased from 179.9 million tons in 1994 to 151.4 million tons in 2006.

     International Coal Production. Coal is imported into the United States, primarily from Columbia and Venezuela. Imported coal generally serves coastal states along the Gulf of Mexico, such as Alabama and Florida, and states along the eastern seaboard. We believe that significant new capital expenditures for transportation infrastructure would have to be incurred by inland coal consumers in the United States if they desired to import significant quantities of foreign coal because most domestic waterways and water transportation facilities are built for export rather than import of coal. To date, the cost of transporting coal from the coast to interior electric generation facilities via rail has generally proven to be expensive. However, coal imports have demonstrated recent strength due to their competitive pricing, particularly when compared to Appalachian coal. According to the EIA, coal imports increased from 8.9 million tons in 1994 to 36.1 million tons in 2006.

     Coal Mining Methods

     The geological characteristics of coal reserves largely determine the coal mining method employed. There are two primary methods of mining coal: surface mining and underground mining.

     Surface Mining. We use surface mining when coal is found close to the surface. We have included the identity and location of our surface mining operations in the table on page 7. In 2006, approximately 83% of our coal production came from surface mining operations.

     Surface mining involves removing overburden (earth and rock covering the coal) with heavy earth-moving equipment, such as draglines, power shovels, excavators and loaders. Once exposed, we drill, fracture and systematically remove the coal using haul trucks or conveyors to transport the coal to a preparation plant or to a unit train loadout facility. After we have removed the coal, we use draglines, power shovels, excavators or loaders to backfill the remaining pits with the overburden removed at the beginning of the process. Once we have replaced the overburden and topsoil, we reestablish vegetation and make other improvements that have local community and environmental benefits.

     The following diagram illustrates a typical surface mining operation:

     Underground Mining. We use underground mining methods when coal is located deep beneath the surface. We have included the identity and location of our underground mining operations in the table on page 7. In 2006, approximately 17% of our coal production came from underground mining operations.

     Our underground mines are typically operated using longwall mining techniques. Longwall mining involves the full extraction of coal from a section of a coal seam using mechanical shearers. Longwall mining is effective for long rectangular blocks of medium to thick coal seams. Ultimate seam recovery using longwall mining techniques can reach 70%. In longwall mining, we use continuous mining equipment to develop access to long rectangular coal seams. Hydraulically-powered supports temporarily hold up the roof of the mine while a rotating drum mechanically advances across the face of the coal seam, loosening the coal. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface. Once coal is extracted from an area, the roof is allowed to collapse in a controlled fashion.

     The following diagram illustrates a typical underground mining operation using longwall mining techniques:

     Coal Preparation. Coal extracted from the ground, particularly at our underground mining operations, contains impurities, such as rock and dirt, and comes in a variety of different-sized fragments. Our Dugout Canyon mining complex in the Western Bituminous region uses a coal preparation plant located near the mine. This coal preparation plant allows us to treat the coal we extract from that mining complex to ensure a consistent quality and to enhance its suitability for particular end-users. For more information about our preparation plants, you should see the section entitled “Our Mining Operations” below.

     The treatments we employ depend on the properties of the extracted coal and its intended use. To remove impurities, we crush raw coal and separate it into various sizes. For larger pieces of coal, we use dense media separation techniques in which we float coal in a tank containing a liquid of specific gravity. Since coal is lighter than its impurities, it floats, and we can separate it from rock and other sediment. We treat smaller pieces of coal using a number of different methods, including centrifuge devices. A centrifuge spins material very quickly, causing solids and liquids to separate.

     Our Mining Operations

     At December 31, 2006, we operated six active mines at seven mining complexes located in the United States. We have two reportable business segments, which are based on the low sulfur coal producing regions in the United States in which we operate — the Powder River Basin and the Western Bituminous region. These geographically distinct areas are characterized by geology, coal transportation routes to consumers, regulatory environments and coal quality. These regional similarities have caused market and contract pricing environments to develop by coal region and form the basis for the segmentation of our operations.

     The following map shows the locations of our mining operations:

     The following table provides the location of and a summary of information regarding our mining complexes at December 31, 2006, the total sales associated with these complexes for the years ended December 31, 2004, 2005 and 2006 and the total reserves associated with these complexes at December 31, 2006. The amounts disclosed below for the total cost of property, plant and equipment of each mining complex do not include the costs of the coal reserves that we have assigned to any individual complex:

																										Total Cost
																										of Property,
																										Plant and
																										Equipment
						Mining								Tons Sold												at December				Assigned
Mining Complex		Mines				Equipment				Railroad				2004				2005				2006				31, 2006				Reserves
																		(Million tons)								($ in millions)				(Million tons)
Powder River Basin:
Black Thunder			S				D, S			UP/BN					75.1				87.6				92.5			$	577.2				1,403.2
Coal Creek (1)			S				D, S			UP/BN					¾				¾				3.1				140.4				232.0
Western Bituminous:
Arch of Wyoming (2)			¾				¾			UP					0.2				¾				¾				23.0				19.7
Dugout Canyon (3)			U			LW, C				UP					3.8				4.9				4.2				105.0				35.6
Skyline (3) (4)			U			LW, C				UP					0.6				¾				1.5				96.3				14.5
Sufco (3)			U			LW, C				UP					7.8				7.5				7.4				178.5				60.5
West Elk			U			LW, C				UP					6.2				5.9				5.0				204.8				66.9
Totals															93.7				105.9				113.7			$	1,325.2				1,832.4

S = Surface mine		D = Dragline		UP = Union Pacific Railroad
U = Underground mine		S = Shovel/truck		BN = Burlington Northern Railroad
		LW = Longwall
		C = Continuous miner

     Powder River Basin. Our operations in the Powder River Basin are located in Wyoming and include two surface mines. During 2006, these mining complexes sold approximately 95.6 million tons of compliance coal to customers in the United States. We control approximately 1.8 billion tons of proven and probable coal reserves in the Powder River Basin.

Black Thunder		The Black Thunder mine is a surface mining complex located in Campbell County, Wyoming. The mine complex is located on approximately 24,300 acres, with a majority of coal controlled by federal and state leases, as well as a small amount of private fee coal acreage. The mine currently consists of six active pit areas, two owned loadout facilities and one leased loadout facility. All of the coal is shipped raw to customers, and there are no preparation plant processes. All of the production is shipped via the Burlington Northern and Union Pacific railroads. The loadout facilities are capable of loading a 14,500-ton unit train in two to three hours.
Coal Creek		The Coal Creek mine is a surface mining complex located in Campbell County, Wyoming. The mine complex is located on approximately 7,400 acres, with a majority of coal controlled by federal and state leases, and a small amount of private fee coal acreage. The mine currently consists of two active pit areas and one loadout facility. All of the coal is shipped raw to customers, and there are no preparation plant processes. All of the production is shipped via the Burlington Northern and Union Pacific railroads. The loadout facility is capable of loading a 14,000-ton unit train in less than three hours.

     Western Bituminous. Our operations in the Western Bituminous region are located in southern Wyoming, Colorado and Utah and include four underground mines and four inactive surface mines. All of the surface mines are in reclamation mode. During 2006, the mining complexes in the Western Bituminous region sold approximately 18.1 million tons of compliance coal to customers in the United States. We control approximately 464.0 million tons of proven and probable coal reserves in the Western Bituminous region.

Arch of Wyoming		The Arch of Wyoming mining complex is a surface mining complex located in Carbon County, Wyoming. The complex consists of four inactive surface mines that are in the final process of reclamation and bond release. The complex also consists of a mining area called Carbon Basin that has recently begun preliminary development of the surface mining area known as the Elk Mountain mine. The inactive surface mines under reclamation are located on approximately 30,100 acres, with a majority of coal controlled by federal, private and state leases. The Carbon Basin mining area is located on approximately 29,900 acres with a majority of coal controlled by federal, private and state leases. The Arch of Wyoming complex had minimal coal production during 2006 attributable to the development mining at the Elk Mountain mine.
Dugout Canyon		The Dugout Canyon mine is an underground mine located in Carbon County, Utah. The mine is located on approximately 20,000 acres, with a majority of coal controlled by federal and state leases, as well as a small amount of private fee coal acreage. The mine currently consists of a single longwall, two continuous miner sections and one truck loadout facility. We wash a portion of the coal we produce at the Dugout Canyon mine at a 400-ton per hour heavy media vessel preparation plant. All of the production is shipped via the Union Pacific railroad or directly to customers by highway trucks. The mine loadout facility is capable of loading about 20,000 tons per day into highway trucks. Train shipments are handled by a third-party loadout that can load an 11,000-ton train in less than three hours.
Skyline		The Skyline mine is an underground mine located in Carbon and Emery Counties, Utah. The mine is located on approximately 13,300 acres, with a majority of coal controlled by federal leases, as well as a small amount on private and county leases. The mine currently consists of one continuous miner section, a longwall and one loadout facility. All of the coal can be shipped raw to customers, and there are no preparation plant processes. All of the production is shipped via the Union Pacific railroad or directly to customers by highway trucks. The loadout facility is capable of loading a 12,000-ton unit train in less than four hours.
Sufco		The Sufco mine is an underground mine located in Sevier County, Utah. The mine is located on approximately 29,100 acres, with a majority of coal controlled by federal and state leases, as well as a small amount of private fee coal acreage. The mine currently consists of a single longwall, two continuous miner sections and one loadout facility. All of the coal is shipped raw to customers without preparation plant processing. Coal is shipped via the Union Pacific railroad or delivered directly to customers by highway trucks. The rail loadout facility, located approximately 80 miles from the mine, is capable of loading an 11,000-ton unit train in less than three hours.
West Elk		The West Elk mine is an underground mine located in Gunnison County, Colorado. The mine is located on approximately 17,000 acres, with a majority of coal controlled by federal and state leases, as well as a small amount of private fee coal acreage. The mine currently consists of a single longwall, three continuous miner sections and one loadout facility. All of the coal is shipped raw to customers, and there are no preparation plant processes. All of the production is shipped via the Union Pacific railroad. The loadout facility is capable of loading an 11,000-ton unit train in less than three hours.

     We also incorporate by reference the information about the operating results of each of our segments for the years ended December 31, 2006, 2005 and 2004 contained in Note 21 – Segment Information to our consolidated financial statements beginning on page F-1.

     Transportation

     We ship our coal to customers by means of railroad cars or trucks, or a combination of these means of transportation. As is customary in the industry, once the coal is loaded onto the rail car, our customers are typically responsible for the freight costs to the ultimate destination. Transportation costs borne by the customer vary greatly based on each customer’s proximity to the mine and our proximity to the loadout facilities.

     Sales, Marketing and Customers

     Coal prices are influenced by a number of factors and vary dramatically by region. As a result of these regional characteristics, prices of coal by product type within a given major coal producing region tend to be relatively consistent with each other. The price of coal within a region is influenced by market conditions, mine operating costs, coal quality, transportation costs involved in moving coal from the mine to the point of use and the costs of alternative fuels. In addition to supply and demand factors, the price of coal at the mine is influenced by geologic characteristics such as seam thickness, overburden ratios and depth of underground reserves. It is generally cheaper to mine coal seams that are thick and located close to the surface than to mine thin underground seams. Underground mining, which is the mining method we use in the Western Bituminous region, is generally more expensive than surface mining, which is the mining method we use in the Powder River Basin. This is the case because of the higher capital costs, including costs for construction of extensive ventilation systems, and higher per unit labor costs due to lower productivity associated with underground mining.

     In addition to the cost of mine operations, the price of coal is also a function of quality characteristics such as heat value, sulfur, ash and moisture content. Higher carbon and lower ash content generally result in higher prices, and higher sulfur and higher ash content generally result in lower prices.

     Management, including our chief executive officer and chief operating officer, reviews and makes resource allocations based on the goal of maximizing our profits in light of the comparative cost structures of our various operations. Because most of our customers purchase coal on a regional basis, coal can generally be sourced from several different locations within a region. Once we have a contractual commitment to sell coal at a certain price, Arch Coal’s centralized marketing group assigns contract shipments to our various mines which can be used to source the coal in the appropriate region.

     Long-Term Coal Supply Arrangements

     We sell coal both under long-term contracts, the terms of which are more than one year, and on a current market or spot basis with terms of one year or less. In 2006, we sold approximately 79% of our coal under long-term supply arrangements. We expect to sell a significant portion of our coal under long-term supply arrangements. We selectively renew or enter into new long-term supply arrangements when we can do so at prices that we believe are favorable. When our coal sales contracts expire or are terminated, we are exposed to the risk of having to sell coal into the spot market, where demand is variable and prices are subject to greater volatility.

     Provisions permitting renegotiation or modification of coal sale prices are present in some of our more recently negotiated long-term contracts and usually occur midway through a contract or every two to three years, depending upon the length of the contract. In some circumstances, either we have or our customer has the option to terminate the contract if the parties cannot agree on a new price.

     Competition

     The coal industry is intensely competitive. The most important factors on which we compete are coal quality, transportation costs from the mine to the customer and the reliability of supply. Our principal domestic competitors include Foundation Coal Holdings, Inc., Peabody Energy Corp. and Rio Tinto Energy — North America. Some of these coal producers are larger than us and have greater financial resources and larger reserve bases than we do. We also compete directly with a number of smaller producers in each of the geographic regions in which we operate. As the price of domestic coal increases, we may also begin to compete with companies that produce coal from one or more foreign countries, such as Columbia and Venezuela.

     Additionally, coal competes with other fuels, such as nuclear energy, natural gas, hydropower and petroleum, for steam and electrical power generation. Costs and other factors, such as safety and environmental considerations, relating to these alternative fuels affect the overall demand for coal as a fuel.

     Geographic Data

     Coal sales to foreign customers for 2006, 2005 and 2004 were insignificant.

     Environmental Matters

     Our operations, like operations of other coal companies, are subject to regulation, primarily by federal and state authorities, on matters such as the discharge of materials into the environment; employee health and safety; mine permits and other licensing requirements; reclamation and restoration activities involving our mining properties; management of materials generated by mining operations; surface subsidence from underground mining; water pollution; air quality standards; protection of wetlands; endangered plant and wildlife protection; limitations on land use; storage of petroleum products; and substances that are regarded as hazardous under applicable laws including electrical equipment containing polychlorinated biphenyls, which we refer to as PCBs.

     Additionally, the electric generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal. The possibility exists that new legislation or regulations may be adopted or that the enforcement of existing laws could become more stringent, either of which may have a significant impact on our mining operations or our customers’ ability to use coal and may require us or our customers to significantly change operations or to incur substantial costs.

     While it is not possible to quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. Federal and state mining laws and regulations require us to obtain surety bonds to guarantee performance or payment of certain long-term obligations, including mine closure and reclamation costs, federal and state workers’ compensation benefits, coal leases and other miscellaneous obligations. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.

     The following is a summary of the various federal and state environmental and similar regulations that have a material impact on our operations:

     Clean Air Act. The federal Clean Air Act and similar state and local laws, which regulate emissions into the air, affect coal mining and processing operations primarily through permitting and emissions control requirements. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the emissions from coal-fired industrial boilers and power plants, which are the largest end-users of our coal. These regulations can take a variety of forms, as explained below.

     The Clean Air Act imposes obligations on the United States Environmental Protection Agency, which we refer to as EPA, and on the states to implement regulatory programs that will lead to the attainment and maintenance of national ambient air quality standards, which we refer to as NAAQS. EPA has promulgated a number of NAAQS for air pollutants that are associated with the combustion of coal, including sulfur dioxide, particulate matter, nitrogen oxides and ozone. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources in an effort to comply with these standards. As these standards become more stringent in the years ahead, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding.

     In July 1997, EPA adopted more stringent standards for ozone and particulate matter, which we refer to as PM. EPA adopted what is commonly referred to as the 8-hour ozone standard, established for the first time annual and daily standards for fine PM, or particles that are 2.5 micrometers in diameter (PM2.5), and revised the NAAQS for coarse PM, or particles that are less than 10 micrometers in diameter (PM10). EPA’s Phase I and Phase II 8-hour ozone implementation rules were challenged, and in December 2006, the D.C. Circuit Court of Appeals vacated and remanded EPA’s Phase I 8-hour ozone implementation rule. Litigation challenging certain EPA designations for PM2.5 non-attainment areas is currently being held in abeyance pending reconsideration by EPA. States having designated non-attainment areas for the 1997 standards are required to submit their state implementation plans for achieving attainment of the 8-hour ozone standards by April 2007 and the PM2.5 standards by April 2008 and are likely to require electric power generators to reduce further sulfur dioxide, nitrogen oxide and particulate matter emissions. The attainment deadlines for 8-hour ozone non-attainment areas range from 2007 to 2012 and for PM2.5 non-attainment areas range from 2010 to 2015.

     In September 2006, EPA promulgated final, new PM NAAQS. EPA strengthened the daily PM2.5 standards but retained the annual PM2.5 standards and daily PM10 standards and revoked the annual PM10 standards. The 2006 PM NAAQS are the subject of challenge in the D.C. Circuit Court of Appeals. States having non-attainment areas for the 2006 PM2.5 NAAQS are required to submit their state implementation plans for the 2006 PM2.5 NAAQS by April 2013, and the attainment dates range from 2015 to 2020. With respect to ozone, EPA is currently obligated under a consent decree to sign proposed and final rulemakings concerning any new or revised ozone NAAQS in May 2007 and February 2008, respectively.

     In October 1998, EPA finalized a rule that requires 19 states in the eastern United States that have ambient air quality programs to make substantial reductions in nitrogen oxide emissions. Under the rule, which is commonly known as NOx SIP Call, Phase I states were required to reduce nitrogen oxide emissions by 2004, and Phase II states are required to reduce nitrogen oxide emissions by 2007. Except for five states (Indiana, Illinois, Kentucky, Michigan and Virginia) that failed to submit their Phase II NOx SIP Call rules, all affected states have adopted and submitted to EPA NOx SIP Call rules. For the five states that did not submit Phase II NOx SIP Call rules, EPA is expected to promulgate a federal implementation plan in February 2008. As a result of any federal and state implementation plans, many electric power generation facilities and large industrial plants have been or will be required to install additional emission control measures.

     EPA has also initiated a regional haze program designed to protect and improve visibility at and around National Parks, National Wilderness Areas and International Parks, particularly those located in the southwest and southeast United States. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. In June 2005, EPA finalized amendments to the regional haze rules or Clean Air Visibility Rule, which we refer to as CAVR, that will require certain existing coal-fired power plants to install Best Available Retrofit Technology, which we refer to as BART, to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, and particulate matter. In October 2006, EPA published a final emissions trading rule as an alternative to BART. As a result, individual facilities may not have to install emission controls provided the target emissions reductions are met. In December 2006, the D.C. Circuit Court of Appeals upheld EPA’s CAVR, rejecting arguments that EPA’s CAVR improperly allows the states covered by EPA’s Clean Air Interstate Rule trading program to forgo source-specific emissions control requirements to reduce haze. Regional haze state implementation plans are due in 2008.

     New regulations concerning the routine maintenance provisions of the New Source Review program were published in October 2003. These regulations were challenged, and in March 2006, the D.C. Circuit Court of Appeals vacated EPA’s rule as contrary to §111(a) (4) of the Clean Air Act. EPA and a utility trade association petitioned the United States Supreme Court for a writ of certiorari in November 2006. In addition, in October 2005, the EPA published a proposed rule requiring an hourly emissions test for power plants for determining an emissions increase under the New Source Review program. In September 2006, EPA proposed changes to the New Source Review program concerning de-bottlenecking, aggregation, and project netting.

     In January 2004, the EPA Administrator announced that EPA would be taking new enforcement actions against utilities for violations of the existing New Source Review requirements, and shortly thereafter, EPA issued enforcement notices to several electric utility companies. Additionally, the U.S. Department of Justice, on behalf of EPA, filed lawsuits against several investor-owned electric utilities for alleged violations of the Clean Air Act. EPA claims that these utilities have failed to obtain permits required under the Clean Air Act for alleged major modifications to their power plants. Some of these lawsuits have been settled, with the owners agreeing to install additional pollution control devices on their coal-fired power plants, and other cases are still pending.

     In March 2004, North Carolina submitted to EPA a petition under §126 of the Clean Air Act regarding interstate transport of pollution. In its petition, North Carolina alleges that power plants in 12 southeastern and midwestern states contribute significantly to non-attainment in, and interfere with maintenance by, North Carolina with respect to the PM2.5 NAAQS. In addition, North Carolina alleges that power plants in five states contribute significantly to non-attainment in, and interfere with maintenance by, North Carolina with respect to the 8-hour ozone NAAQS. In March 2006, EPA promulgated a final rule denying North Carolina’s §126 petition. Following EPA’s denial of North Carolina’s §126 petition, North Carolina and environmental groups petitioned for review. Depending upon the outcome of the litigation, EPA’s response to North Carolina’s §126 petition could adversely impact the coal needs of power plants in the affected states. With respect to the international transport of pollution, Canadian cities petitioned EPA in November 2006, under §115 of the Clean Air Act, to require emissions reductions from 150 coal-fired power plants in seven midwestern states. If EPA grants the petition, then the affected plants could be required to reduce emissions.

     In March 2005, EPA issued three new rules that will impact coal-fired power plants. The three new rules are (i) the Clean Air Interstate Rule, which we refer to as CAIR, aimed at capping emissions of sulfur dioxide and nitrogen oxides in the eastern United States; (ii) the mercury de-listing rule, which de-lists power plants as a source of mercury and other toxic air pollutants and rescinds a finding made in 2000 that it was appropriate and necessary to regulate power plants under Section 112(c) of the Clean Air Act; and (iii) the Clean Air Mercury Rule, which we refer to as CAMR, aimed at capping and reducing mercury emissions from coal-fired power plants. Both CAIR and CAMR provide power plant operators a market-based system in which plants that exceed federal requirements can sell emission allowances to plant operators who need more time to comply with the stricter rules. CAIR requires reductions of sulfur dioxide and/or nitrogen oxide emissions across 28 eastern states and the District of Columbia and, when fully implemented in 2015, CAIR will reduce sulfur dioxide emissions in these states by over 70% and nitrogen oxide emissions by over 60% from 2003 levels. Under CAMR, mercury emissions from coal-fired power plants will not be regulated as a Hazardous Air Pollutant, which would require installation of Maximum Available Control Technology, which we refer to as MACT. Instead, using the cap-and-trade system, these plants will have until 2010 to cut mercury emission levels to 38 tons a year from 48 tons and until 2018 to bring that level down to 15 tons, a 69% reduction. All three rules are the subject of ongoing litigation.

     CAIR and CAMR state implementation plans were due November 2006. More than 21 states missed the deadline for CAMR state implementation plans. For these states, EPA is expected to promulgate a CAMR federal implementation plan in 2007. More than 23 states have adopted or are in the process of adopting state-specific rules that are more stringent than CAMR.

     In December 2005, seven northeastern states (Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York, and Vermont) signed the Regional Greenhouse Gas Initiative agreement, which we refer to as RGGI, calling for a 10% reduction of carbon dioxide emissions by 2019, with compliance to begin January 1, 2009. Maryland has subsequently signed on as a full participant in RGGI. The RGGI final model rule was issued in August 2006, and the participating states are developing their state rules. New York, for example, issued draft rules in December 2006 proposing to auction, as opposed to allocate, 100% of its allowances under RGGI. Climate change developments are also taking place in California. In September 2006, California adopted

greenhouse gas legislation requiring that long-term base-load generators must not have greenhouse gas emissions rates greater than that of combined cycle natural gas generators. Rules implementing the new greenhouse gas legislation for investor-owned utilities are expected in February 2007. A trading partnership between RGGI states and California has been announced. These and other state climate change rules will likely require additional controls on coal-based electric power generation facilities and industrial boilers and may even cause some users of coal to switch from coal to a lower carbon fuel. In addition, there are a number of climate change lawsuits alleging nuisance and other theories of liability against various defendants pending in the lower courts. In November 2006, the United States Supreme Court heard oral argument in Massachusetts v. EPA on whether EPA has improperly failed to list carbon dioxide as a criteria pollutant. If this litigation results in a court order directing EPA to promulgate a new NAAQS for carbon dioxide, then the market demand for coal could decline.

     Other Clean Air Act programs are also applicable to power plants that use our coal. For example, the acid rain control provisions of Title IV of the Clean Air Act require a reduction of sulfur dioxide emissions from power plants. Title IV imposes a two-phase approach to the implementation of required sulfur dioxide emissions reductions. Phase I, which became effective in 1995, regulated the sulfur dioxide emissions levels from 261 generating units at 110 power plants and targeted the highest sulfur dioxide emitters. Phase II, implemented January 1, 2000, made the regulations more stringent and extended them to additional power plants, including all power plants of greater than 25-megawatt capacity. Affected electric power generation facilities can comply with these requirements by: (i) burning lower sulfur coal, either exclusively or mixed with higher sulfur coal, (ii) installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal, (iii) reducing electricity generating levels or (iv) purchasing or trading emissions allowances. Specific emissions sources receive these allowances, which electric utilities and industrial concerns can trade or sell to allow other units to emit higher levels of sulfur dioxide. Each allowance permits its holder to emit one ton of sulfur dioxide.

     Other proposed initiatives may have an effect upon coal operations. Several so-called mutli-pollutant bills, which would regulate additional air pollutants, have been proposed by various members of Congress. While the details of all of these proposed initiatives vary, there appears to be a movement toward increased regulation of emissions, including carbon dioxide and mercury.

     Mine Health and Safety Laws. Stringent safety and health standards have been imposed by federal legislation since the adoption of the Mine Safety and Health Act of 1969. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Safety and Health Act of 1969, imposes comprehensive safety and health standards on all mining operations. In addition, as part of the Mine Safety and Health Acts of 1969 and 1977, the Black Lung Act requires payments of benefits by all businesses conducting current mining operations to coal miners with black lung and to some survivors of a miner who dies from this disease. The states in which we operate also have mine safety and health laws. Federal legislation was enacted in June 2006 that imposes new requirements for emergency response plans, notification procedures in the event of accidents, and increased civil penalties for violations of the law.

     Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act, which we refer to as SMCRA, establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, we are contractually obligated under the terms of our leases to comply with all laws, including SMCRA and equivalent state and local laws. These obligations include reclaiming and restoring the mined areas by grading, shaping, preparing the soil for seeding and by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan.

     SMCRA also requires us to submit a bond or otherwise financially secure the performance of our reclamation obligations. The earliest a reclamation bond can be completely released is five years after reclamation has been achieved. Federal law and some states impose on mine operators the responsibility for repairing the property or compensating the property owners for damage occurring on the surface of the property as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Act, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is $0.35 per ton of coal produced from surface mines and $0.15 per ton of coal produced from underground mines. These amounts will decline to $0.315 and $0.135, respectively, beginning October 2007.

     We also lease some of our coal reserves to third-party operators. Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent mine lessees and other third parties could potentially be imputed to other companies that are deemed, according to the regulations, to have ‘‘owned’’ or ‘‘controlled’’ the mine operator. Sanctions against the ‘‘owner’’ or ‘‘controller’’ are quite severe and can include civil penalties, reclamation fees and reclamation costs. We are not aware of any claims against us asserting that we ‘‘own’’ or ‘‘control’’ any of our lessees’ operations.

     Framework Convention on Global Climate Change. The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, that is intended to limit or capture emissions of greenhouse gases such as carbon dioxide and methane. The U.S. Senate has neither ratified the treaty commitments, which would mandate a reduction in U.S. greenhouse gas emissions, nor enacted any law specifically controlling greenhouse gas emissions, and the Bush Administration has withdrawn support for this treaty. Nonetheless, future regulation of

greenhouse gases could occur either pursuant to future U.S. treaty obligations or pursuant to statutory or regulatory changes under the Clean Air Act.

     Clean Water Act. The federal Clean Water Act prohibits the “discharge” of “pollutants” into “waters of the United States” without a “permit” and defines each of these terms broadly. The statute affects our mining operations in two distinct ways. First, for any discharge of rock or soil into a topographic feature that might constitute a stream, the U.S. Army Corps of Engineers will require a permit specified under §404 of the Clean Water Act for the placement of such “fill” material into the stream. The Corps’ implementation of this program and issuance of this permit has been highly litigated in West Virginia since 1998.

     Second, EPA, or states which have been delegated the duty, require a permit specified under §402 of the Clean Water Act for any discharge of water from any site that has been disturbed by the act of mining. The §402 permit imposes limitations on the composition of the effluent that flows from the site, and requires that water quality standards specified for the receiving stream also be achieved. This requires our mining operations to always observe certain management practices, such as routing all surface water flows through sedimentation structures, before the discharge enters public waters. Depending upon the precise water quality standards that must be achieved, additional treatment of the discharge may also be required.

     Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, which we refer to as CERCLA, and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances that may endanger public health or welfare or the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners and lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could implicate the liability provisions of the statute. Thus, coal mines that we currently own or have previously owned or operated, and sites to which we sent waste materials, may be subject to liability under CERCLA and similar state laws. In particular, we may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination at sites where we own surface rights.

     Mining Permits and Approvals. Mining companies must obtain numerous permits that strictly regulate environmental and health and safety matters in connection with coal mining, some of which have significant bonding requirements. In connection with obtaining these permits and approvals, we may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit can be refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.

     In order to obtain mining permits and approvals from state regulatory authorities, mine operators must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically we submit the necessary permit applications several months before we plan to begin mining a new area. Some of our required permits are becoming increasingly more difficult and expensive to obtain, and the application review processes are taking longer to complete and becoming increasingly subject to challenge.

     Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.

     Endangered Species. The federal Endangered Species Act and counterpart state legislation protects species threatened with possible extinction. Protection of 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. 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. The Bush Administration has also proposed to add polar bears to the list of endangered species. If that proposal should be finalized, then that action could result in regulation of carbon dioxide emissions to address global warming.

     Other Environmental Laws. We are required to comply with numerous other federal, state and local environmental laws in addition to those previously discussed. These additional laws include, for example, the Resource Conservation and Recovery Act, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. We believe that we are in substantial compliance with all applicable environmental laws.

     Employees

     At March 26, 2007, we employed a total of approximately 1,563 persons. We believe that our relations with all employees are good.

     Executive Officers

     Our managing member is an indirect, wholly-owned subsidiary of Arch Coal. As a result, we are effectively managed by the management of Arch Coal. The following is a list of executive officers of Arch Coal, their ages as of March 26, 2007 and their positions and offices during the last five years:

C. Henry Besten, Jr.		Mr. Besten, 58, is Senior Vice President – Strategic Development of Arch Coal and has served in such capacity since December 2002. Mr. Besten also served as President of Arch Energy Resources, Inc., a subsidiary of Arch Coal, from July 1997 to October 2006. From July 1997 to December 2002, Mr. Besten served as Vice President – Strategic Marketing of Arch Coal. Mr. Besten also served as acting Chief Financial Officer from December 1999 to November 2000.
John W. Eaves		Mr. Eaves, 49, is President and Chief Operating Officer of Arch Coal and has served in such capacity since April 2006. Mr. Eaves has also been a director of Arch Coal since February 2006. From December 2002 to April 2006, Mr. Eaves served as Executive Vice President and Chief Operating Officer of Arch Coal. From February 2000 to December 2002, Mr. Eaves served as Senior Vice President – Marketing of Arch Coal and from September 1995 to December 2002 as President of Arch Coal Sales Company, Inc., a subsidiary of Arch Coal. Mr. Eaves also served as Vice President – Marketing of Arch Coal from July 1997 through February 2000. Mr. Eaves also serves on the board of directors of ADA-ES, Inc.
Sheila B. Feldman		Ms. Feldman, 52, is Vice President – Human Resources of Arch Coal and has served in such capacity since February 2003. From 1997 to February 2003, Ms. Feldman was the Vice President – Human Resources and Public Affairs of Solutia Inc. On December 17, 2003, Solutia Inc. and its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York.
Robert G. Jones		Mr. Jones, 50, is Vice President – Law, General Counsel and Secretary of Arch Coal and has served in such capacity since March 2000. Mr. Jones served as Assistant General Counsel of Arch Coal from July 1997 through February 2000 and as Senior Counsel from August 1993 to July 1997.
Paul A. Lang		Mr. Lang, 46, is Senior Vice President – Operations of Arch Coal and has served in such capacity since December 2006. Mr. Lang served as President of Arch Coal’s western operations from July 2005 through December 2006 and President and General Manager of Thunder Basin Coal Company, L.L.C. from November 1998 through July 2005.
Steven F. Leer		Mr. Leer, 54, is Chairman and Chief Executive Officer of Arch Coal. Mr. Leer served as President and Chief Executive Officer of Arch Coal from 1992 to April 2006. Mr. Leer also serves on the board of directors of the Norfolk Southern Corporation, USG Corp., the Western Business Roundtable and the University of the Pacific and is chairman of the Coal Industry Advisory Board. Mr. Leer is a past chairman and continues to serve on the board of directors of the Center for Energy and Economic Development, the National Coal Council and the National Mining Association.
Robert J. Messey		Mr. Messey, 61, is Senior Vice President and Chief Financial Officer of Arch Coal and has served in such capacity since December 2000. Mr. Messey also serves on the board of directors of Baldor Electric Company and Stereotaxis, Inc.
David B. Peugh		Mr. Peugh, 52, is Vice President – Business Development of Arch Coal and has served in such capacity since 1995.
Deck S. Slone		Mr. Slone, 43, is Vice President – Investor Relations and Public Affairs of Arch Coal and has served in such capacity since 2001. Mr. Slone has helped direct Arch Coal’s investor relations and public affairs functions since joining 1997.

David N. Warnecke		Mr. Warnecke, 51, is Vice President – Marketing and Trading of Arch Coal and is President of our Arch Coal Sales Company, Inc., a subsidiary of Arch Coal. Previously, Mr. Warnecke served as President of Arch Transportation Company and served as Executive Vice President of Arch Coal Sales Company, Inc. until June 1, 2005, when he was appointed President.

     Available Information

     We file annual, quarterly and current reports, and amendments to those reports, and other information with the Securities and Exchange Commission. You may access and read our filings without charge through the SEC’s website, at sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

Item 1A. Risk Factors.

     Our business involves certain risks and uncertainties. In addition to the risks and uncertainties described below, we may face other risks and uncertainties, some of which may be unknown to us and some of which we may deem immaterial. If one or more of these risks or uncertainties occur, our business, financial condition or results of operations may be materially and adversely affected.

Risks Related to Our Business

     Our profitability and the value of our coal reserves depend upon coal demand by United States electric power generators and other factors beyond our control.

     Our results of operations and the value of our coal reserves are substantially dependent upon the prices we receive for our coal. The prices we receive for our coal depend upon factors beyond our control, including the coal consumption patterns of the United States electric generation industry. According to the EIA, the United States electric generation industry accounts for approximately 92% of domestic coal consumption. Certain factors beyond our control, including those listed below, influence the amount of coal consumed for United States electric power generation:

	•		the overall demand for electricity, which in turn significantly depends on general economic conditions and summer and winter temperatures in the United States;
	•		environmental and government regulation, including air emission standards for domestic and foreign coal-fired power plants;
	•		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, wind and solar power; and
	•		technological developments, including the effects of worldwide energy conservation measures.

     Demand for our low sulfur coal and the prices we obtain for it will also be affected by the price and availability of high sulfur coal. In some instances, United States electric power generators can use high sulfur coal together with emissions allowances in order to satisfy federal and state air emission standards. In addition, restrictions imposed by federal and state air emission standards may cause some electric power generators to shift from coal to natural gas-fired power plants. A decrease in coal consumption by United States electric power generators could reduce the prices we receive for our coal. Significant decreases in the prices we receive for our coal could have a material adverse effect on our profitability and the value of our coal reserves.

     Certain conditions or events beyond our control could negatively impact our coal mining operations, our production or our operating costs.

     We conduct coal mining operations in underground mines and at surface mines. Certain factors beyond our control, including those listed below, could disrupt our coal mining operations, reduce our production or increase our operating costs:

	•		unexpected variations in geological conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;
	•		mining and processing equipment failures and unexpected maintenance problems;
	•		interruptions due to transportation delays;
	•		unexpected delays and difficulties in acquiring, maintaining or renewing necessary permits or mining or surface rights;
	•		unavailability of mining equipment and supplies and increases in the price of mining equipment and supplies;
	•		shortage of qualified labor and a significant rise in labor costs;
	•		fluctuations in the cost of industrial supplies, including steel-based supplies, natural gas, diesel fuel and oil;

	•		adverse weather and natural disasters, such as heavy rains and flooding;
	•		unexpected or accidental surface subsidence from underground mining;
	•		accidental mine water discharges, fires, explosions or similar mining accidents; and
	•		regulatory issues involving the plugging of and mining through oil and gas wells that penetrate the coal seams we mine.

     If any of these conditions or events occur, particularly at our Black Thunder mine, our coal mining operations may be disrupted, we could experience a delay or halt of production or our operating costs could increase significantly. In addition, if our insurance coverage is limited or excludes certain of these conditions or events, then we may not be able to recover any of the losses we may incur as a result of such conditions or events, some of which may be substantial.

     Increases in the price of steel, diesel fuel or rubber tires could negatively affect our operating costs.

     Our coal mining operations use significant amounts of steel, diesel fuel and rubber tires. The costs of roof bolts we use in our underground mining operations depend on the price of scrap steel. We also use significant amounts of diesel fuel and tires for the trucks and other heavy machinery we use, particularly at our Black Thunder mine. A worldwide increase in mining, construction and military activities has caused a shortage of the large rubber tires we use in our mining operations. While we have taken initiatives aimed at extending the useful lives of our rubber tires, including increased driver training, improved road maintenance and reduced driving speeds, we may be unable to obtain a sufficient quantity of rubber tires in the future or at prices which are favorable to us. If the prices of steel, diesel fuel and rubber tires increase, our operating costs could be negatively affected. In addition, if we are unable to procure rubber tires, our coal mining operations may be disrupted or we could experience a delay or halt of production.

     Our labor costs could increase if the shortage of skilled coal mining workers continues.

     Efficient coal mining using modern techniques and equipment requires skilled workers with experience and proficiency in multiple mining tasks. The resurgence in coal mining activity in recent years has caused a significant tightening of the labor supply. In addition, employee turnover rates in the coal industry have increased during this period as coal producers compete for skilled personnel. Because of the shortage of trained coal miners in recent years, we have operated certain facilities without full staff and have hired novice miners, who are required to be accompanied by experienced workers as a safety precaution. These measures have negatively affected our productivity and our operating costs. If the shortage of experienced labor continues or worsens, our production may be negatively affected or our operating costs could increase.

     Our inability to acquire additional coal reserves or our inability to develop coal reserves in an economically feasible manner may adversely affect our business.

     As we mine, we deplete our coal reserves. As a result, our ability to produce coal in the future depends, in part, on our ability to acquire additional coal reserves. We may not be able to obtain replacement reserves when we require them. If available, replacement reserves may not be available at favorable prices, or we may not be capable of mining those reserves at costs that are comparable with our existing coal reserves. Our ability to obtain coal reserves in the future could also be limited by restrictions under our existing or future debt agreements and competition from other coal producers. If we are unable to acquire coal reserves to replace the coal reserves we mine, our future production may decrease significantly and our operating results may be negatively affected.

     In addition to the availability of additional coal reserves, our future performance depends on the accuracy with which we estimate the quantity and quality of the coal included within those reserves. We base our estimates of reserve information on engineering, economic and geological data assembled, analyzed and reviewed by internal and third-party engineers and consultants. Certain assumptions and other factors beyond our control, including those listed below, could affect the accuracy of our estimates:

	•		unexpected geological and mining conditions which may not be fully identified by available exploration data or drill hole density and may differ from our experience in areas we currently mine;
	•		future coal prices, operating costs, capital expenditures, severance and excise taxes, royalties and development and reclamation costs;
	•		future mining technology improvements; and
	•		the assumed effects of federal and state environmental, safety or other regulations.

     We control substantial undeveloped reserves and have not identified the equipment or workforce that will be employed to mine these reserves. Permits have been obtained for some of these undeveloped reserves. We expect to obtain the required remaining permits by the time we commence mining these reserves, but we may be unable to do so at all or within the necessary time period. Some of the required permits have become increasingly more difficult and expensive to obtain and the application review processes are taking longer to complete and have been subject to more frequent challenges.

     Because of these uncertainties, the quantity and quality of the coal we are ultimately able to recover within our coal reserves may differ materially from our estimates. Inaccuracies in our estimates could result in revenue that is lower than we expect or operating costs that are higher than we expect.

     A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine our coal reserves or result in significant unanticipated costs.

     We conduct a significant part of our coal mining operations on properties that we lease. A title defect or the loss of a lease could adversely affect our ability to mine the associated coal reserves. We may not verify title to our leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or coal reserves that we intend to mine may contain defects prohibiting our ability to conduct mining operations. Similarly, our leasehold interests may be subject to superior property rights of other third parties. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and contain minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.

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

     We depend upon rail, truck and belt transportation systems to deliver coal to our customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair our ability to supply coal to our customers. As we do not have long-term contracts with transportation providers to ensure consistent and reliable service, decreased performance levels over longer periods of time could cause our customers to look to other sources for their coal needs. In addition, increases in transportation costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of the United States or abroad. If we experience disruptions in our transportation services or if transportation costs increase significantly and we are unable to find alternative transportation providers, our coal mining operations may be disrupted, we could experience a delay or halt of production or our profitability could decrease significantly.

     We may be unable to realize the benefits we expect to occur as a result of acquisitions that we undertake.

     We continually seek to expand our operations and coal reserves through acquisitions of other businesses and assets, including leasehold interests. Certain risks, including those listed below, could cause us not to realize the benefits we expect to occur as a result of those acquisitions:

	•		uncertainties in assessing the value, risks, profitability and liabilities (including environmental liabilities) associated with certain businesses or assets;
	•		the potential loss of key customers, management and employees of an acquired business;
	•		the possibility that operating and financial synergies expected to result from an acquisition do not develop;
	•		problems arising from the integration of an acquired business; and
	•		unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the rationale for a particular acquisition.

     Our profitability depends upon the long-term coal supply agreements we have with our customers. Changes in purchasing patterns in the coal industry could make it difficult for us to extend our existing long-term coal supply agreements or to enter into new agreements in the future.

     We sell a substantial portion of our coal under long-term coal supply agreements, which we define as contracts with a term greater than one year. Under these arrangements, we fix the prices of coal shipped during the initial year and may adjust the prices in later years. As a result, at any given time the market prices for similar-quality coal may exceed the prices for coal shipped under these arrangements. Changes in the coal industry may cause some of our customers not to renew, extend or enter into new long-term coal supply agreements with us or to enter into agreements to purchase fewer tons of coal than in the past or on different terms or prices. In addition, uncertainty caused by federal and state regulations, including the Clean Air Act, could deter our customers from entering into long-term coal supply agreements.

     Because we sell a substantial portion of our coal production under long-term coal supply agreements, our ability to capitalize on more favorable market prices may be limited. Conversely, at any given time we are subject to fluctuations in market prices for the quantities of coal that we have produced but which we have not committed to sell. As described above under “Our profitability and the value of our coal reserves depend upon coal demand by United States electric power generators and other factors beyond our control,” the market prices for coal may be volatile and may depend upon factors beyond our control. Our profitability may be

adversely affected if we are unable to sell uncommitted production at favorable prices or at all. For more information about our long-term coal supply agreements, you should see “Long-Term Coal Supply Arrangements” on page 9.

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

     For the year ended December 31, 2006, we derived approximately 32% of our total coal revenues from sales to our three largest customers, Tennessee Valley Authority, American Electric Power Company, Inc. and TUCO, Inc., and approximately 62% of our total coal revenues from sales to our ten largest customers. At December 31, 2006, we had coal supply agreements with those ten customers that expire at various times from 2007 to 2017. We expect to renew, extend or enter into new long-term coal supply agreements with those and other customers. However, we may be unsuccessful in obtaining long-term coal supply agreements with those customers, and those customers may discontinue purchasing coal from us. If any of those customers, particularly any of our three largest customers, was to significantly reduce the quantities of coal it purchases from us, or if we are unable to sell coal to those customers on terms as favorable to us as the terms under our current long-term coal supply agreements, our profitability could suffer significantly. We have limited protection during adverse economic conditions and may face economic penalties if we are unable to satisfy certain quality specifications under our long-term coal supply agreements.

     Our long-term coal supply agreements typically contain force majeure provisions allowing the parties to temporarily suspend performance during specified events beyond their control. Most of our long-term coal supply agreements also contain provisions requiring us to deliver coal that satisfies certain quality specifications, such as heat value, sulfur content, ash content, hardness and ash fusion temperature. These provisions in our long-term coal supply agreements could result in negative economic consequences to us, including price adjustments, purchasing replacement coal in a higher-priced open market, the rejection of deliveries or, in the extreme, contract termination. Our profitability may be negatively affected if we are unable to seek protection during adverse economic conditions or if we incur financial or other economic penalties as a result of these provisions of our long-term supply agreements.

     The amount of indebtedness we have incurred could significantly affect our business.

     At December 31, 2006, we had consolidated indebtedness of approximately $1.0 billion. We also have significant lease and royalty obligations. Our ability to satisfy our debt, lease and royalty obligations, and our ability to refinance our indebtedness, will depend upon our future operating performance. We may be unable to generate sufficient cash flow from operations and future borrowings or other financing may be unavailable in an amount sufficient to enable us to satisfy our financial obligations or our other liquidity needs. Our ability to satisfy our financial obligations may be adversely affected if we incur additional indebtedness in the future. In addition, the amount of indebtedness we have incurred could have significant consequences to our business, including those listed below:

	•		making it more difficult for us to satisfy our debt covenants and debt service, lease payment and other obligations;
	•		increasing our vulnerability to general adverse economic and industry conditions;
	•		limiting our ability to obtain additional financing to fund future acquisitions, working capital, capital expenditures or other general operating requirements;
	•		reducing the availability of cash flow from operations to fund acquisitions, working capital, capital expenditures or other general operating purposes;
	•		limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete; and
	•		placing us at a competitive disadvantage when compared to competitors with less relative amounts of debt.

     We may be unable to comply with restrictions imposed by our financing arrangements.

     The agreements governing our outstanding debt impose a number of restrictions on us. For example, the terms of our leases and other financing arrangements contain financial and other covenants that create limitations on our ability to effect acquisitions or dispositions and incur additional debt and require us to maintain various financial ratios and comply with various other financial covenants. Our ability to comply with these restrictions may be affected by events beyond our control and, as a result, we may be unable to comply with these restrictions. A failure to comply with these restrictions could result in an event of default under these agreements. In the event of a default, our lenders and the counterparties to our other financing arrangements could terminate their commitments to us and declare all amounts borrowed, together with accrued interest and fees, immediately due and payable. If this were to occur, we might not be able to pay these amounts, or we might be forced to seek an amendment to our financing arrangements which could make the terms of these arrangements more onerous for us.

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

•

Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations.

We generally reprice these bonds annually, however, they are not cancellable by the surety. Surety bond issuers and holders may increase premiums on the bonds or impose other less favorable terms upon those renewals. The ability of surety bond issuers and holders to demand additional collateral or other less favorable terms has increased as the number of companies willing to issue these bonds has decreased over time. Our failure to maintain, or our inability to acquire, surety bonds required by federal and state law could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.

     Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may adversely affect our business.

     Terrorist attacks and threats, escalation of military activity or acts of war have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may significantly affect our operations and those of our customers. As a result, we could experience delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal or extended collections from our customers.

Risks Related to Environmental and Other Regulations

     Federal and state regulations impose significant costs on us, and future regulations could increase those costs or limit our ability to produce and sell coal.

     Federal and state authorities regulate certain areas, including those listed below, that significantly affect the coal mining industry:

	•		the discharge of materials into the environment;
	•		employee health and safety;
	•		mine permitting and licensing requirements;
	•		reclamation and restoration of mining properties after mining is completed;
	•		management of materials generated by mining operations;
	•		surface subsidence from underground mining;
	•		water pollution;
	•		statutorily mandated benefits for current and retired coal miners;
	•		air quality standards;
	•		protection of wetlands;
	•		endangered plant and wildlife protection;
	•		limitations on land use;
	•		storage and disposal of petroleum products and substances that are regarded as hazardous under applicable laws; and
	•		management of electrical equipment containing PCBs.

     The costs, liabilities and requirements associated with these regulations may be significant and time-consuming and may delay commencement or continuation of exploration or production operations. Failure to comply with these regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our mining operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. Our profitability may be negatively affected if we incur significant costs and liabilities as a result of these regulations. You should see “Environmental Matters” beginning on page 10 for more information about the federal and state regulations affecting us.

     The possibility exists that new legislation and/or regulations and orders may be adopted that may adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. New legislation or administrative regulations (or new judicial interpretations or administrative enforcement of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. Such regulations, if enacted in the future, could have a material adverse effect on our business, financial condition and results of operations.

     Our failure to obtain and renew permits necessary for our mining operations could negatively affect our business.

     Mining companies must obtain numerous permits that regulate environmental and health and safety matters in connection with coal mining, including permits issued by various federal and state agencies and regulatory bodies. We believe that we have obtained the necessary permits to mine our developed reserves at our mining complexes. However, as we commence mining our undeveloped reserves, we will need to apply for and obtain the required permits. The permitting rules are complex and change frequently, making our ability to comply with the applicable requirements more difficult or even impossible. In addition, private individuals and the public at large have certain rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need for our mining operations may not be issued, or, if issued, may not be issued in a timely fashion. The permits may also involve requirements that may be changed or interpreted in a manner which restricts our ability to conduct our mining operations or to do so profitably. An inability to conduct our mining operations pursuant to applicable permits would reduce our production, cash flow and profitability.

     If the assumptions underlying our estimates of reclamation and mine closure obligations are inaccurate, our costs could be greater than anticipated.

     SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of underground mining. We base our estimates of reclamation and mine closure liabilities on permit requirements and our engineering expertise related to these requirements. Our management and engineers periodically review these estimates. The estimates can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, which we refer to as Statement No. 143, requires us to record these obligations as liabilities at fair value. If actual costs differ from our estimates of fair value, our profitability could be negatively affected.

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

     Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. We could become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share.

     We maintain coal refuse areas and slurry impoundments at some of our mining complexes. Slurry impoundments have been known to fail, releasing large volumes of coal slurry into the surrounding environment. 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. If one of our impoundments were to fail, we could be subject to claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.

     Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage,” which we refer to as AMD. The treating of AMD can be costly. Although we do not currently face material costs associated with AMD, it is possible that we could incur significant costs in the future.

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

Item 1B. Unresolved Staff Comments.

     None.

Item 2. Properties.

     At December 31, 2006, we owned or controlled primarily through long-term leases approximately 101,000 acres of coal land in Wyoming, 62,000 acres of coal land in Utah, 22,000 acres of coal land in New Mexico and 17,000 acres of coal land in Colorado. We sublease a significant portion of our coal land from Arch Coal. Arch Coal leases a portion of that property from the federal government or from various state governments. Those government leases are subject to readjustment and/or extension and to earlier termination for failure to meet diligent development requirements. Our Sufco, Medicine Bow and Seminoe II loadout facilities are located on properties subject to leases which expire at varying dates over the next 30 years. Most of the leases contain options to renew. Our remaining loadout facilities are located on property owned by Arch Coal or us or for which we have a special use permit.

     Our Reserves

     We estimate that we owned or controlled approximately 2.3 billion tons of proven and probable recoverable reserves at December 31, 2006. Recoverable reserves include only saleable coal and do not include coal which would remain unextracted, such as for support pillars, and processing losses, such as washery losses. Reserve estimates are prepared by our engineers and geologists and reviewed and updated periodically. Total recoverable reserve estimates and reserves dedicated to mines and complexes change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings and other factors.

     The following tables present by state our estimated assigned and unassigned recoverable coal reserves at December 31, 2006:

Total Assigned Reserves
(Tons in millions)

		Total
		Assigned												Sulfur Content
		Recoverable												(lbs. per million Btus)												As Received				Reserve Control								Mining Method								Past Reserve Estimates
		Reserves				Proven				Probable				<1.2				1.2-2.5				>2.5				Btu per lb. (1)				Leased				Owned				Surface				Under-ground				2004				2005
Wyoming			1,655				1,612				43				1,611				44				—				8,849				1,639				16				1,655				—				1,840				1,748
Utah			110				59				51				94				16				—				11,491				108				2				—				110				112				108
Colorado			67				52				15				67				—				—				11,767				65				2				—				67				80				74
Total			1,832				1,723				109				1,772				60				—				9,114				1,812				20				1,655				177				2,032				1,930

Total Unassigned Reserves
(Tons in millions)

		Total
		Unassigned												Sulfur Content
		Recoverable												(lbs. per million Btus)												As Received				Reserve Control								Mining Method
		Reserves				Proven				Probable				<1.2				1.2-2.5				>2.5				Btu per lb.(1)				Leased				Owned				Surface				Underground
Wyoming			368				255				113				321				47				—				9,591				277				91				193				175
Utah			41				17				24				36				5				—				10,939				40				1				—				41
Colorado			52				42				10				52				—				—				11,579				52				—				—				52
Total			461				314				147				409				52				—				9,935				369				92				193				268

     At December 31, 2006, approximately 4.9% of our coal reserves were held in fee, with the balance controlled by leases, most of which do not expire until the exhaustion of mineable and merchantable coal. Other leases have primary terms expiring in various years ranging from 2007 to 2020, and most contain options to renew for stated periods. Under current mining plans, substantially all reported leased reserves will be mined out within the period of existing leases or within the time period of assured lease renewals. Royalties are paid to lessors either as a fixed price per ton or as a percentage of the gross sales price of the mined coal. The majority of the significant leases are on a percentage royalty basis. In some cases, a payment is required, payable either at the time of execution of the lease or in annual installments. In most cases, the prepaid royalty amount is applied to reduce future production royalties.

     Federal and state legislation controlling air pollution affects the demand for certain types of coal by limiting the amount of sulfur dioxide which may be emitted as a result of fuel combustion and encourages a greater demand for low sulfur coal. All of our identified coal reserves have been subject to preliminary coal seam analysis to test sulfur content. Of these reserves, approximately 95.1% consist of compliance coal, or coal which emits 1.2 pounds or less of sulfur dioxide per million Btu upon combustion, while the balance could be sold as low-sulfur coal. Some of our low-sulfur coal can be marketed as compliance coal when blended with other compliance coal. Accordingly, most of our reserves are primarily suitable for the domestic steam coal markets.

     The carrying cost of our coal reserves at December 31, 2006 was $460.3 million, consisting of $7.4 million of prepaid royalties and the $452.9 million net book value of coal lands and mineral rights.

     Title to coal properties held by lessors or grantors to us and our subsidiaries and the boundaries of properties are normally verified at the time of leasing or acquisition. However, in cases involving less significant properties and consistent with industry practices, title and boundaries are not completely verified until such time as our independent operating subsidiaries prepare to mine such reserves. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to mine such reserves could be adversely affected.

     We must obtain permits from applicable state regulatory authorities before we begin to mine particular reserves. Applications for permits require extensive engineering and data analysis and presentation, and must address a variety of environmental, health and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction,

the storage, use and disposal of waste and other substances and other impacts on the environment, the construction of overburden fills and water containment areas, and reclamation of the area after coal extraction. We are required to post bonds to secure performance under our permits. As is typical in the coal industry, we strive to obtain mining permits within a time frame that allows us to mine reserves as planned on an uninterrupted basis. We generally begin preparing applications for permits for areas that we intend to mine up to three years in advance of their expected issuance date. Regulatory authorities have considerable discretion in the timing of permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

     Our reported coal reserves are those that could be economically and legally extracted or produced at the time of their determination. In determining whether our reserves meet this standard, we take into account, among other things, our potential inability to obtain a mining permit, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in costs required to be incurred to meet regulatory requirements and obtaining mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. We have obtained, or we have a high probability of obtaining, all required permits or government approvals with respect to our reserves. Except as described elsewhere in this document with respect to permits to conduct mining operations involving valley fills, which has been taken into account in determining our reserves, we are not currently aware of matters which would significantly hinder our ability to obtain future mining permits or governmental approvals with respect to our reserves.

     Arch Coal periodically engages third parties to review our reserve estimates. The most recent third-party review of our reserve estimates was conducted by Weir International Mining Consultants in February 2007.

Item 3. Legal Proceedings.

     You should see “Contingencies” on page 29 for more information.

Item 4. Submission of Matters to a Vote of Security Holders.

     Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

     There is no market for our common equity.

Item 6. Selected Financial Data.

		Year Ended December 31
		2006				2005				2004				2003				2002
		(1)				(1) (2)				(3)				(4)
						(Amounts in thousands, except per ton data)
Statement of Operations Data:
Coal sales revenue		$	1,491,362			$	1,126,742			$	735,162			$	500,555			$	492,191
Income from operations			314,263				186,061				83,275				62,710				49,824
Income before cumulative effect of accounting change			287,013				128,844				32,946				20,996				19,909
Cumulative effect of accounting change			—				—				—				(18,278	)			—
Net income			287,013				128,844				32,946				2,718				19,909
Balance Sheet Data:
Cash and cash equivalents		$	186			$	152			$	1,351			$	35,171			$	249
Receivable from Arch Coal, Inc.			1,152,102				869,056				677,934				351,866				333,825
Total assets			2,557,772				2,215,376				2,013,436				1,411,515				1,373,061
Total debt			958,881				960,247				961,613				700,000				675,000
Redeemable membership interests			6,934				5,647				4,971				4,746				4,733
Non-redeemable membership interests			934,545				677,795				543,058				471,890				469,241
Cash Flow Data:
Cash provided by operating activities		$	539,666			$	225,798			$	115,302			$	129,045			$	138,827
Depreciation, depletion and amortization			108,272				98,347				80,703				63,053				69,388
Capital expenditures			260,368				108,600				78,313				27,322				51,360
Operating Data:
Tons sold			113,759				105,796				86,264				69,541				72,519
Tons produced			114,928				106,554				91,466				69,361				73,203
Average sales price per ton		$	13.11			$	10.65			$	8.52			$	7.20			$	6.79

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

     Overview

     Our two reportable business segments are based on the low-sulfur coal producing regions in the western United States in which we operate – the Powder River Basin and the Western Bituminous region. These geographically distinct areas are characterized by geology, coal transportation routes to consumers, regulatory environments and coal quality. These similarities within a region have caused market and contract pricing environments to develop by coal region and form the basis for the segmentation of our operations.

     Our results for 2006 reflect higher margins driven primarily by increased price realization. We achieved those results despite continued rail challenges and weak near-term market conditions. In 2005, we experienced significant disruptions in our rail service from major repair and maintenance work in the Powder River Basin. During 2006, we experienced some shipment disruptions due to ongoing repairs and maintenance on the rail lines, although not of the magnitude experienced in 2005. Our results for 2006 also reflected production at our Coal Creek surface mine in Wyoming, which restarted production in 2006, and Skyline longwall mine in Utah, which commenced mining in a new reserve area in 2006.

     Across both of our segments, we have committed to sell a large percentage of our coal under sales contracts that we signed in periods when market prices of coal were lower than current market prices. Beginning in 2006 and continuing over the course of the next several years, many of these commitments will expire, and we expect to reprice future coal production at more favorable prices. Abnormal weather patterns, better than expected performance by competing fuels, increased coal production and an increase in utilities’ coal stockpiles during 2006 resulted in lower consumption by electric power generation facilities. Nevertheless, we believe domestic and global demand growth for coal along with supply pressures will cause coal prices to increase. In addition, we expect demand growth from new domestic coal-fueled capacity will also influence future coal consumption and coal prices.

     We expect public interest in domestic energy security to accelerate the adoption of coal conversion and other clean-coal technologies. We anticipate that growing legislative support for reducing the geopolitical risks associated with United States oil supplies will cause alternative fuel sources, including liquid fuels generated from coal, to become more significant. We believe that advancement of these technologies represents a positive development for the long-term outlook for coal demand.

     Items Affecting Comparability of Reported Results

     The comparison of our operating results for the years ended December 31, 2006, 2005 and 2004 is affected by the following significant items:

     Peabody reserve swap and asset sale – On December 30, 2005, we sold a rail spur, rail loadout and an idle office complex located in the Powder River Basin to Peabody Energy Corp. for a purchase price of $79.6 million. In conjunction with the transactions, we agreed to lease the rail spur and loadout and office facilities through 2008. We recognized a gain of $43.3 million on the transaction, after the deferral of $7.0 million of the gain, equal to the present value of the lease payments, which will be recognized over the term of the lease.

     West Elk combustion event – The combustion-related event at our West Elk mine in Colorado in October 2005 caused the idling of the mine into the first quarter of 2006. We estimate that the idling resulted in $30.0 million in lost profits during the first quarter of 2006, in addition to the effect of the idling and fire-fighting costs incurred during the fourth quarter of 2005 of $33.3 million. We recognized insurance recoveries related to the event of $41.9 million during the year ended December 31, 2006. We have reflected these insurance recoveries as a reduction of our cost of coal sales for the year ended December 31, 2006. We do not expect to recover any significant additional amounts as a result of this event.

     Accounting for pit inventory – On January 1, 2006, we adopted the provisions of Emerging Issues Task Force Issue No. 04-6, Accounting for Stripping Costs in the Mining Industry. This issue applies to stripping costs incurred in the production phase of a mine for the removal of overburden or waste materials for the purpose of obtaining access to coal that will be extracted. Under the issue, stripping costs incurred during the production phase of the mine are variable production costs that are included in the cost of

inventory produced and extracted during the period the stripping costs are incurred. Historically, we recorded stripping costs associated with the tons of coal uncovered and not yet extracted (pit inventory) at our surface mining operations as coal inventory. The cumulative effect of adoption was to reduce inventory by $37.6 million and deferred development cost by $2.0 million with a corresponding decrease to retained earnings. This accounting change creates volatility in our results of operations, as cost increases or decreases related to fluctuations in pit inventory can only be attributed to tons extracted from the pit. Due to decreases in pit inventory, net income was $11.8 million higher during the year ended December 31, 2006 than it would have been under our previous methodology of accounting for pit inventory.

     Contribution of North Rochelle Mine– On August 20, 2004, Arch Coal acquired (1) Vulcan Coal Holdings, L.L.C., which owned all of the common equity of Triton Coal Company, LLC, and (2) all of the preferred units of Triton for a purchase price of $382.1 million, including transaction costs and working capital adjustments. Upon acquisition, Arch Coal contributed the assets and liabilities of Triton’s North Rochelle mine to us. We integrated the North Rochelle mine into our existing Black Thunder mine in the Powder River Basin.

     Acquisition of remaining interests of Canyon Fuel – On July 31, 2004, Arch Coal purchased the remaining 35% interest in Canyon Fuel that we did not previously own from ITOCHU Corporation. We have consolidated Canyon Fuel in our financial statements since the acquisition. The results of operations of the Canyon Fuel mines are included in our Western Bituminous segment.

     Results of Operations

     Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

     The following discussion summarizes our operating results for the year ended December 31, 2006 and compares those results to our operating results for the year ended December 31, 2005.

     Revenues. The following table summarizes information about coal sales during the year ended December 31, 2006 and compares those results to the comparable information for the year ended December 31, 2005:

		Year Ended December 31								Increase
		2006				2005				$				%
		(Amounts in thousands, except per ton data)
Coal sales		$	1,491,362			$	1,126,742			$	364,620				32.4	%
Tons sold			113,759				105,796				7,963				7.5
Coal sales realization per ton sold		$	13.11			$	10.65			$	2.46				23.1	%

     Coal sales increased during 2006 when compared to 2005 due to higher contract prices in both of our segments and higher volumes in our Powder River Basin segment. We have provided more information about the tons sold and the coal sales prices per ton by operating segment below.

     The following table shows the number of tons sold by operating segment during the year ended December 31, 2006 and compares those amounts to the comparable information for the year ended December 31, 2005:

		Tons Sold								Increase (Decrease)
		2006				2005				Tons				%
						(Amounts in thousands)
Powder River Basin			95,637				87,597				8,040				9.2	%
Western Bituminous			18,122				18,199				(77	)			(0.4	)
Total			113,759				105,796				7,963				7.5	%

     Sales volume increased in the Powder River Basin as a result of the restart of the Coal Creek mine in the second quarter of 2006 and rail service that improved during 2006 when compared to 2005. In the Western Bituminous region, the effect of an extended longwall move at the Dugout Canyon mine offset a portion of the 1.5 million tons sold from our Skyline mine, which commenced production in a new reserve area in the second quarter of 2006.

     The following table shows the coal sales price per ton by operating segment during the year ended December 31, 2006 and compares those amounts to the comparable information for the year ended December 31, 2005. Coal sales prices per ton exclude certain transportation costs that we pass through to our customers. We use these financial measures because we believe the amounts as adjusted better represent the coal sales prices we achieved within our operating segments. Since other companies may calculate coal sales prices per ton differently, our calculation may not be comparable to similarly titled measures used by those companies. For the year ended December 31, 2006, transportation costs per ton billed to customers were $0.02 for the Powder River Basin and $2.91 for the Western Bituminous region. Transportation costs per ton billed to customers for the year ended December 31, 2005 were $0.07 for the Powder River Basin and $3.10 for the Western Bituminous region.

		Year Ended December 31								Increase
		2006				2005				$				%
Powder River Basin		$	10.78			$	8.20			$	2.58				31.5	%
Western Bituminous			22.42				19.01				3.41				17.9

     The increase in our coal sales prices in 2006 resulted from higher contract pricing in both of our segments when compared to 2005, due primarily to the expiration of lower-priced legacy contracts. As discussed previously, we continue to replace sales contracts that we signed in periods when market prices of coal were lower than current market prices.

     Expenses, costs and other. The following table summarizes expenses, costs and other operating income for the year ended December 31, 2006 and compares those results to the comparable information for the year ended December 31, 2005:

										Increase (Decrease)
		Year Ended December 31								in Net Income
		2006				2005				$				%
						(Amounts in thousands)
Cost of coal sales		$	1,049,429			$	865,760			$	(183,669	)			(21.2	)%
Depreciation, depletion and amortization			108,272				98,347				(9,925	)			(10.1	)
Selling, general and administrative expenses			23,466				23,958				492				2.1
Gain on sale of Powder River Basin assets			—				(43,297	)			(43,297	)			(100.0	)
Other operating income			(4,068	)			(4,087	)			(19	)			(0.5	)
Total		$	1,177,099			$	940,681			$	(236,418	)			(25.1	)%

     Cost of coal sales. Our cost of coal sales increased from 2005 to 2006 primarily due to increased sales volume in the Powder River Basin, and higher costs, primarily production taxes and coal royalties, which we pay as a percentage of coal sales. We have provided more information about our operating margins by segment below.

     Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization from 2005 to 2006 is due primarily to capital improvements associated with development projects. We have provided additional information concerning our capital spending during 2006 in the section entitled “Liquidity and Capital Resources” beginning on page 27.

     Selling, general and administrative expenses. Selling, general and administrative expenses represent expenses allocated to us from Arch Coal.

     Gain on sale. You should see “Items Affecting Comparability of Reported Results” beginning on page 23 for more information about the gain on the sale of our Powder River Basin assets.

     Operating margins. Our operating margins (reflected below on a per-ton basis) include all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs discussed in “Revenues” above) and all depreciation, depletion and amortization attributable to mining operations.

		Year Ended December 31								Increase
		2006				2005				$				%
Powder River Basin		$	2.22			$	1.19			$	1.03				86.6	%
Western Bituminous			6.87				3.27				3.60				110.1
Powder River Basin — On a per-ton basis, operating margins in 2006 increased significantly from 2005 primarily due to the increase in per-ton coal sales realizations discussed previously. The effect of the higher realizations were partially offset by increased production taxes and coal royalties, which we pay as a percentage of coal sales realizations, higher repair and maintenance activity and higher diesel, tire and explosives costs during 2006 compared to 2005.
Western Bituminous — Operating margins per ton in 2006 increased from 2005 primarily due to higher per ton sales prices and insurance recoveries related to the West Elk thermal event of $41.9 million, partially offset by higher costs resulting from an extended longwall move at our Dugout Canyon mine, higher coal royalties and production taxes, which we pay as a percentage of sales, and higher repair and supplies costs.
Net interest expense. The following table summarizes our net interest expense for the year ended December 31, 2006 and compares that information to the comparable information for the year ended December 31, 2005:
										Increase (Decrease)
		Year Ended December 31								in Net Income
		2006				2005				$				%
						(Amounts in thousands)
Interest expense		$	(72,273	)		$	(65,543	)		$	(6,730	)			(10.3	)%
Interest income			81,853				45,233				36,620				81.0
Total		$	9,580			$	(20,310	)		$	29,890				147.2	%

     The increase in interest expense in 2006 compared to 2005 results from the discount on trade accounts receivable sold to Arch Coal under Arch Coal’s accounts receivable securitization program. See further discussion about this program in the section entitled “Liquidity and Capital Resources” beginning on page 27.

     Arch Coal manages our cash transactions. Cash paid to or from us that is not considered a distribution or a contribution is recorded in an Arch Coal receivable account. The receivable earns interest at the prime rate. The increase in interest income on the

receivable from Arch Coal results from a higher average receivable balance in 2006 as compared to 2005, including the effect of amounts related to the sale of trade accounts receivable to Arch Coal.

     Other non-operating expense. Our non-operating expense is related to the termination of hedge accounting on interest rate swaps and the resulting amortization of amounts that had previously been deferred.

     Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

     Revenues. The following table summarizes information about coal sales during the year ended December 31, 2005 and compares those results to the comparable information for the year ended December 31, 2004:

		Year Ended December 31								Increase (Decrease)
		2005				2004				$				%
		(Amounts in thousands, except per ton data)
Coal sales		$	1,126,742			$	735,162			$	391,580				53.3	%
Tons sold			105,796				86,264				19,532				22.6
Coal sales realization per ton sold		$	10.65			$	8.52			$	2.13				25.0	%

     Coal sales. The increase in our coal sales resulted from a combination of increased volumes in both segments and higher pricing. Our per ton realizations increased due primarily to higher contract prices in both segments.

     The following table shows the number of tons sold by operating segment during the year ended December 31, 2005 and compares those amounts to the comparable information for the year ended December 31, 2004:

		Tons Sold								Increase
		2005				2004				Tons				%
						(Amounts in thousands)
Powder River Basin			87,597				75,069				12,528				16.7	%
Western Bituminous			18,199				11,195				7,004				62.6
Total			105,796				86,264				19,532				22.6	%

     In 2005, volumes increased as a result of the contribution of the North Rochelle mine in the Powder River Basin by Arch Coal on August 20, 2004 and the consolidation of Canyon Fuel in the Western Bituminous region beginning on July 31, 2004, as discussed previously. In addition, both operating segments benefited from an overall increase in demand,

     The following table shows the coal sales price per ton by operating segment during the year ended December 31, 2005 and compares those amounts to the comparable information for the year ended December 31, 2004. Coal sales prices per ton exclude certain transportation costs that we pass through to our customers. We use these financial measures because we believe the amounts as adjusted better represent the coal sales prices we achieved within our operating segments. As other companies may calculate coal sales prices per ton differently, our calculation may not be comparable to similarly titled measures used by those companies. Transportation costs per ton billed to customers for the year ended December 31, 2005 were $0.07 for the Powder River Basin and $3.10 for the Western Bituminous region. For the year ended December 31, 2004, transportation costs per ton billed to customers were $0.04 for the Powder River Basin and $2.12 for the Western Bituminous region.

		Year Ended December 31								Increase
		2005				2004				$				%
Powder River Basin		$	8.20			$	7.11			$	1.09				15.3	%
Western Bituminous			19.01				15.67				3.34				21.3

     In the Powder River Basin, our coal sales prices increased due to higher base pricing and above-market pricing on certain contracts acquired with the contribution of the North Rochelle mine, as well as higher sulfur dioxide quality premiums resulting from an increase in sulfur dioxide emission allowance prices. The Western Bituminous region’s coal sales prices increased due to higher contract pricing.

     Expenses, costs and other. The following table summarizes expenses, costs and other operating income for the year ended December 31, 2005 and compares those results to the comparable information for the year ended December 31, 2004:

										Increase (Decrease)
		Year Ended December 31								in Net Income
		2005				2004				$				%
						(Amounts in thousands)
Cost of coal sales		$	865,760			$	577,660			$	(288,100	)			(49.9	)%
Depreciation, depletion and amortization			98,347				80,703				(17,644	)			(21.9	)
Selling, general and administrative expenses			23,958				17,168				(6,790	)			(39.6	)
Gain on sale of Powder River Basin assets			(43,297	)			—				43,297				100.0
Other operating income			(4,087	)			(23,644	)			(19,557	)			(82.7	)
Total		$	940,681			$	651,887			$	(288,794	)			(44.3	)%

     Cost of coal sales. The increase in our cost of coal sales resulted from a combination of increased volumes and the contribution of the North Rochelle mine in the Powder River Basin by Arch Coal on August 20, 2004 and the consolidation of Canyon Fuel in the Western Bituminous region beginning on July 31, 2004, as discussed previously, along with an increase in sales-sensitive taxes

and royalties and higher diesel fuel, explosives and utilities costs.

     Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization is due primarily to the property additions resulting from the acquisitions during the third quarter of 2004 and to higher capital expenditures during 2005.

     Selling, general and administrative expenses. Selling, general and administrative expenses represent expenses allocated to us from Arch Coal.

     Gain on sale. You should see “Items Affecting Comparability of Reported Results” beginning on page 23 for more information about the gain on the sale of our Powder River Basin assets.

     Other operating income, net. The decrease in other operating income in 2005 compared to 2004 is due to the decrease in income from investments accounted for under the equity method of $8.4 million and production and administration payments from Canyon Fuel, which ended with the consolidation of Canyon Fuel beginning in July, 2004, and a decrease in gains on other asset sales of $5.8 million in 2005 compared to 2004.

     Operating margins. Our operating margins (reflected below on a per-ton basis) include all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs discussed in “Revenues” above) and all depreciation, depletion and amortization attributable to mining operations.

		Year Ended December 31								Increase
		2005				2004				$				%
Powder River Basin		$	1.19			$	0.99			$	0.20				20.2	%
Western Bituminous			3.27				0.76				2.51				330.2
Powder River Basin — On a per-ton basis, higher coal sales prices in the Powder River Basin were partially offset by higher operating costs, primarily due to higher production taxes and coal royalties, diesel fuel costs, depreciation, depletion and amortization costs and higher repairs and maintenance costs. Additionally, average costs were higher due to the integration of the North Rochelle mine into our Black Thunder mine in the third quarter of 2004. These costs would have been largely offset by increased productivity had rail service not adversely impacted volumes during the year.
Western Bituminous — On a per-ton basis, higher coal sales prices were partially offset by the effect of the West Elk thermal event discussed under “Items Affecting Comparability of Reported Results” beginning on page 23.
Net interest expense. The following table summarizes our net interest expense for the year ended December 31, 2005 and compares that information to the comparable information for the year ended December 31, 2004:
										Increase (Decrease)
		Year Ended December 31								in Net Income
		2005				2004				$				%
						(Amounts in thousands)
Interest expense		$	(65,543	)		$	(55,582	)		$	(9,961	)			(17.9	)%
Interest income			45,233				20,570				24,663				119.9
Total		$	(20,310	)		$	(35,012	)		$	14,702				42.0	%

     The increase in interest expense results from a higher amount of average borrowings in 2005 as compared to the same period in 2004, primarily due to the issuance of $250.0 million of 6³/4% senior notes in October 2004. The increase in interest income resulted from an increase in the receivable from Arch Coal.

     Other non-operating expense. Our non-operating expense is related to the termination of hedge accounting on interest rate swaps and the resulting amortization of amounts that had previously been deferred.

     Liquidity and Capital Resources

     Our primary sources of cash include sales of our coal production to customers, sales of assets and debt and offerings related to significant transactions. Excluding any significant mineral reserve acquisitions, we generally satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations and, if necessary, cash from Arch Coal. Our ability to satisfy debt service obligations, to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control.

     The following is a summary of cash provided by or used in each of the indicated types of activities during the past three years:

		Year Ended December 31
		2006				2005				2004
		(Amounts in thousands)
Cash provided by (used in):
Operating activities		$	539,666			$	225,798			$	115,302
Investing activities			(539,617	)			(226,932	)			(405,663	)
Financing activities			(15	)			(65	)			256,541

     Cash provided by operating activities increased $313.9 million in 2006 compared to 2005 primarily as a result of an increase in net income and the sale of our trade accounts receivable to Arch Coal.

     On February 10, 2006, Arch Coal established an accounts receivable securitization program. Under the program, we sell our receivables to Arch Coal without recourse at a discount based on the prime rate and days sales outstanding. During 2006, we sold $1.5 billion of trade accounts receivable to Arch Coal, at a total discount of $10.5 million.

     The increase in cash provided by operating activities in 2005 compared to 2004 resulted from improved operating results, the inclusion of a full year of results for the North Rochelle assets contributed by Arch Coal on August 20, 2004 and the consolidation of Canyon Fuel beginning July 31, 2004.

     We used $312.7 million more cash in investing activities in 2006 than in 2005, due to increased capital expenditures and a decrease of $81.5 million in proceeds from dispositions of property, plant and equipment. Higher spending at our Powder River Basin operations related to the restart of the Coal Creek mine and costs related to the purchase of a replacement longwall at the Canyon Fuel operations in the Western Bituminous region resulted in an increase in capital expenditures in 2006 compared to the prior year period. The decrease in proceeds is a result of the sale in 2005 of the railspur, rail loadout and idle office complex in the Powder River Basin described in “Items Affecting Comparability of Reported Results,” beginning on page 23.

     We make capital expenditures to improve and replace existing mining equipment, expand existing mines, develop new mines and improve the overall efficiency of mining operations. We anticipate that capital expenditures during 2007 will be between approximately $125 million and $145 million. This estimate includes work on a new loadout at Black Thunder, and the final expenditures for a new longwall at the Sufco mine. This estimate assumes no other acquisitions, significant expansions of our existing mining operations or additions to our reserve base. We anticipate that we will fund these capital expenditures with available cash, existing credit facilities and cash generated from operations.

     Cash used in investing activities decreased $178.7 million during 2005 compared to 2004 as a result of the sale of the rail spur, rail loadout and idle office complex, which resulted in proceeds of $79.6 million. In addition, the receivable from Arch Coal increased $318.8 million in 2004 compared to $187.3 million in 2005, due to the proceeds from borrowings in 2004 being loaned to Arch Coal. The decrease was partially offset by increased capital spending as a result of the addition of the North Rochelle mining operations and the consolidation of Canyon Fuel.

     Cash provided by financing activities in 2004 was $256.4 million. On August 20, 2004, we borrowed $100.0 million under a term loan facility, which was loaned to Arch Coal to help finance the Triton acquisition. On October 22, 2004, we issued $250 million of 6³/4% senior notes due 2013 at a price of 104.75% of par. The net proceeds of the offering were used to repay and retire the $100.0 million term loan, to repay indebtedness under our revolving credit facility and for general corporate purposes.

     Contractual Obligations

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

		Payments Due by Period
		2007				2008-2009				2010-2011				After 2011				Total
						(Amounts in thousands)
Long-term debt		$	—			$	—			$	—			$	958,881			$	958,881
Operating leases			23,401				40,939				33,731				11,220				109,291
Royalty leases			5,031				6,110				3,086				8,590				22,817
Unconditional purchase obligations			162,051				—				—				—				162,051
Total contractual obligations		$	190,483			$	47,049			$	36,817			$	978,691			$	1,253,040

     Long-term debt is reflected at the amount on our consolidated balance sheet. Certain of our 6³/4% senior notes due 2013 were issued at a premium. The par value of our long-term debt is $950.0 million.

     Royalty leases represent non-cancelable royalty lease agreements. Unconditional purchase obligations represent amounts committed for purchases of materials and supplies, payments for services, purchased coal, and capital expenditures.

     Our consolidated balance sheet reflects a liability of $182.0 million for the fair value of asset retirement obligations that arise from SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The determination of the fair value of asset retirement obligations involves a number of estimates, as discussed in the section entitled “Critical Accounting Policies” beginning on page 29, including the timing of payments to satisfy asset retirement obligations. The timing of payments to satisfy asset retirement obligations is based on numerous factors, including mine closure dates. You should see the notes to our consolidated financial statements for more information about our asset retirement obligations.

     The contractual obligations table included above also excludes certain other obligations reflected in our consolidated balance sheet, including an allocated portion of liabilities under Arch Coal’s pension and postretirement benefit plans and obligations under our self-insured workers’ compensation program. We are not obligated to make contributions to Arch Coal’s plans, but we are charged for an allocated portion of Arch Coal’s contributions. The timing of payments may vary based on changes in the fair value of the plan’s assets (for pension obligations) and actuarial assumptions, and benefit payments. See the section entitled “Critical Accounting Policies” for more information about these assumptions. See Notes 13 and 14 to our consolidated financial statements for more informaton about the amounts we have recorded for workers’ compensation and pension and postretirement benefit obligations.

     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, financial instruments with off-balance sheet risk, such as performance or

surety bonds. Liabilities related to these arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

     We use a combination of surety bonds and corporate guarantees (e.g., self bonds) to secure our financial obligations for reclamation, workers’ compensation, coal lease obligations and other obligations as follows as of December 31, 2006:

										Workers’
		Reclamation				Lease				Compensation
		Obligations				Obligations				Obligations				Other				Total
						(Amounts in thousands)
Self bonding		$	265,222			$	—			$	—			$	—			$	265,222
Surety bonds			71,120				23,097				100				5,100				99,417

     Contingencies

     SMCRA and similar state statutes require that mine property be restored in accordance with specified standards and an approved reclamation plan. We accrue for the costs of reclamation in accordance with the provisions of Statement No. 143. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at underground mines. Other costs of reclamation common to surface and underground mining are related to reclaiming refuse and slurry ponds, eliminating sedimentation and drainage control structures, and dismantling or demolishing equipment or buildings used in mining operations. The establishment of the asset retirement obligation liability is based upon permit requirements and requires various estimates and assumptions, principally associated with costs and productivities.

     We review our entire environmental liability periodically and make necessary adjustments, including permit changes and revisions to costs and productivities, to reflect current experience. Our management believes it is making adequate provisions for all expected reclamation and other associated costs.

     We are a party to numerous claims and lawsuits and are subject to numerous other contingencies with respect to various matters. We provide for costs related to contingencies, including environmental, legal and indemnification matters, when a loss is probable and the amount is reasonably determinable. After conferring with counsel, it is the opinion of management that the ultimate resolution of these claims, to the extent not previously provided for, will not have a material adverse effect on our consolidated financial condition, results of operations or liquidity.

     Critical Accounting Policies

     We prepare our financial statements 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 amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Additionally, these estimates and judgments are discussed with our audit committee on a periodic basis. Actual results may differ from the estimates used under different assumptions or conditions. We have provided a description of all significant accounting policies in the notes to our consolidated financial statements. 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 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. Our asset retirement obligations are initially recorded at fair value, or the amount at which the obligations could be settled in a current transaction between willing parties. This involves determining the present value of estimated future cash flows on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage and reclamation costs and assumptions regarding productivity. We estimate disturbed acreage based on approved mining plans and related engineering data. Since we plan to use internal resources to perform reclamation activities, our estimate of reclamation costs involves estimating third-party profit margins, which we base on our historical experience with contractors that perform certain types of reclamation activities. We base productivity assumptions on historical experience with the equipment that we expect to utilize in the reclamation activities. In order to determine fair value, we must also discount our estimates of cash flows to their present value. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.

     On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the actual cost of reclamation and the fair value will be recorded as a gain or loss when the obligation is settled. We expect our actual cost to reclaim our properties will be less than the amount

reflected as an asset retirement obligation. At December 31, 2006, we had recorded asset retirement obligation liabilities of $182.0 million, including amounts classified as a current liability. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2006, we estimate that the aggregate undiscounted cost of final mine closure is approximately $465.3 million.

     Related Party Transactions

     We receive certain services from, and have entered into certain transactions with, Arch Coal. These include Arch Coal’s management of our cash transactions, accounts receivable securitization and coal land lease transactions. In addition, certain costs are controlled at Arch Coal and allocated to us, including employee benefit plan costs and selling, general and administrative costs. These transactions are discussed in “Certain Relationships and Related Transactions, and Director Independence” beginning on page 32. Transactions with Arch Coal may not be at arms length and cost allocations require the use of estimates. If such transactions were negotiated with an unrelated party, the impact could be material to our results of operations.

     Employee Benefit Plans

     We participate in Arch Coal’s non-contributory defined benefit pension plans covering certain of our salaried and non-union hourly employees. Benefits are generally based on the employee’s age and compensation. Arch Coal allocates the net periodic benefit cost and benefit obligation based on participant information. The calculation of our net periodic benefit costs (expense) and benefit obligation (liability) associated with Arch Coal’s defined benefit pension plans requires the use of a number of assumptions that we deem to be “critical accounting estimates.” These assumptions include the long term rate of return on plan assets and the discount rate, representing the interest rate at which pension benefits could be effectively settled. Changes in these assumptions can result in different pension expense and liability amounts, and actual experience can differ from the assumptions. Arch Coal reports separately on the assumptions used in the determination of net periodic benefit costs and benefit obligation associated with its defined benefit plans.

     We also provide certain postretirement medical/life insurance coverage for eligible employee’s under Arch Coal’s plans. Generally, covered employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The salaried employee postretirement medical/life plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. Arch Coal allocates the net postretirement benefit cost and benefit obligation based on participant information. The calculation of our net postretirement benefit costs (expense) and benefit obligation (liability) associated with Arch Coal’s postretirement benefit plans requires the use of assumptions that we deem to be “critical accounting estimates,” primarily the discount rate. Because postretirement costs for participants are capped at current levels, future changes in health care costs have no future effect on the plan benefits. Arch Coal reports separately on the assumptions used in the determination of net periodic benefit costs and benefit obligation associated with its postretirement plans.

     The impact of lowering the expected long-term rate of return on pension plan assets 0.5% in 2006 would have been an increase in expense of approximately $0.5 million. The impact of lowering the discount rate 0.5% in 2006 would have been an increase in net periodic pension and postretirement costs of approximately $1.1 million.

     Accounting Standards Issued and Not Yet Adopted

     In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements, which we refer to as Statement No. 157. Statement No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Statement No. 157 applies under other accounting pronouncements that require or permit fair value measurements. Statement No. 157 is effective prospectively for fiscal years beginning after November 15, 2007, and interim periods within that fiscal year. We are still analyzing Statement No. 157 to determine what the impact of adoption will be.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

     We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements, rather than through the use of derivative instruments. The majority of our tonnage is sold under long-term contracts. We are also exposed to price risk related to the value of sulfur dioxide emission allowances that are a component of quality adjustment provisions in many of our coal supply contracts. We manage this risk through the use of long-term coal supply agreements. In addition, Arch Coal may enter into derivative instruments that fix the price we ultimately realize related to sulfur dioxide emission allowances.

     We are also exposed to the risk of fluctuations in cash flows related to our purchase of diesel fuel. Arch Coal enters into forward physical purchase contracts and heating oil swaps and options to reduce volatility in the price of diesel fuel for our operations. The swap agreements essentially fix the price paid for diesel fuel by requiring us to pay a fixed heating oil price and receive a floating heating oil price. The call options protect against increases in diesel fuel by granting us the right to participate in increases in heating oil prices. The changes in the floating heating oil price highly correlate to changes in diesel fuel prices.

     We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At December 31, 2006, all of our outstanding debt bore interest at fixed rates. In the past, we have utilized interest rate swap agreements to modify the interest characteristics of our floating-rate debt. We had no swaps outstanding as of December 31, 2006.

Item 8. Financial Statements and Supplementary Data.

     The consolidated financial statements and consolidated financial statement schedule of Arch Western Resources, LLC and subsidiaries are included in this Annual Report on Form 10-K beginning on page F-1.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

     None.

Item 9A. Controls and Procedures.

     We performed an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2006. Based on that evaluation, our management, including our chief executive officer and chief financial officer, concluded that the disclosure controls and procedures were effective as of such date. There were no changes in internal control over financial reporting that occurred during our fiscal quarter ended December 31, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

     None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

     Our managing member is an indirect, wholly-owned subsidiary of Arch Coal. As a result, we are effectively managed by the management of Arch Coal. You should see the list of Arch Coal’s executive officers and related information under “Executive Officers” beginning on page 14.

     The following is a list of directors of Arch Coal, other than Messrs. Eaves and Leer, whose biographical information is contained under “Executive Officers” beginning on page 14, their ages on March 26, 2007 and biographical information:

     James R. Boyd, 60, has been a director of Arch Coal since 1990. Mr. Boyd served as chairman of the board of directors from 1998 to April 2006, when he was appointed lead director. He served as Senior Vice President and Group Operating Officer of Ashland Inc., a multi-industry company with operations in chemicals, motor oil, car care products and highway construction, from 1989 until his retirement in January 2002. Mr. Boyd is also a director of Farmers Bancorp of Lynchburg, Tennessee and Halliburton Inc.

     Frank M. Burke, 67, has been a director of Arch Coal since September 2000. He has served as Chairman, Chief Executive Officer and Managing General Partner of Burke, Mayborn Company, Ltd., a private investment and consulting company since 1984. Mr. Burke is also a director of Crosstex Energy GP, LLC (general partner of Crosstex Energy, L.P.), Crosstex Energy, Inc. and Corrigan Investments, Inc., and is a member of the National Petroleum Council.

     Patricia F. Godley, 58, has been a director of Arch Coal since 2004. Since 1998, Ms. Godley has been a partner with the law firm of Van Ness Feldman in Washington, D.C., practicing in the areas of economic and environmental regulation of electric utilities and natural gas companies. From 1994 until 1998, Ms. Godley served as the Assistant Secretary for Fossil Energy at the U.S. Department of Energy. Ms. Godley is also a director of the United States Energy Association.

     Douglas H. Hunt, 54, has been a director of Arch Coal since 1995 and, since May 1995, has served as Director of Acquisitions of Petro-Hunt, LLC, a private oil and gas exploration and production company.

     Brian J. Jennings, 46, has been a director of Arch Coal since July 2006. From March 2004 to December 2006, Mr. Jennings served as Senior Vice President – Corporate Finance and Development and Chief Financial Officer of Devon Energy Corporation. Mr. Jennings served as Senior Vice President – Corporate Finance and Development from 2001 to March 2004. Mr. Jennings joined Devon in March 2000 as Vice President – Corporate Finance.

     Thomas A. Lockhart, 71, has been a director of Arch Coal since February 2003 and a member of the Wyoming State House of Representatives since 2000. Mr. Lockhart worked for PacifiCorp, an electric utility, for over 30 years and retired in 1998 as a Vice President. Mr. Lockhart is also a director of First Interstate Bank of Casper, Wyoming and Blue Cross Blue Shield of Wyoming.

     A. Michael Perry, 70, has been a director of Arch Coal since 1998. He served as Chairman of Bank One, West Virginia, N.A. from 1993 and as its Chief Executive Officer from 1983 to his retirement in June 2001. Mr. Perry is also a director of Champion Industries, Inc., and Portec Rail Products, Inc.

     Robert G. Potter, 67, has been a director of Arch Coal since April 2001. Mr. Potter was Chairman and Chief Executive Officer of Solutia Inc., a producer and marketer of a variety of high performance chemical-based materials, from 1997 to his retirement in 1999. Mr. Potter served for 32 years with Monsanto Company prior to its spin-off of Solutia in 1997, most recently as the Chief Executive of its chemical businesses. Mr. Potter is a private investor and director of Stepan Company.

     Theodore D. Sands, 61, has been a director of Arch Coal since 1999 and, since February 1999, has served as President of HAAS Capital, LLC, a private consulting and investment company. Mr. Sands is also a director of Protein Sciences Corporation and Terra

Nitrogen Corporation. Mr. Sands served as Managing Director, Investment Banking for the Global Metals/Mining Group of Merrill Lynch & Co. from 1982 until February 1999.

     Wesley M. Taylor, 64, has been a director of Arch Coal since July 2005. Mr. Taylor was President of TXU Generation, a company engaged in electricity infrastructure ownership and management. Mr. Taylor served for 38 years at TXU prior to his retirement in 2004. Mr. Taylor is also a director of FirstEnergy Corporation.

     All of our officers and employees must act ethically at all times and in accordance with the Arch Coal code of conduct, which is published under ‘‘Corporate Governance’’ in the Investors section of Arch Coal’s website at archcoal.com and available in print upon request. Amendments to or waivers from (to the extent applicable to an executive officer of the company) the code will be posted on Arch Coal’s website.

Item 11. Executive Compensation.

     Our managing member is an indirect wholly-owned subsidiary of Arch Coal. As a result, we are effectively managed by the management of Arch Coal. Arch Coal reports separately on the executive compensation of its management.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

     Arch Coal owns 99.5% of our common membership interests. In addition to the remaining 0.5% of our common membership interests, BP p.l.c. owns a 0.5% preferred membership interest. The stockholders of Arch Coal may be deemed to beneficially own an interest in our membership interests by virtue of their ownership of shares of common stock of Arch Coal. Arch Coal reports separately on the ownership by its directors, executive officers and significant stockholders of shares of its common stock.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

     We are subject to the conflict of interest restrictions contained in Arch Coal’s code of conduct and do not have a separate policy governing transactions with related persons. As a result, transactions with Arch Coal may not be at arms length. If the transactions were negotiated with an unrelated party, the impact could be material to our results of operations.

     Our cash transactions are managed by Arch Coal. Cash paid to or from us that is not considered a distribution or a contribution is recorded in an Arch Coal receivable account. In addition, any amounts owed between us and Arch Coal are recorded in the account. The receivable from Arch Coal was $1.2 billion at December 31, 2006 and $869.1 million at December 31, 2005. This amount earns interest from Arch Coal at the prime interest rate. Interest earned was $81.2 million in 2006, $44.8 million in 2005 and $20.5 million in 2004. The receivable is payable on demand; however, it is currently management’s intention to not demand payment of the receivable within the next year. Therefore, the receivable is classified on our balance sheets as long-term.

     On February 10, 2006, Arch Coal established an accounts receivable securitization program. Under the program, we sell our receivables to Arch Coal without recourse at a discount based on the prime rate and days sales outstanding. Under the program, we sold $1.5 billion of trade accounts receivables to Arch Coal during 2006, at a total discount of $10.5 million.

     We mine on tracts that are owned by Arch Coal and subleased to us. Certain subleases required annual advance royalty payments of $10.0 million in each of the years ended December 31, 2005 and 2004 which were fully recoupable against production through production royalties. All sublease agreements between us and Arch Coal were amended as of April 1, 2005 such that royalties on all properties leased from Arch Coal are 7% of the value of the coal mined and removed from the leased land, pursuant to Federal coal regulations. No advance royalties are required under the new agreement. We incurred production royalties of $41.4 million in 2006, $23.2 million in 2005 and $11.5 million in 2004 to Arch Coal under sublease agreements.

     Amounts charged to the intercompany account for our allocated portion of cash contributions to Arch Coal’s pension and postretirement plans totaled $17.0 million in 2006, $12.9 million in 2005 and $11.3 million in 2004.

     We are charged selling, general and administrative services fees by Arch Coal. Expenses are allocated based on Arch Coal’s best estimates of proportional or incremental costs, whichever is more representative of costs incurred by Arch Coal on our behalf. Amounts allocated to us by Arch Coal were $23.5 million in 2006, $24.0 million in 2005 and $17.2 million in 2004. Such amounts are reported as selling, general and administrative expenses in our statements of income.

     Prior to our consolidation of Canyon Fuel, we received administration and production fees from Canyon Fuel for managing those operations. The production fee was calculated on a per-ton basis while the administration fee represented the costs incurred by our employees for administrative matters. We received administration and production fees of $4.8 million during 2004 in connection with these arrangements.

     Our managing member is an indirect, wholly-owned subsidiary of Arch Coal. As a result, we are effectively managed by the management of Arch Coal. Arch Coal reports separately on the independence of its directors.

Item 14. Principal Accounting Fees and Services.

     Ernst & Young LLP is our independent registered public accounting firm. Our audit fees are determined as part of the overall audit fees for Arch Coal and are approved by the audit committee of the board of directors of Arch Coal. Arch Coal reports separately on the fees and services of its principal accountants.

PART IV

Item 15. Exhibits and Financial Statement Schedules

     The consolidated financial statements and consolidated financial statement schedule of Arch Western Resources, LLC and subsidiaries are included in this Annual Report on Form 10-K beginning on page F-1.

     You should see the exhibit index for a list of exhibits included in this Annual Report on Form 10-K.

Report of Independent Registered Public Accounting Firm

The Members
Arch Western Resources, LLC

We have audited the accompanying consolidated balance sheets of Arch Western Resources, LLC and subsidiaries (the Company) as of December 31, 2006 and 2005, and the related consolidated statements of income, nonredeemable membership interest, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedule listed in the index at Item 15. 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 Arch Western Resources, LLC and subsidiaries at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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 2 to the consolidated financial statements, the Company changed its method of accounting for stripping costs effective January 1, 2006. As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for pension and other postretirement benefits effective December 31, 2006.

/s/ Ernst & Young LLP
St. Louis, Missouri
March 23, 2007

ARCH WESTERN RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

		Year Ended December 31
		2006				2005				2004
						(In thousands)
Revenues
Coal sales		$	1,491,362			$	1,126,742			$	735,162
Costs, expenses and other
Cost of coal sales			1,049,429				865,760				577,660
Depreciation, depletion and amortization			108,272				98,347				80,703
Selling, general and administrative expenses			23,466				23,958				17,168
Other operating income:
Gain on sale of Powder River Basin assets			—				(43,297	)			—
Other income			(4,068	)			(4,087	)			(23,644	)
			1,177,099				940,681				651,887
Income from operations			314,263				186,061				83,275
Interest income (expense), net:
Interest expense			(72,273	)			(65,543	)			(55,582	)
Interest income, primarily from Arch Coal, Inc.			81,853				45,233				20,570
			9,580				(20,310	)			(35,012	)
Other non-operating expense:
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps			(7,928	)			(12,688	)			(14,295	)
Income before minority interest			315,915				153,063				33,968
Minority interest			(28,902	)			(24,219	)			(1,022	)
Net income		$	287,013			$	128,844			$	32,946
Net income attributable to redeemable membership interest		$	1,435			$	644			$	165
Net income attributable to non-redeemable membership interest		$	285,578			$	128,200			$	32,781

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

ARCH WESTERN RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		December 31
		2006				2005
		(In thousands)
ASSETS
Current assets
Cash and cash equivalents		$	186			$	152
Trade accounts receivable			985				111,948
Other receivables			14,733				5,469
Inventories			94,828				98,478
Prepaid royalties			2,945				—
Other			24,458				17,318
Total current assets			138,135				233,365
Property, plant and equipment
Coal lands and mineral rights			762,819				762,699
Plant and equipment			973,359				772,027
Deferred mine development			357,736				280,996
			2,093,914				1,815,722
Less accumulated depreciation, depletion and amortization			(860,068	)			(747,563	)
Property, plant and equipment, net			1,233,846				1,068,159
Other assets
Receivable from Arch Coal, Inc.			1,152,102				869,056
Other			33,689				44,796
Total other assets			1,185,791				913,852
Total assets		$	2,557,772			$	2,215,376
LIABILITIES AND MEMBERS’ INTERESTS
Current liabilities
Accounts payable		$	110,725			$	89,632
Accrued expenses			129,495				111,821
Total current liabilities			240,220				201,453
Long-term debt			958,881				960,247
Accrued postretirement benefits other than pension			31,036				27,016
Asset retirement obligations			174,902				136,092
Accrued workers’ compensation			10,027				11,446
Other noncurrent liabilities			38,705				62,060
Total liabilities			1,453,771				1,398,314
Redeemable membership interest			6,934				5,647
Minority interest			162,522				133,620
Non-redeemable membership interest			934,545				677,795
Total liabilities and membership interests		$	2,557,772			$	2,215,376

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

ARCH WESTERN RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Year Ended December 31
		2006				2005				2004
		(In thousands)
Operating Activities
Net income		$	287,013			$	128,844			$	32,946
Adjustments to reconcile to cash provided by operating activities:
Depreciation, depletion and amortization			108,272				98,347				80,703
Prepaid royalties expensed			5,264				12,722				10,051
Net (gain) loss on dispositions of property, plant and equipment			221				(44,525	)			(5,826	)
Net distributions from equity investment			—				—				16,049
Minority interest			28,902				24,220				1,022
Other non-operating expense			7,928				12,688				14,295
Changes in operating assets and liabilities (see Note 20)			119,900				(6,681	)			(28,190	)
Other			(17,834	)			183				(5,748	)
Cash provided by operating activities			539,666				225,798				115,302
Investing Activities
Capital expenditures			(260,368	)			(108,600	)			(78,313	)
Increase in receivable from Arch Coal, Inc.			(279,135	)			(187,280	)			(318,766	)
Additions to prepaid royalties			(409	)			(12,807	)			(14,643	)
Proceeds from dispositions of property, plant and equipment			295				81,755				6,059
Cash used in investing activities			(539,617	)			(226,932	)			(405,663	)
Financing Activities
Proceeds from issuance of senior notes			—				—				261,875
Debt financing costs			(15	)			(65	)			(5,334	)
Cash provided by (used in) financing activities			(15	)			(65	)			256,541
Increase (decrease) in cash and cash equivalents			34				(1,199	)			(33,820	)
Cash and cash equivalents, beginning of year			152				1,351				35,171
Cash and cash equivalents, end of year		$	186			$	152			$	1,351
Supplemental cash flow information:
Cash paid during the year for interest		$	64,125			$	65,423			$	46,636