UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2005

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

For the transition period from                      to                     .

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, Suite 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 1, 2006, 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			17
Item 1B.		Unresolved Staff Comments			26
Item 2.		Properties			26
Item 3.		Legal Proceedings			28
Item 4.		Submission of Matters to a Vote of Security Holders			28
Part II					28
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			28
Item 6.		Selected Financial Data			29
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			30
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk			41
Item 8.		Financial Statements and Supplementary Data			41
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			41
Item 9A.		Controls and Procedures			42
Item 9B.		Other Information			42
Part III					42
Item 10.		Directors and Executive Officers of the Registrant			42
Item 11.		Executive Compensation			43
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			43
Item 13.		Certain Relationships and Related Transactions			43
Item 14.		Principal Accounting Fees and Services			44
Part IV					44
Item 15.		Exhibits and Financial Statement Schedules			44
Master Lease and Sublease Agreement
Amendment No. 1 to Master Lease and Sublease Agreement
Subsidiaries of the Registrant
Rule 13a-14(a)/15d-14(a) Certification of Paul A. Lang
Rule 13a-14(a)/15d-14(a) Certification of Robert J. Messey
Section 1350 Certification of Paul A. Lang
Section 1350 Certification of Robert J. Messey

i 

PART I

Item 1. Business.

     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, see “Risk Factors” under Item 1A.

     General

     Arch Western Resources, LLC is a subsidiary of Arch Coal, Inc., one of the largest coal producers in the United States. From mines located in the western United States, we mine, process and market bituminous and sub-bituminous coal with a low sulfur content. We sell substantially all of our coal to producers of electric power and industrial facilities. In 2005, we sold approximately 105.8 million tons of coal.

     At December 31, 2005, we operated six active mines and controlled approximately 2.4 billion tons of proven and probable coal reserves. 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. At December 31, 2005, we estimate our proven and probable coal reserves had an average heat value of approximately 9,300 Btus and an average sulfur content of approximately 0.32%.

     Our History

     We were formed as a joint venture on June 1, 1998 when Arch Coal, Inc. 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 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. Upon acquisition, Arch Coal contributed the assets and liabilities of Triton’s North Rochelle mine (excluding coal reserves) to us. Upon 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 major contributor to the global energy supply, representing more than 24% of international primary energy consumption, according to the World Coal Institute. The United States produces more than 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 preliminary 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 2005. Coal also represents the lowest cost fossil fuel used for electric power generation, making it critical to the United States economy. According to the EIA, the average delivered cost of coal to electric power generators for the first nine months of 2005 was $1.52/mm Btu, which was $5.05/mm Btu less expensive than residual fuel oil and $5.98/mm Btu less expensive than natural gas.

     Several events occurring in 2005 highlighted coal’s relative importance to the United States. Compared to other fuels used for electric power generation, coal is domestically-available, reliable, and can be used in an environmentally-friendly manner. Prices for oil and natural gas in the United States reached record levels in 2005 because of tensions regarding international supply and disruptions from two major hurricanes. High 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, over 80,000 megawatts 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.

     Record level demand for coal in the United States strained production and transportation in 2005. 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 2005, a third rail-carrier announced that it is seeking financing to construct rail access to the Powder River Basin in Wyoming. We believe this announcement further demonstrates the commitment to coal as a future source of fuel for the United States.

     The coal industry also experienced record low miner fatalities in 2005. We expect that the industry will continue to explore ways to further reduce and eliminate work-place hazards in the coming years.

     Coal is expected to remain the fuel of choice for domestic power generation through 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 believe these 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 utilities 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. Production of coal in the United States has increased from 434 million tons in 1960 to about 1.1 billion tons in 2004 based on information provided by the EIA.

     According to the EIA, U.S. coal consumption by sector for 2003 and 2004, the last years for which final information is currently available, is as follows:

		2003								2004
End Use		Tons (millions)				% of Total				Tons (millions)				% of Total
Electric generation			1,005.1				91.8	%			1,016.3				91.9	%
Industrial			61.3				5.6	%			61.2				5.5	%
Steel production			24.3				2.2	%			23.7				2.1	%
Residential/Commercial			4.2				0.4	%			4.2				0.4	%
Total			1,094.9				100.0	%			1,105.4				100.0	%

     Coal has long been favored as an electricity generating fuel by utilities because of its cost advantage and its availability throughout the United States. According to the EIA, coal accounted for 50% of U.S. electricity generation in 2004 and is projected to account for 57% in 2030 since generation from natural gas is expected to peak in 2020. The largest cost component in electricity generation 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 plant built today, fuel costs would represent about one-half of total operating costs, whereas the share for a new natural gas-fired plant would be almost 90%. Other factors that influence each utility’s choice of electricity generation method include facility cost, fuel transportation infrastructure, environmental

restrictions and other factors. According to the EIA, the breakdown of U.S. electricity generation by fuel source in 2004, the last year for which final information is currently available, is as follows:

		% of Total U.S.
Electricity Generation Mode		Electricity Generation
Coal			50.0	%
Nuclear			19.9	%
Natural gas			17.7	%
Hydro			6.8	%
Petroleum			3.0	%
Other			2.6	%
Total			100.0	%

     The EIA projects that generators of electricity will increase their demand for coal as demand for electricity increases. Because coal-fired generation is used in most cases to meet base load requirements, coal consumption has generally grown at the pace of electricity growth. Demand for electricity has historically grown in proportion to the U.S. economic growth by gross domestic product. 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 coal, as well as other fuels such as natural gas, oil and nuclear and alternative energy sources such as hydroelectric power. According to the EIA, coal use for electricity generation is expected to increase on average by 1.8% per year from 2004 to 2025.

     The following chart sets forth the forecasted domestic electricity demand and the portion of demand that is forecasted to be generated by coal based on information provided by the EIA:

     The other major market for coal is the steel industry. Metallurgical coal is distinguished by special quality characteristics including high carbon content, low expansion pressure, low sulfur content and various other chemical attributes. Metallurgical coal is also high in heat value and therefore in some instances desirable to utilities as fuel for electricity generation. The price offered by steel makers for the metallurgical quality attributes is typically higher than the price offered by utility coal buyers for steam coal.

     U.S. Coal Production. In 2004, the last year for which information is currently available, total coal production in the United States as estimated by the U.S. Department of Energy was 1.1 billion tons. According to the EIA, the breakdown of U.S. coal production by production region for 2003 and 2004, the last years for which final information is currently available, is as follows (tons in millions):

		2003								2004
		Tons				%				Tons				%
Appalachia			376.1				35.1	%			389.9				35.1	%
Western			548.7				51.2	%			575.2				51.8	%
Interior (1)			146.0				13.6	%			146.0				13.1	%
Total			1,070.8				100.0	%			1,111.1				100.0	%

     Appalachian Region. Central Appalachia, including eastern Kentucky, Virginia and southern West Virginia, produced 20.8% of the total U.S. coal production in 2004. Coal mined from this region generally has a high heat value of between 12,000 and 14,000 Btus per pound and low sulfur content ranging from 0.7% to 1.5%. From 2002 to 2004, according to the Mine Safety and Health Administration, Central Appalachia experienced a 6.7% decline in production from 248.7 million tons to 232.0 million tons, primarily as a result of the depletion of economically attractive reserves, permitting issues and increasing costs of production. These factors were partially offset by production increases in southern West Virginia due to the expansion of more economically attractive surface mines. Northern Appalachia includes Maryland, Ohio, Pennsylvania and northern West Virginia. Coal from this region generally has a high heat value of between 12,000 and 14,000 Btus per pound. Its typical sulfur content ranges from 1.0% to 4.5%. Southern Appalachia includes Alabama and Tennessee. Coal mined from this region generally has a high heat value of between 12,500 and 14,000 Btus per pound and low sulfur content ranging from 0.7% to 1.5%.

     Western United States. The Powder River Basin is located in northeastern Wyoming and southeastern Montana. Coal from this region has a very low sulfur content of between 0.15% to 0.55% and a low heat value of between 7,500 and 10,000 Btus per pound. Coal shipped east from the Powder River Basin competes with coal sold in the Appalachian region. The price of Powder River Basin coal is less than that of coal produced in Central Appalachia because Powder River Basin coal 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 utilities to either 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 sulfur content of between 0.5% and 1.0% and a heat value of between 10,500 and 12,500 Btus per pound. The Four Corners area includes northwestern New Mexico, northeastern Arizona, southwestern Utah and southeastern Colorado. The coal from this region typically has a sulfur content of between 0.75% and 1.0% and a heat value of between 9,000 and 10,000 Btus per pound.

     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. There has been significant consolidation among coal producers in the Illinois Basin over the past several years. Coal from this region varies in heat value from 10,000 to 12,500 Btus per pound and has a high sulfur content of between 2.0% and 4.0%.

     Other coal-producing states in the interior region of the United States include Arkansas, Kansas, Louisiana, Mississippi, Missouri, North Dakota, Oklahoma and Texas. The majority of production in the interior region outside of the Illinois Basin consists of lignite coal production from Texas and North Dakota. This lignite coal typically has a heat value of between 5,000 and 9,500 Btus per pound and a sulfur content of between 1.0% and 2.0%.

     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 U.S. waterways and water transportation facilities are built for export rather than import of coal. However, coal imports have demonstrated recent strength due to their competitive pricing, particularly when compared to certain domestic coal prices.

     Our Mining Operations

     As of December 31, 2005, we operated six active mines, all 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 significant mining operations:

     We expect our mine management teams to focus their efforts on controlling costs, managing volume and managing the revenue adjustments that may be necessary as a result of the quality of coal produced for contract shipments assigned to a specific mine. We evaluate and compensate our mine management teams based on operating costs per ton at the mine level and on other non-financial measures, such as safety and environmental results.

     Because we manage operating results on a regional basis, the reported profit at any individual mine may not be meaningful and is not indicative of the future economic prospects of the mine. An individual mine’s profit is based on the contract shipments that are assigned to it by Arch Coal’s central marketing group and the pricing under contracts for the sale of coal from a particular mine. Contracts are typically assigned based on the availability of coal and the cost of transporting the coal to the customer. Therefore, a mine that is assigned a lower-price contract will have a lower profit margin than a similar mine with similar costs that ships a nearly identical product under a higher-price contract. For more information about our sales and marketing, you should see “Sales, Marketing and Customers” below, and for more information about our contracts, you should see “Coal Supply Contracts” below.

     The following table provides the location of and a summary of information regarding our principal mining complexes at December 31, 2005, the total sales associated with these complexes for the years ended December 31, 2003, 2004 and 2005 and the total reserves associated with these complexes at December 31, 2005:

		Captive				Contract				Mining				Transport				Tons Sold												Assigned
Mining Complex (Location)		Mine(s)(1)				Mine(1)				Equipment				-ation				2003				2004				2005				Reserves
																		(Amounts in Millions)												(Million Tons)
Powder River:
Black Thunder (Wyoming)			S				—				D, S			UP/BN					62.6				75.1				87.6				1,512.6
Coal Creek (Wyoming) (2)			S				—				D, S			UP/BN					—				—				—				235.8
Western Bituminous:
Arch of Wyoming (Wyoming) (3)			—				—				—			UP					0.5				0.2				—				—
Dugout Canyon (Utah) (4)			U				—			LW, C				UP					2.5				3.8				4.9				34.8
Skyline (Utah) (4) (5)			U				—			LW, C				UP					3.1				0.6				—				16.0
SUFCO (Utah) (4)			U				—			LW, C				UP					7.5				7.8				7.5				57.2
West Elk (Colorado)			U				—			LW, C				UP					6.5				6.2				5.8				73.9
Totals																			82.7				93.7				105.8				1,930.3

     We also incorporate by reference the information about the operating results of each of our segments for the years ended December 31, 2005, 2004 and 2003 contained in Note 19 — Segment Information to our consolidated financial statements.

     Our Mining Methods

     We employ mining methods designed to most efficiently mine coal according to the geological characteristics of our mines.

     Underground Mining. Underground mines are typically operated using one, or both, of two different techniques: continuous mining or longwall mining. In 2005, 17% of our coal production came from underground mining operations generally using longwall mining techniques. Longwall mining is the most productive underground mining method used in the United States. A rotating drum is trammed mechanically across the face of the coal, and a hydraulic system supports the roof of the mine while the drum advances through the coal. Chain conveyors then move the loosened coal to a standard underground mine conveyor system for delivery to the surface. Continuous miners are used to develop access to long rectangular blocks of coal that are then mined with longwall equipment, allowing controlled subsidence behind the advancing machinery. Longwall mining is highly productive and most effective for long blocks of medium to thick coal seams. Ultimate seam recovery of in-place reserves using longwall mining can reach 70%, which is generally much higher than the room-and-pillar underground mining techniques.

     Surface Mining. Surface mining is used when coal is found close to the surface. In 2005, 83% of our coal production came from surface mines. This method involves the removal of overburden (earth and rock covering the coal) with heavy earth moving equipment and explosives, loading out the coal, replacing the overburden and topsoil after the coal has been excavated and reestablishing vegetation as well as making other improvements that have local community and environmental benefits. Seam recovery for surface mining is typically between 80% and 90%. We employ the following two types of surface mining methods: truck-and-shovel mining and dragline mining.

     Truck-and-shovel mining is a surface mining method that uses large shovels, excavators or loaders to remove overburden which is then used to backfill pits after coal removal. Once exposed, shovels, excavators or loaders load the coal into haul trucks for transportation to a preparation plant or unit train loadout facility. Dragline mining is a surface mining method that uses large capacity draglines to remove overburden to expose the coal seams. Once exposed, shovels load coal into haul trucks for transportation to a preparation plan or unit train loadout facility. Seam recovery using the truck-and-shovel or dragline mining methods is typically 85% or more.

     Our Mining Complexes

     The following provides a description of the operating characteristics of our mining complexes. The amounts disclosed below for the total cost of property, plant and equipment and net book value of each mining complex do not include the costs or net book values of the coal reserves that we have assigned to any individual complex.

     Powder River Basin. Our operations in the Powder River Basin are located in Wyoming and include two surface mines. During 2005, these mining complexes sold approximately 87.6 million tons of compliance, low-sulfur coal to customers in the United States. We control approximately 1.9 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 24,000 acres with a majority of coal controlled by federal and state leases with 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. The total cost of property, plant and equipment at the Black Thunder mine at December 31, 2005 was approximately $503.4 million and the net book value was approximately $328.0 million.

     Coal Creek. The Coal Creek mine is a surface mining complex located in Campbell County, Wyoming. The mine complex is located on approximately 10,000 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 no active pit areas, and one loadout facility. Although the mine has been idle since 2000, we plan to reactivate production in 2006. 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. The total cost of property, plant and equipment at the Coal Creek mine at December 31, 2005 was approximately $49.4 million, and the net book value was approximately $35.0 million. The Coal Creek mine had no coal production during 2005.

     Western Bituminous Region. Our operations in the Western Bituminous Region are located in southern Wyoming, Colorado and Utah and include four underground mines and four surface mines. All of the surface mines are in reclamation mode. During 2005, these mining complexes sold approximately 18.3 million tons of compliance, low-sulfur coal to customers in the United States. We control approximately 469.2 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. The complex also consists of an undeveloped mining area called Carbon Basin that has recently been permitted for operations. The inactive surface mines under reclamation are located on approximately 58,000 acres with a majority of coal controlled by federal, private and state leases. The Carbon Basin mine complex is located on approximately 13,000 acres with a majority of coal controlled by federal, private and state leases. The total cost of property, plant and equipment at the Arch of Wyoming complex at December 31, 2005 was approximately $40.8 million, and the net book value was approximately $3.1 million. The Arch of Wyoming complex had no coal production during 2005.

     Dugout Canyon. The Dugout Canyon mine is an underground mine located in Carbon County, Utah. The mine is located on approximately 9,000 acres with a majority of coal controlled by federal and state leases with a small amount of private fee coal acreage. The mine currently consists of a single longwall and two continuous miner sections, and one truck 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 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. The total cost of property, plant and equipment at the Dugout Canyon mine at December 31, 2005 was approximately $81.0 million, and the net book value was approximately $50.9 million.

     Skyline. The Skyline mine is an underground mine located in Carbon and Emery Counties, Utah. The mine is located on approximately 13,000 acres with a majority of coal controlled by federal leases with a small amount on private and county leases. The mine currently consists of two continuous miner sections and a longwall that will be operational in mid-2006 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. The total cost of property, plant and equipment at the Skyline mine at December 31, 2005 was approximately $81.3 million and the net book value was approximately $46.4 million.

     Sufco. The Sufco mine is an underground mine located in Sevier County, Utah. The mine is located on approximately 27,000 acres with a majority of coal controlled by federal and state leases with a small amount of private fee coal acreage. The mine currently consists of a single longwall and two continuous miner sections, and one loadout facility. All of the coal is shipped raw to customers without preparation plant processing. All of the production is shipped via the Union Pacific railroad or directly to customers by highway trucks. The loadout facility, located approximately 90 miles from the mine, is capable of loading an 11,000-ton unit train in less than three hours. The total cost of property, plant and equipment at the Sufco Mine at December 31, 2005 was approximately $121.6 million, and the net book value was approximately $45.6 million.

     West Elk. The West Elk mine is an underground mine located in Gunnison County, Colorado. The mine is located on approximately 15,000 acres with a majority of coal controlled by federal and state leases with a small amount of private fee coal acreage. The mine currently consists of a single longwall and 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. The total cost of property, plant and equipment at the West Elk mine at December 31, 2005 was approximately $173.5 million, and the net book value was approximately $71.9 million.

     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 within a given major coal producing region tend to be relatively consistent. The two principal components of the price of coal within a region are the price of coal at the mine, which is influenced by market conditions and by mine operating costs, coal quality, and transportation costs involved in moving coal from the mine to the point of use. 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. Within a particular geographic region, 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 modern mining equipment and construction of extensive ventilation systems and higher 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.

     Management 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 our customers purchase coal on a regional basis, coal can generally be sourced from several different locations within a region. Once a contractual commitment to purchase an amount of coal at a certain price has been obtained, Arch Coal’s central marketing group assigns contract shipments to our various mines which can be used to source the coal in the appropriate region.

     Coal Supply Contracts

     We sell coal both under long-term contracts, the terms of which are greater than 12 months, and on a current market or spot basis. When 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. Historically, the price of coal sold under long-term contracts has exceeded prevailing spot prices for coal. However, in the past several years new contracts have been priced at or near existing spot rates.

     The terms of the coal sales contracts allocated to us result from bidding and extensive negotiations with customers. Consequently, the terms of these contracts typically vary significantly in many respects, including price adjustment features, provisions permitting renegotiation or modification of coal sale prices, coal quality requirements, quantity parameters, flexibility and adjustment mechanisms, permitted sources of supply, treatment of environmental constraints, options to extend, and force majeure, suspension, termination and assignment provisions.

     Provisions permitting renegotiation or modification of coal sale prices are present in many 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, customers have the option to terminate the contract if prices have increased by a specified percentage from the price at the commencement of the contract or if the parties cannot agree on a new price. The term of sales contracts has decreased significantly over the last two decades as competition in the coal industry has increased and, more recently, as electricity generators have prepared themselves for federal Clean Air Act requirements and the deregulation of their industry.

     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 competitors include Foundation Coal Holdings, Inc., Kennecott Energy Company and Peabody Energy Corp. Some of these coal producers are larger and have greater financial resources and larger reserve bases than we do. We also compete directly with a number of smaller producers in the Powder River Basin areas and Western Bituminous region. 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 petroleum, natural gas, hydropower and nuclear energy for steam and electrical power generation. Over time, costs and other factors, such as safety and environmental consideration, relating to these alternative fuels may affect the overall demand for coal as a fuel.

     Geographic Data

     We market our coal principally to electric utilities in the United States. Coal sales to foreign customers for 2005, 2004 and 2003 were insignificant.

     Environmental Matters

     Our operations, like operations of other companies engaged in similar businesses, are subject to regulation by federal, state and local 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 and management of 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 the EPA, and the states to implement regulatory programs that will lead to the attainment and maintenance of EPA-promulgated ambient air quality standards. EPA has promulgated ambient air quality standards for a number of air pollutants, including standards for sulfur dioxide, particulate matter, nitrogen oxides and ozone, which are associated with the combustion of coal. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources in an effort to comply with these ambient air quality standards. In particular, coal-fired power plants will be affected by state regulations designed to achieve attainment of the ambient air quality standard for ozone, which may require significant expenditures for additional emissions control equipment needed to meet the current national ambient air standard for ozone. Ozone is produced by the combination of two primary precursor pollutants: volatile organic compounds and nitrogen oxides. Nitrogen oxides are a by-product of coal combustion. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding in the years ahead.

     In July 1997, the EPA adopted more stringent ambient air quality standards for ozone and fine particulate matter (PM_2.5, which can be formed in the air from gaseous emissions of sulfur dioxide and nitrogen oxides, both of which are associated with coal combustion). In a February 2001 decision, the United States Supreme Court largely upheld the EPA’s position, although it remanded the EPA’s ozone implementation policy for further consideration. On remand, the Court of Appeals for the D.C. Circuit affirmed the EPA’s adoption of these more stringent ambient air quality standards. As a result of the finalization of these standards, states that are not in attainment for these standards will have to revise their State Implementation Plans to include provisions for the control of ozone precursors and/or particulate matter. In April 2004, the EPA issued final nonattainment designations for the eight-hour ozone standard, and, in December 2004, issued the final nonattainment designations for PM_2.5. On April 30, 2004, the EPA published the final Phase 1, 8-hour ozone implementation rule, and on November 29, 2005, the EPA published its final Phase 2, 8-hour ozone implementation rule. On November 1, 2005, the EPA published its proposed PM_2.5 implementation rule. States will have to submit their 8-hour ozone and PM_2.5 SIPs by April 2007 and April 2008, respectively, and are likely to require electric power generators to reduce further sulfur dioxide, nitrogen oxide and particulate matter emissions, particularly in designated nonattainment areas. Both the nonattainment designations and the 8-hour implementation rule are the subject of litigation. Depending upon the outcome of the litigation, the potential need to achieve such emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other pollutants could restrict the market for coal and our development of new mines. This in turn may result in decreased production and a corresponding decrease in our revenues. The EPA is currently obligated under a consent decree to sign final rulemakings concerning the particulate matter National Ambient Air Quality Standards (NAAQS) in September 2006, and proposed and final rulemakings concerning the ozone NAAQS in March 2007 and December 2007, respectively. On January 17, 2006, the EPA published a new and more stringent proposed NAAQS for PM_2.5 and inhalable course particles (PM_10-2.5), which are smaller than 10 micrometers in diameter but larger than PM_2.5. These and other ambient air quality standards could restrict the market for coal and the development of new mines.

     In October 1998, the 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 the NOx SIP Call, Phase I states are required to reduce nitrogen oxide emissions by 2004, and Phase II states are required to reduce nitrogen oxide emissions by 2007. The Court of Appeals for the D.C. Circuit largely upheld the NOx SIP Call, and affected states have adopted and submitted to the EPA NOx SIP Call rules. As a result, many power plants and large industrial sources have been or will be required to install additional control

measures. The installation of these control measures could make it more costly to operate coal-fired units and, depending upon the requirements of individual SIPs, could make coal a less attractive fuel.

     The EPA has also initiated a regional haze program designed to protect and to 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 (CAVR) which will require certain existing coal-fired power plants to install Best Available Retrofit Technology (BART) to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, and particulate matter. By imposing limitations upon the placement and construction of new coal-fired power plants and BART requirements on existing coal-fired power plants, the EPA’s regional haze program could affect the future market for coal. The EPA’s CAVR is the subject of litigation in the Court of Appeals for the D.C. Circuit. In addition, in August 2005, the EPA published a proposed emissions trading rule as an alternative to BART.

     New regulations concerning the routine maintenance provisions of the New Source Review program were published in October 2003. Fourteen states, the District of Columbia and a number of municipalities filed lawsuits challenging these regulations, and in December 2003 the Court stayed the effectiveness of these rules. In July 2004 the EPA granted a petition to reconsider the legal basis for the routine maintenance provisions, and the litigation was suspended while the rule was being reconsidered. In June 2005, the EPA issued its final response, which does not change the rule. The case has been returned to the D.C. Circuit’s active docket, and final briefs were due in January 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. By imposing requirements for the construction and modification of coal-fired units, these New Source Review reforms could make coal a less attractive fuel.

     In January 2004, the EPA Administrator announced that the EPA would be taking new enforcement actions against utilities for violations of the existing New Source Review requirements, and shortly thereafter, the EPA issued enforcement notices to several electric utility companies. Additionally, the U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities for alleged violations of the Clean Air Act. The EPA claims that these utilities have failed to obtain permits required under the Clean Air Act for alleged major modifications to their power plants. We supply coal to some of the currently affected utilities, and it is possible that other of our customers will be sued. These lawsuits could require the utilities to pay penalties and install pollution control equipment or undertake other emission reduction measures, which could adversely impact their demand for coal.

     In March 2004, North Carolina submitted to the EPA a petition under § 126 of the Clean Air Act. In its petition, North Carolina alleges that power plants in 12 states contribute significantly to nonattainment 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 nonattainment in, and interfere with maintenance by, North Carolina with respect to the 8-hour ozone NAAQS. In August 2005, the EPA published a proposed rule in response to North Carolina’s §126 Petition. For ozone, the EPA is proposing to deny North Carolina’s petition. For PM_2.5, the EPA is proposing to deny North Carolina’s petition as to Michigan and Illinois and with respect to the other targeted States is proposing two options. Under Option 1, the EPA is proposing to deny North Carolina’s petition if the EPA issues its Clean Air Interstate Rule (CAIR) Federal Implementation Plan (FIP) by March 15, 2006, and under Option 2, the EPA is proposing to grant North Carolina’s petition if the EPA does not issue its CAIR FIP by March 15, 2006. Pursuant to a consent decree, the EPA is obligated to promulgate its final rule on North Carolina’s § 126 petition by March 15, 2006. If the EPA grants North Carolina’s § 126 petition, then coal-fired power plants in Alabama, Georgia, Indiana, Kentucky, Ohio, Pennsylvania, South Carolina, Tennessee, Virginia, and West Virginia must reduce their SO₂ and NO_X emissions by March 15, 2009. If finalized, the EPA’s proposed response to North Carolina’s § 126 petition could adversely impact the coal needs of power plants in the affected states.

     In March 2005, the EPA issued three new rules that will impact coal-fired power plants. These are (i) the Clean Air Interstate Rule (CAIR), which caps emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) 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 (CAMR), which caps and reduces

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 pollution credits to plant operators who need more time to comply with the stricter rules. CAIR requires reductions of SO2 and/or NOx emissions across 28 eastern states and the District of Columbia and, when fully implemented in 2015, CAIR will reduce SO2 emissions in these states by over 70 percent and NOx emissions by over 60 percent from 2003 levels. Under the new mercury emissions rule, 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 (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 percent reduction. Utility analysts have estimated meeting the goals for SO2 and NOx will cost power generators approximately $50 billion to install the required filtration systems, or “scrubbers,” on their smokestacks, but these controls are expected to also reduce the mercury emissions to the targeted levels in 2010. Additional controls will be required to meet the mercury emissions cap in 2018. The CAIR, mercury de-listing rule, and the CAMR are the subject of ongoing litigation. If the mercury de-listing rule is not upheld, then the CAMR and its cap-and-trade program may also be rejected in favor of the MACT approach. If CAIR and CAMR survive the legal challenges, or if a MACT requirement is imposed for mercury emissions, the additional costs that may be associated with operating coal-fired power generation facilities due to the implementation of these new rules may render coal a less attractive fuel source.

     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. Because sulfur is a natural component of coal, required sulfur dioxide reductions can affect coal mining operations. 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 utilities can comply with these requirements by:

	•		burning lower sulfur coal, either exclusively or mixed with higher sulfur coal;
	•		installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal;
	•		reducing electricity generating levels; or
	•		purchasing or trading emissions credits.

     Specific emissions sources receive these credits, which electric utilities and industrial concerns can trade or sell to allow other units to emit higher levels of sulfur dioxide. Each credit allows its holder to emit one ton of sulfur dioxide.

     Other proposed initiatives may have an effect upon coal operations. One such proposal is the Bush Administration’s Clear Skies legislation. As proposed, this legislation is designed to reduce emissions of sulfur dioxide, nitrogen oxides, and mercury from power plants. Other 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 towards increased regulation of emissions, including carbon dioxide and mercury. If such initiatives were to become law, power plants could choose to shift away from coal as a fuel source to meet these requirements.

     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. In January 2006, the West Virginia legislature amended its mine safety and health laws to require mine operators to notify emergency response coordinators promptly after serious accidents and provide miners with wireless tracking and communications devices and self-contained self-rescue breathing equipment. Federal legislation has been proposed along the same lines but has not been yet passed, and other states are considering similar laws.

     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.

     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 currently pending or asserted 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. Efforts to control greenhouse gas emissions could result in reduced demand for coal if electric power generators switch to lower carbon sources of fuel.

     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.

     Regulatory authorities exercise considerable discretion in the timing of permit issuance. Also, private individuals and the public at large possess 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, or may 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.

     In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including us, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior 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. As a result, we cannot be sure that we will not experience difficulty in obtaining mining permits in the future.

     Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, the activities of mine operators, including us, may be more closely regulated. Legislation and regulations, as well as future interpretations of existing laws, may also require substantial increases in equipment expenditures and operating costs, as well as delays, interruptions or the termination of operations. We cannot predict the possible effect of such regulatory changes.

     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.

     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.

     Definitions of Select Mining Terms

     Assigned Reserves. Recoverable coal reserves that have been designated for mining by a specific operation.

     Auger Mining. Auger mining employs a large auger, which functions much like a carpenter’s drill. The auger bores into a coal seam and discharges coal out of the spiral onto waiting conveyor belts. After augering is completed, the openings are reclaimed. This method of mining is usually employed to recover any additional coal left in deep overburden areas that cannot be reached economically by other types of surface mining.

     Btu — British Thermal Unit. A measure of the energy required to raise the temperature of one pound of water one degree of Fahrenheit.

     Coal Seam. A bed or stratum of coal.

     Coal Washing. The process of removing impurities, such as ash and sulfur-based compounds, from coal.

     Compliance Coal. Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus, which is equivalent to 0.72% sulfur per pound of 12,000 Btu coal. Compliance coal requires no mixing with other coals or use of sulfur dioxide reduction technologies by generators of electricity to comply with the requirements of the Clean Air Act.

     Continuous Miner. A machine used in underground mining to cut coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation.

     Continuous Mining. One of two major underground mining methods now used in the United States. This process utilizes a continuous miner.

     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 from the end of a long boom. The bucket, which is suspended by cables, is able to scoop up great amounts of overburden as it is dragged across the excavation area.

     Excavator-and-Loader Mining. A form of surface mining in which large excavators remove overburden from above the coal seam. The overburden is loaded into trucks and hauled to a valley fill or back-stacked on previously mined areas.

     Highwall Mining. Highwall mining employs a large machine with a continuous miner head. The head cuts into a coal seam and discharges coal out onto waiting conveyor belts. After highwall mining is completed, the openings are reclaimed. This method of mining is usually employed to recover any additional coal left in deep overburden areas that cannot be reached economically by other types of surface mining.

     Longwall Mining. One of two major underground coal mining methods now used in the United States. This method employs a rotating drum, which is pulled mechanically back and forth across a face of coal that is usually several hundred feet long. The loosened coal falls onto a conveyor for removal from the mine. Longwall operations include a hydraulic roof support system that advances as mining proceeds, allowing the roof to fall in a controlled manner in areas already mined.

     Low-Sulfur Coal. Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btus.

     Metallurgical Coal. The various grades of coal suitable for distillation into carbon in connection with the manufacture of steel. Also known as “met” coal.

     Preparation Plant. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content.

     Probable Reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart; therefore, the degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

     Proven Reserves. Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well established.

     Reclamation. The restoration of land and environmental values to a mining site after the coal is extracted. Reclamation operations are usually underway where the coal has already been taken from a mine, even as mining operations are taking place elsewhere at the site. 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.

     Spot Market. Sales of coal under an agreement for shipments over a period of less than one year.

     Steam Coal. Coal used in steam boilers to produce electricity.

     Surface Mine. A mine in which the coal lies near the surface and can be extracted by removing overburden.

     Tons. References to a “ton” mean a “short” or net tonne, which is equal to 2,000 pounds.

     Truck-and-Loader Mining. A form of surface mining in which endloaders remove overburden from above the coal seam. The overburden is loaded into trucks and hauled to a valley fill or back-stacked on previously mined areas.

     Truck-and-Shovel Mining. An open-cast method of mining that uses large shovels to remove overburden, which is used to backfill pits after coal removal.

     Unassigned Reserves. Recoverable coal reserves that have not yet been designated for mining by a specific operation.

     Underground Mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car or conveyor to the surface.

     Employees

     As of March 1, 2006, we employed a total of approximately 2,120 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, Inc. As a result, we are effectively managed by the management of Arch Coal, Inc. The following is a list of the executive officers of Arch Coal, Inc., their ages and their positions and offices during the last five years:

     C. Henry Besten, Jr., 58, is Senior Vice President — Strategic Development of Arch Coal, Inc. and has served in such capacity since December 2002. Mr. Besten is also President of Arch Energy Resources, Inc., a subsidiary of Arch Coal, Inc., and has served in that capacity since July 1997. From July 1997 to December 2002, Mr. Besten served as Vice President — Strategic Marketing of Arch Coal, Inc. Mr. Besten also served as Acting Chief Financial Officer of Arch Coal, Inc. from December 1999 to November 2000.

     John W. Eaves, 48, is Executive Vice President and Chief Operating Officer of Arch Coal, Inc. and has served in such capacity since December 2002. Mr. Eaves has also been a director of Arch Coal, Inc. since February 2006. From February 2000 to December 2002, Mr. Eaves served as Senior Vice President — Marketing of Arch Coal, Inc. and from September 1995 to December 2002 as President of Arch Coal Sales Company, Inc., a subsidiary of Arch Coal, Inc. Mr. Eaves also served as Vice President — Marketing of Arch Coal, Inc. from July 1997 through February 2000. Mr. Eaves serves on the board of directors of ADA-ES, Inc.

     Sheila B. Feldman, 51, is Vice President — Human Resources of Arch Coal, Inc. 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.

     Robert G. Jones, 49, is Vice President — Law, General Counsel and Secretary of Arch Coal, Inc. and has served in such capacity since March 2000. Mr. Jones served as Assistant General Counsel of Arch Coal, Inc. from July 1997 through February 2000 and as Senior Counsel from August 1993 to July 1997.

     Steven F. Leer, 53, is President and Chief Executive Officer and a director of Arch Coal, Inc. and has served in such capacity since 1992. Mr. Leer also serves on the boards of the Norfolk Southern Corporation, USG Corp., the Western Business Roundtable and the University of the Pacific. Mr. Leer is a past chairman and continues to serve on the boards of the Center for Energy and Economic Development, the National Coal Council and the National Mining Association.

     Robert J. Messey, 60, is Senior Vice President and Chief Financial Officer of Arch Coal, Inc. and has served in such capacity since December 2000. Mr. Messey serves on the board of directors of Baldor Electric Company and Stereotaxis, Inc.

     David B. Peugh, 51, is Vice President — Business Development of Arch Coal, Inc. and has served in such capacity since 1993.

     Deck S. Slone, 42, is Vice President — Investor Relations and Public Affairs of Arch Coal, Inc. and has served in such capacity since 2001. Mr. Slone was named one of the senior officers of Arch Coal, Inc. in August 2005. Mr. Slone has helped direct the investor relations and public affairs functions of Arch Coal, Inc. since joining in 1997.

     David N. Warnecke, 50, is Vice President — Marketing and Trading of Arch Coal, Inc. and is President of Arch Coal Sales Company, Inc., a subsidiary of Arch Coal, Inc. 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.

Item 1A. Risk Factors.

     Our business inherently involves certain risks and uncertainties. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business operations. Should one or more of any of these risks materialize, our business, financial condition or results of operations could be materially adversely affected.

Risks Related to Our Business

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

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

	•		the supply of and demand for domestic and foreign coal;
	•		the demand for electricity in the United States;
	•		the capacity and cost of transportation facilities;
	•		domestic and foreign governmental regulations and taxes;
	•		air emission standards for domestic and foreign coal-fired power plants;
	•		regulatory, administrative and judicial decisions that affect the coal mining industry;
	•		the price and availability of alternative fuels, including the effects of technological developments;
	•		the effect of worldwide energy conservation measures; and
	•		the supply of and demand for metallurgical coal.

     Any one or more of the foregoing factors could adversely affect the sale prices we may be able to obtain for our coal. Declines in the prices we receive for our coal could adversely affect our operating results and our revenue.

     Any change in coal demand by U.S. electric power generators that results in a decrease in the use of coal could result in lower prices for our coal, which would reduce our revenue and adversely impact our earnings and the value of our coal reserves.

     Demand for our coal and the prices that we may obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry, which has accounted for approximately 92% of domestic coal consumption in recent years according to the EIA. The amount of coal consumed for U.S. electric power generation is influenced by factors beyond our control, including:

	•		the overall demand for electricity, which is significantly dependent upon general economic conditions and summer and winter temperatures in the United States;
	•		environmental and government regulation;
	•		technological developments; and
	•		the location, availability, quality and price of competing sources of coal, alternative fuels such as natural gas, oil and nuclear and alternative energy sources such as hydroelectric power.

     Demand for our low sulfur coal and the prices that we will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances in order to meet Clean Air Act requirements.

     In addition, the requirements of the Clean Air Act may result in more electric power generations shifting from coal to natural gas-fired power plans. Any reduction in the amount of coal consumed by domestic electric power

generators could reduce the price of steam coal that we produce, thereby reducing our revenue and adversely affecting our earnings and the value of our coal reserves.

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

     Our coal mining operations are conducted in underground mines and at surface mines. The level of our production at these mines is subject to operating conditions and events beyond our control that could disrupt operations, affect production and the costs of mining at particular mines for varying lengths of time and have a significant impact on our operating results. Adverse operating conditions and events that we may experience include:

	•		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;
	•		regulatory issues involving the plugging of and mining through oil and gas wells that penetrate the coal seams we mine; and
	•		the cost of surety bonds and the collateral required for our mining complexes is increasing and the surety bonds are becoming more difficult to obtain.

     If any of these conditions or events occur in the future at any of our mining complexes, particularly our Black Thunder mine, our cost of mining and any delay or halt of production either permanently or for varying lengths of time could adversely affect our operating results. In addition, if we do not have insurance covering certain of these conditions or events or if the insurance coverage we have 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 and petroleum products and a shortage of tires used in our mining operations could significantly affect our operating profitability.

     Our coal mining operations use significant amounts of steel, diesel fuel and tires. The price of scrap steel, which is used in making roof bolts and required by the room and pillar method of mining, has risen significantly in recent months. During 2005, the costs of diesel fuel, explosives and coal trucking increased as a direct result of supply chain problems related to Hurricane Katrina’s devastation in Mississippi and Louisiana and Hurricane Rita’s destruction in Texas and Louisiana. There may be other acts of nature that could also increase the costs of raw materials. We have also recently experienced a shortage in rubber tires, which are used on the trucks and heavy machinery with which we operate our mines. If the price of steel, petroleum products or other materials remains high or continues to increase and if tires continue to remain in short supply, our operational expenses will remain high or increase and our production could be affected, which could have a significant negative impact on our profitability.

     There is a shortage of skilled coal mining workers, and as a result we are facing significantly higher labor costs as well as competition for workers from other coal producers.

     Efficient coal mining using modern techniques and equipment requires skilled workers, preferably with at least one year of experience and proficiency in multiple mining tasks. Increased demand for coal and the increase in the market price for such coal in recent years has caused a resurgence of mining activity. Consequently, there has been a significant tightening of the labor supply and an increase in the turnover of the labor force as coal producers compete with each other for skilled personnel. In recent years, a shortage of trained coal miners has caused us to operate certain units without full staff, which has decreased our productivity and increased our costs. We are currently experiencing increasing labor costs, especially with regard to state certified electricians who are in short supply. We employ certain drug testing programs and take appropriate corrective actions that include terminating or suspending workers caught abusing drugs. This causes us to lose otherwise skilled workers and puts further pressure on what is already a tight labor supply. In addition, because of the shortage of experienced miners, we have hired novice miners, who are required to be accompanied by experienced workers as a safety precaution. These measures adversely affect the productivity of our workers as well as the operating efficiency of our mining complexes. If the shortage of experienced labor continues or worsens and if our labor costs continue to rise, it could have an adverse impact on our labor productivity and costs and our ability to expand production.

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

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

	•		unexpected geological and mining conditions which may not be fully identified by available exploration data or drill hole density and may differ from our experiences 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 regulation by governmental agencies.

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

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

     We conduct a significant part of our mining operations on properties that we lease. A title defect or the loss of any lease could adversely affect our ability to mine the associated reserves. Because title to most of our leased properties and mineral rights is not usually verified until we make a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property, our right to mine some of our reserves has in the past, and may again in the future, be adversely affected if defects in title or boundaries exist. In order to obtain leases or mining contracts to conduct our mining operations on property where these defects exist, we have had to, and may in the future have to, incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases or mining contracts for properties containing additional reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of

the lease. Some leases have minimum production requirements. Failure to meet those requirements could result in losses of prepaid royalties and, in some rare cases, could result in a loss of the lease itself.

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

     We depend upon barge, rail, truck and belt transportation systems to deliver coal to our customers. Disruption of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair our ability to supply coal to our customers, resulting in decreased shipments. Decreased performance levels over longer periods of time could cause our customers to look to other sources for their coal needs, negatively affecting our revenue and profitability. We have no long-term contracts with transportation providers to ensure consistent and reliable service. In addition, increases in transportation costs, including increases resulting from fluctuations in the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels such as natural gas or could make our coal production less competitive than coal produced in other regions of the United States or abroad. If there are disruptions of the transportation services provided by the railroad companies we use, or if rail transport costs rise significantly and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

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

     We continually seek to expand our operations and coal reserves through acquisitions of businesses and assets, including leases of coal reserves. Acquisitions involve various inherent risks, such as:

	•		uncertainties in assessing the value, strengths and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental liabilities) of, acquisition or other transaction candidates;
	•		the potential loss of key customers, management and employees of an acquired business;
	•		the ability to achieve identified operating and financial synergies anticipated to result from an acquisition or other transaction;
	•		problems that could arise from the integration of the acquired business; and
	•		unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the acquisition or other transaction rationale.

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

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

     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 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.

     We may not be able to mine all our reserves as profitably as we do at our current operations. Our planned development projects and acquisition activities may not result in significant additional reserves, and we may not have continuing success developing new mines or expanding existing mines beyond our existing reserve base. Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by our customers.

     Because the amount of coal in our reserves decline as we mine our coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. Replacement reserves may not be available when required or, if available, may not be available at commercially attractive prices or be

capable of being mined at comparable costs. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our profitability and financial condition. Exhaustion of reserves at particular mines also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

     Our profitability may be adversely affected by our commitments under long-term coal supply contracts and changes in purchasing patterns in the coal industry may make it difficult to extend existing contracts or to enter into long-term supply contracts.

     We sell a substantial portion of our coal under long-term coal supply agreements, which we define as contracts with a term greater than 12 months. The prices for coal shipped under these contracts is fixed for the initial year of the contract and may be subject to certain adjustments in later years. As a result, the prices for coal shipped under these contracts may be below the current market price for similar-type coal at any given time, depending on the timeframe of the contract execution or initiation. For the year ended December 31, 2005, we sold approximately 70% of the total tons sold pursuant to long-term coal supply agreements. As a consequence of the substantial volume of our sales that are subject to these long-term agreements, we have less coal available with which to capitalize on higher coal prices if and when they arise. In addition, in some cases, our ability to realize the higher prices that may be available in the open market may be restricted when customers elect to purchase higher volumes under some contracts.

     When the current contracts with customers expire or are otherwise renegotiated, our customers may decide not to extend or enter into new long-term contracts or, in the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including under different pricing terms. Furthermore, uncertainty caused by laws and regulations affecting electric utilities, including the Clean Air Act, could deter our customers from entering into long-term coal supply agreements. To the degree that we operate outside of long-term contracts, our revenues are subject to pricing in the coal open market, which can be significantly more volatile than the pricing structure negotiated through a long-term coal supply agreement. This volatility could adversely affect the profitability of our operations if open market pricing for coal becomes unfavorable. For additional information relating to these contracts, you should see “Business — Coal Supply Contracts” under Item 1.

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

     For the year ended December 31, 2005, we derived approximately 28% of our total coal revenues from sales to our three largest customers, Tennessee Valley Authority, Ameren and Intermountain Power Agency, and approximately 62% of our total coal revenues from sales to our ten largest customers. At December 31, 2005, the coal supply agreements with those ten customers expire at various times from 2006 to 2017. We intend to discuss the extension of existing agreements or entering into new long-term agreements with those and other customers, but the negotiations may not be successful, and those customers may not continue to purchase coal from us under long-term coal supply agreements, or at all. If any of those customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under the current agreements, our revenues and profitability could suffer materially.

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

     Coal supply agreements typically contain force majeure provisions allowing temporary suspension of performance by us or our customers during the duration of specified events beyond the control of the affected party. Most of the coal supply agreements also contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as heat value, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, purchasing replacement coal in the higher priced open market, the rejection of deliveries or, in the extreme, termination of the contracts. Consequently, due to the risks mentioned above with respect to long-term supply agreements, we may not achieve the revenue or profit we expect to achieve from these sales commitments.

     We have a significant amount of debt relative to our total capitalization, which limits our flexibility and imposes restrictions on us, and a downturn in economic or industry conditions may materially affect our ability to meet our future financial commitments and liquidity needs.

     As of December 31, 2005, we had consolidated indebtedness of approximately $960.2 million, representing approximately 58.3% of our total capitalization. We also have significant lease and royalty obligations. Our ability to satisfy our debt, lease and royalty obligations will depend upon our future operating performance, which will be affected by prevailing economic conditions in the markets that we serve and financial, business and other factors, many of which are beyond our control. 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 fund our future financial obligations or our other liquidity needs.

     The amount and terms of our debt could have material consequences to our business, including, but not limited to:

	•		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.

     Despite these significant levels of indebtedness, we may incur additional indebtedness in the future, which would heighten the risks described above.

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

     We are subject to long-term liabilities under a variety of benefit plans and other arrangements with current and former employees. These obligations have been estimated based on actuarial assumptions, including:

	•		actuarial estimates;
	•		assumed discount rates;
	•		estimates of mine lives;
	•		expected returns on pension plan assets; and
	•		changes in health care costs.

     If the assumptions relating to these benefits change in the future or are incorrect, we may be required to record additional expenses, which would reduce our profitability. In addition, future regulatory and accounting changes relating to these benefits could result in increased obligations or additional costs, which could also have a material adverse affect on our financial results. You should see Note 12 – Employee Benefit Plans to our consolidated financial statements included in Part IV, Item 15 of this Annual Report on Form 10-K for more information about these assumptions.

     Increased consolidation and competition within the coal industry may adversely affect our ability to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.

     During the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. According to the NMA, in 1994, the top ten coal producers accounted for approximately 45% of total domestic coal production. By 2004, however, the top ten coal producers’ share had increased to approximately 69% of total domestic coal production, according to the NMA. Consequently,

some of our competitors in the domestic coal industry are major coal producers who have greater financial resources than we do. The intense competition among coal producers may impact our ability to retain or attract customers and may, therefore, adversely affect our future revenue and profitability. Recent increases in coal prices could encourage the development of expanded coal producing capacity in the United States. Any resulting overcapacity from existing or new competitors could reduce coal prices and, therefore, our revenue.

     We may be unable to comply with restrictions imposed by our financing arrangements which could result in a default under these agreements.

     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, among other things, effect acquisitions or dispositions and incur additional debt. 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, the counterparties to our financing arrangements could 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, which could adversely affect 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. These bonds are typically re-priced annually but are non-cancellable by the surety. Surety bond issuers and holders may increase premiums associated with 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 that are required by state and federal law would affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal.

     Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations.

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

Risks Related to Environmental and Other Regulation

     Federal and state governments extensively regulate our mining operations, which imposes significant costs on us, and future regulations could increase those costs or limit our ability to produce and sell coal.

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

	•		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 costly and time-consuming and may delay commencement or continuation of exploration or production operations. Failure to comply with these regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we incur significant costs and liabilities, our business, financial condition and results of operations could be adversely affected. You should see “Business – Environmental Matters” under Item 1.

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

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

     Mining companies must obtain numerous permits that strictly 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, thereby precluding continuing or future mining operations. 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, or may 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.

     The Clean Air Act affects us and our customers, and could increase the cost of coal production and/or reduce the demand for coal as a fuel source and thereby cause our sales and profitability to decline.

     The Clean Air Act regulates coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through Clean Air Act permitting requirements and/or emission control requirements, including requirements relating to particulate matter. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxide, mercury and other

compounds emitted by coal-fired electricity generating plants. Clean Air Act requirements that may directly or indirectly affect our operations or those of our electric utility customer base, and which could cause them to reduce their coal usage, include:

	•		reduction of sulfur dioxide emissions imposed by Title IV of the Clean Air Act;
	•		reduction of sulfur dioxide, nitrogen oxide and ozone emissions under EPA National Ambient Air Quality Standards;
	•		reduction of nitrogen oxide emissions under the NOx SIP Call program;
	•		reduction of nitrous oxide, sulfur dioxide, and mercury emissions by power plants through “cap-and-trade” programs under the Clear Skies Initiative;
	•		reduction of sulfur dioxide and nitrogen oxide emissions under the Clean Air Interstate Rule;
	•		reduction of and permanent cap on mercury emissions from coal-fired power plants under the Utility Mercury Reductions Rule;
	•		potential reduction of carbon dioxide emissions that could result from ongoing state lawsuits against the EPA; and
	•		reduction requirements for regional haze around national parks and national wilderness areas.

     The potential negative effects of these emissions and other requirements on our business include:

	•		reduction in demand for our coal by electric utilities, our largest customers, due to increased compliance requirements, which could impose significant capital expenditure and costs on coal-fired electricity generation;
	•		reduction in demand for our coal due to decisions by our customers to replace outdated coal plants with, or to construct new plants using, alternative fuel technologies, due to increased capital expenditure, cost or permitting restrictions; and
	•		increased costs to us of coal mining and/or processing due to permitting requirements and/or emission control requirements relating to particulate matter.

     Any resulting decrease in the demand for our coal will adversely affect our business and our results of operations.

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

     SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations,” requires that retirement obligations be recorded as a liability based on fair value, which is calculated as the present value of the estimated future cash flows. In estimating future cash flows, we considered the estimated current cost of reclamation and applied inflation rates and a third-party profit, as necessary. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf. Our resulting liability could change significantly if actual costs differ from our assumptions.

     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 are not subject to material claims arising out of contamination at our facilities or other locations, but may incur such liabilities in the future.

     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.

     Judicial rulings affecting our operating activities could significantly increase our operating costs, discourage customers from purchasing our coal, and materially harm our financial condition and operating results.

     In addition, we often need to obtain permits to conduct operating activities. Some of these permits are “nationwide” permits (as opposed to individual permits) issued by the Army Corps of Engineers for dredging and filling in streams and wetlands. Lawsuits challenging the Army Corps of Engineers’ authority to issue Nationwide permits have been instituted by environmental groups. We cannot predict the final outcomes of those lawsuits. If mining methods at issue are limited or prohibited, it could significantly increase our operational costs, make it more difficult to economically recover a significant portion of our reserves and lead to a material adverse effect on our financial condition and results of operation. We may not be able to increase the price we charge for coal to cover higher production costs without reducing customer demand for our coal.

Item 1B. Unresolved Staff Comments.

     None.

Item 2. Properties.

     As of December 31, 2005, we owned or controlled primarily through long-term leases approximately 99,000 acres of coal land in Wyoming, 63,000 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 lease approximately 115,000 acres of our coal land from the federal government and approximately 28,000 acres of our coal land from various state governments. These governmental leases have terms expiring between 2007 and 2010 and are subject to readjustment and/or extension and to earlier termination for failure to meeting diligent development requirements. Our Sufco, Medicine Bow and Seminoe II loadout facilities are located on properties held under leases which expire at varying dates over the next thirty years. Most of the leases contain options to renew. Our remaining loadout facilities are located on property owned by us or for which we have a special use permit.

     Our subsidiaries currently own or lease the equipment utilized in their mining operations. You should see “Item 1. Business” for more information about our mining operations and mining complexes.

Our Reserves

     We estimate that we owned or controlled approximately 2.4 billion tons of proven and probable recoverable reserves at December 31, 2005. 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, 2005:

Total Assigned Reserves
(tonnage in millions)

		Total
		Assigned												Sulfur Content																								Mining Method								Past Reserve
		Recoverable												(lbs. per million Btus)												As Received				Reserve Control												Under-				Estimates
		Reserves				Proven				Probable				<1.2				1.2-2.5				>2.5				Btu per lb. (1)				Leased				Owned				Surface				ground				2003				2004
Wyoming			1,748				1,705				43				1,697				51				—				8,814				1,746				2				1,748				—				1,025				1,840
Utah			108				60				48				108				—				—				11,653				107				1				—				108				116				112
Colorado			74				56				18				73				1				—				11,866				72				2				—				74				85				80
Total			1,930				1,821				109				1,878				52				—				9,090				1,925				5				1,748				182				1,226				2,032

Total Unassigned Reserves
(tonnage 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			387				273				114				338				49				—				9,671				282				105				213				174
Utah			37				15				22				32				5				—				11,177				37				—				—				37
Colorado			56				45				11				55				1				—				11,498				55				1				—				56
Total			480				333				147				425				55				—				10,001				374				106				213				267

     As of December 31, 2005, approximately 4.6% 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 2006 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 lease bonus 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 95.6% consist of very low sulfur 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, 2005 was $498.5 million, consisting of $12.3 million of prepaid royalties and the $486.2 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.

     We periodically engage 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 2006.

Item 3. Legal Proceedings.

     The information required by this item is contained under the caption “Contingencies” appearing in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of this Annual Report on Form 10-K and is hereby incorporated by reference.

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,
		2005 (1) (2)				2004				2003				2002 (3)				2001 (4)
		(in thousands, except per share data)
Statement of Operations Data:
Coal sales revenue		$	1,126,742			$	735,162			$	500,555			$	492,191			$	468,137
Income from operations			186,061				83,275				62,710				49,824				60,370
Income before cumulative effect of accounting change			128,844				32,946				20,996				19,909				31,342
Cumulative effect of accounting change			—				—				(18,278	)			—				—
Net income			128,844			$	32,946			$	2,718			$	19,909			$	31,342
Balance Sheet Data:
Cash and cash equivalents		$	152			$	1,351			$	35,171			$	249			$	461
Receivable from Arch Coal, Inc.			869,056				677,934				351,866				333,825				259,822
Total assets			2,215,376				2,013,436				1,411,515				1,373,061				1,329,688
Total debt			960,247				961,613				700,000				675,000				675,000
Redeemable equity interests			5,647				4,971				4,746				4,733				4,667
Non-redeemable equity interests			677,795				543,058				471,890				469,241				455,742
Cash Flow Data:
Cash provided by (used in) operating activities		$	38,518			$	(203,464	)		$	66,357			$	68,080			$	29,758
Depreciation, depletion and amortization			98,347				80,703				63,053				69,388				66,493
Capital expenditures			108,600				78,313				27,322				51,360				32,142
Operating Data:
Tons sold			105,796				86,264				69,541				72,519				73,719
Tons produced			106,554				91,466				69,361				73,203				74,032
Average sales price (per ton)		$	10.65			$	8.52			$	7.20			$	6.79			$	6.35

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

     Executive Overview

     We focus on taking steps to improve earnings, strengthen cash generation and improve productivity at our large-scale mines. We are also seeking to enhance our position as a preferred supplier to U.S. power producers, acting as a reliable and ethical partner. We plan to focus on organic growth by continuing to develop our existing reserve base, and we plan to evaluate acquisitions that represent a good fit with our existing operations.

     Economic expansion and the high cost of competing fuels translated into strong coal demand throughout 2005. We estimate that coal-fueled electric generation increased 2.5% during 2005. In addition to increasing utilization at existing coal-fired power plants, U.S. power generators are moving forward with plans to build new coal plants. Already, projects have been announced that we believe could boost the installed coal-based generating units by approximately 80 gigawatts, or 25%, which could ultimately increase coal demand by as much as 300 million tons annually. In addition, interest in converting coal into transportation fuels and synthetic natural gas has increased from prior years.

     Meanwhile, coal production during 2005 struggled to keep pace with increased demand, with consumption outstripping supply for the third consecutive year, according to our estimates. We estimate that utility coal stockpiles ended 2005 at their lowest year-end levels in decades at approximately 33 days of supply, or 37% below the 15-year average. We believe stockpile levels are particularly low in the midwestern United States, where coal fuel costs have boosted wholesale power sales and rail disruptions have constrained coal deliveries. We believe that strong coal demand and continuing supply constraints will result in a multi-year effort to restore utility stockpiles to targeted levels, particularly in the midwestern United States traditionally served by coal producers operating in the Powder River Basin.

     Rail service disruptions experienced throughout the industry during 2004 continued for much of 2005 and resulted in missed shipments in both of our operating regions. Severe weather and the resulting maintenance efforts exacerbated the railroad disruptions already existing as a result of inadequate staffing at the railroads, equipment shortages and an overall increase in rail shipments. We expect continued challenges during 2006 due to rail shortages, and we continue to work with our customers and the railroads in an effort to minimize the impact of future disruptions.

Results of Operations

     Recent Developments

     On October 27, 2005, we conducted a precautionary evacuation of our West Elk mine after we detected elevated readings of combustion-related gases in an area of the mine where we had completed mining activities but had not yet removed all remaining longwall equipment. We have successfully controlled the combustion-related gases, re-entered and rehabilitated the mine, and we resumed longwall mining in late March 2006. We estimate that the financial impact of idling the mine and fighting the fire during the fourth quarter of 2005 was $33.3 million in reduced operating profit. We will continue to be negatively impacted during the first quarter of 2006 until the longwall is back in production and the mine is operating at full capacity.

     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, resulting in a gain of $43.3 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.

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

     The following discussion summarizes our operating results for the year ended December 31, 2005 and compares those results to our operating results for the year ended December 31, 2004.

     Revenues. The following table summarizes the number of tons we sold during the year ended December 31, 2005 and the sales associated with those tons 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	%

     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								% of Total
		2005				2004				2005				2004
		(Amounts in thousands)
Powder River Basin			87,597				75,069				82.8	%			87.0	%
Western Bituminous Region			18,199				11,195				17.2	%			13.0	%
Total			105,796				86,264				100.0	%			100.0	%

     Coal sales. The increase in our coal sales resulted from a combination of increased volumes, higher pricing, and the acquisition of Triton in the Powder River Basin on August 20, 2004 and the consolidation of Canyon Fuel in the Western Bituminous region beginning on July 31, 2004.

     Our volume in the Powder River Basin increased 16.7% during 2005 compared to 2004. In the Western Bituminous region, our volume increased 62.6% during the same period, despite the loss of production at the West Elk mine in the fourth quarter of 2005. In addition to an overall increase in demand, volumes in both regions also benefited from the acquisition and consolidation described above.

     Our per ton realizations increased due primarily to higher contract prices in both segments. In the Powder River Basin, our per ton realization increased 15.7% due to increased base pricing and above-market pricing on certain contracts acquired in our Triton acquisition as well as higher sulfur dioxide quality premiums resulting from higher sulfur dioxide emission allowance prices. The Western Bituminous region’s per ton realization increased 24.7%. In addition to higher contract pricing, per ton realization in the Western Bituminous region was also affected by our consolidation of Canyon Fuel during the third quarter of 2004.

     Operating costs and expenses. The following table summarizes our operating costs and expenses for 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)
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	%
		$	988,065			$	675,531			$	312,534				46.3	%

     Cost of coal sales. The increase in cost of coal sales is primarily due to the acquisition of Triton in the Powder River Basin on August 20, 2004 and the consolidation of Canyon Fuel in the Western Bituminous region beginning on July 31, 2004, along with an increase in sales-sensitive costs resulting from the increase in revenue discussed above. In addition to the acquisition of Triton and the consolidation of Canyon Fuel during the third quarter of 2004, our costs of coal sales were affected by the following:

	•		Production taxes and coal royalties, which we incur as a percentage of coal sales realization, increased $79.9 million during 2005 compared to 2004.
	•		Labor costs increased $57.9 million during 2005 compared to 2004 due to higher compensation rates and due to the acquisition and consolidation in 2004 described above.
	•		Repair and maintenance costs increased $36.3 million during 2005 compared to 2004 due to increased repair and maintenance activity in 2005 resulting from the acquisition and consolidation in 2004 described above.

	•		Costs for diesel fuel, explosives and utilities increased $18.2 million, $6.4 million and $5.2 million, respectively, in 2005 compared to 2004 as a result of higher commodity pricing and increased usage resulting from the acquisition and consolidation in 2004 described above.
	•		Costs for operating supplies increased $22.3 million due partially to increased steel prices during 2005 compared to 2004 and increased usage resulting from the acquisition and consolidation in 2004 described above.

     Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization is due primarily to the property additions resulting from the acquisition and consolidation 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, Inc. The cost increase for the year ended 2005 compared to the 2004 is a result of increased compensation-related expenses and increased legal and professional fees at Arch Coal.

     Our operating costs (reflected below on a per-ton basis) are defined as including all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs) and all depreciation, depletion and amortization attributable to mining operations.

		Year Ended December 31,								Increase (Decrease)
		2005				2004				$				%
Powder River Basin		$	6.97			$	6.14			$	0.83				13.5	%
Western Bituminous Region			16.40				15.71				0.69				4.4	%

      Powder River Basin — On a per ton basis, operating costs increased in the Powder River Basin primarily due to higher diesel fuel costs ($0.14 per ton), higher repairs and maintenance costs ($0.11 per ton) and increased production taxes and coal royalties ($0.44 per ton). 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 offset by increased productivity had rail service not adversely impacted volumes during the year.

      Western Bituminous Region — Operating cost per ton increased primarily due to the West Elk thermal event noted in “Recent Developments.” As a result of the temporary idling of the mine, we incurred higher expenses along with reduced production.

      Other operating income. The following table summarizes our other operating income for the year ended December 31, 2005 and compares that information to the comparable information for the year ended December 31, 2004:

		Year Ended December 31,								Increase (Decrease)
		2005				2004				$				%
		(Amounts in thousands)
Income from equity investments		$	—			$	8,410			$	(8,410	)			(100.0	)%
Gain on sale of Powder River Basin assets			43,297				—				43,297				100.0	%
Other operating income			4,087				15,234				(11,147	)			(73.2	)%
		$	47,384			$	23,644			$	23,740				100.4	%

     Income from equity investment. The decline in income from our equity investment results from the consolidation of Canyon Fuel into our financial statements subsequent to July 31, 2004.

     Other operating income. Other operating income consists of income from sources other than coal sales. The increase in other operating income resulted primarily from the $43.3 million gain we recognized on a transaction with Peabody Energy discussed in “Recent Developments.” During 2004, we had gains on land sales of $5.8 million along with production and administration payments received from Canyon Fuel of $4.8 million. The production and administration payments from Canyon Fuel ceased subsequent to the consolidation of Canyon Fuel in our financial statements.

     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	%
		$	(20,310	)		$	(35,012	)		$	14,702				42.0	%

     Interest expense. The increase in interest expense results from a higher amount of average borrowings in 2005 compared to 2004 primarily due to the issuance of $250.0 million of 6³/4% senior notes due 2013 in October 2004. You should see “Liquidity and Capital Resources” for more information about the issuance of these notes.

     Interest income. Our cash transactions are managed by Arch Coal, Inc. Cash paid to or from us that is not considered a distribution or a contribution is recorded as a receivable from Arch Coal. The receivable balance earns interest from Arch Coal at the prime interest rate. The increase in interest income results primarily from a higher average receivable balance in 2005 as compared to 2004.

     Other non-operating income and expense. The following table summarizes our other non-operating income and 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)
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps		$	(12,688	)		$	(14,295	)		$	1,607				11.2	%

     Amounts reported as non-operating consist of income or expense resulting from our financing activities other than interest. Our results of operations include expenses of $12.7 million for 2005 and $13.6 million for 2004 related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred. Additionally, we incurred expenses of $0.7 million for early debt extinguishment costs in 2004.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

     The following discussion summarizes our operating results for the year ended December 31, 2004 and compares those results to our operating results for the year ended December 31, 2003.

     Revenues. The following table summarizes the number of tons we sold during the year ended December 31, 2004 and the sales associated with those tons and compares those results to the comparable information for the year ended December 31, 2003:

		Year Ended December 31,								Increase (Decrease)
		2004				2003				$				%
		(Amounts in thousands, except per ton data)
Coal sales		$	735,162			$	500,555			$	234,607				46.9	%
Tons sold			86,264				69,541				16,723				24.0	%
Coal sales realization per ton sold		$	8.52			$	7.20			$	1.32				18.3	%

     The following table shows the number of tons sold by operating segment during the year ended December 31, 2004 and compares those amounts to the comparable information for the year ended December 31, 2003:

		Tons Sold								% of Total
		2004				2003				2004				2003
		(Amounts in thousands)
Powder River Basin			75,069				62,625				87.0	%			90.1	%
Western Bituminous Region			11,195				6,916				13.0	%			9.9	%
Total			86,264				69,541				100.0	%			100.0	%

     Coal sales. The increase in coal sales resulted from the combination of increased volumes, higher pricing and the acquisition of Triton and the consolidation of Canyon Fuel during the third quarter of 2004.

     Our volume in the Powder River Basin increased 19.9%. In the Western Bituminous region, our volume increased 61.9%. In addition to an overall increase in demand, volumes in both regions also benefited from the acquisition and consolidation in 2004 described above.

     Our per ton realizations increased due primarily to higher contract prices in both segments. In the Powder River Basin, our per ton realization increased 14.1% due to above-market pricing on certain contracts acquired in the

Triton acquisition. The Western Bituminous region’s per ton realization increased 13.3%. In addition to higher contract pricing, per ton realization in the Western Bituminous region was also affected by our consolidation of Canyon Fuel beginning in the third quarter of 2004.

      Operating costs and expenses. The following table summarizes our operating costs and expenses for the year ended December 31, 2004 and compares those results to the comparable information for the year ended December 31, 2003:

		Year Ended December 31,								Increase (Decrease)
		2004				2003				$				%
		(Amounts in thousands)
Cost of coal sales		$	577,660			$	392,840			$	184,820				47.0	%
Depreciation, depletion and amortization			80,703				63,053				17,650				28.0	%
Selling, general and administrative expenses			17,168				15,686				1,482				9.4	%
		$	675,531			$	471,579			$	203,952				43.2	%

     Cost of coal sales. The increase in cost of coal sales is primarily due to the increase in revenues discussed above. Our costs of coal sales were affected by the following:

	•		Consolidation of Canyon Fuel added $61.7 million for the months of August through December 2004.
	•		Excluding Canyon Fuel, production taxes and coal royalties (which are incurred as a percentage of coal sales realization) increased $48.1 million.
	•		Excluding Canyon Fuel, repairs and maintenance costs increased $15.3 million due partially to the property, plant and equipment additions resulting from the contribution of North Rochelle during the third quarter of 2004.
	•		Poor rail performance during 2004 resulted in missed shipments and disruptions in production. As many of our costs are fixed in nature, the reduced volume did not result in reduced overall costs.
	•		We experienced higher supply costs, primarily related to explosives (an increase of $6.4 million) and diesel fuel (an increase of $10.9 million).
	•		Costs for operating supplies increased $8.3 million due primarily to increased commodity and steel prices during the year.
	•		Incentive compensation costs increased $3.7 million for amounts expected to be earned under Arch Coal’s annual and long-term incentive plans based on operating results for the year ended December 31, 2004.

     Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization is due primarily to the property additions resulting from the consolidation of Canyon Fuel and the acquisition of Triton during the third quarter of 2004.

     Selling, general and administrative expenses. Selling, general and administrative expenses represent expenses allocated to us from Arch Coal, Inc. The cost increase for the year ended 2004 compared to the prior year is a result of increased legal and professional fees and increases in compensation-related expenses at Arch Coal.

     Our operating costs (reflected below on a per-ton basis) are defined as including all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs) and all depreciation, depletion and amortization attributable to mining operations.

		Year Ended December 31,								Increase (Decrease)
		2004				2003				$				%
Powder River Basin		$	6.14			$	5.50			$	0.64				11.6	%
Western Bituminous Region		$	15.71			$	15.42			$	0.29				1.9	%

     Powder River Basin — On a per-ton basis, operating costs increased in the Powder River Basin primarily due to increased production taxes and coal royalties ($0.31 per ton), higher repairs and maintenance charges ($0.11 per ton) and to the higher explosives and diesel fuel costs discussed above. Additionally, average costs were higher due to the integration of the North Rochelle mine into our Black Thunder mine.

     Western Bituminous Region — Operating cost per ton at our Western Bituminous operations increased primarily due to increased repairs and maintentance costs, increased production taxes and coal royalties and disruptions in production caused by poor rail performance. The consolidation of Canyon Fuel in July 2004 offset some of the per

ton operating cost increases as the Canyon Fuel operations have slightly lower costs when compared to our other Western Bituminous operations.

     Other operating income. The following table summarizes our other operating income for the year ended December 31, 2004 and compares that information to the comparable information for the year ended December 31, 2003:

		Year Ended December 31,								Increase (Decrease)
		2004				2003				$				%
		(Amounts in thousands)
Income from equity investments		$	8,410			$	19,707			$	(11,297	)			(57.3	)%
Other operating income			15,234				14,027				1,207				8.6	%
		$	23,644			$	33,734			$	(10,090	)			(29.9	)%

     Income from equity investment. The decline in income from our equity investment results from the consolidation of Canyon Fuel into our financial statements subsequent to July 31, 2004, lower production and sales levels at Canyon Fuel during the period when we accounted for our investment under the equity method, and additional costs related to idling the Skyline Mine, including the severance costs noted above.

     Other operating income. Other operating income consists of income from sources other than coal sales. The increase results primarily from a $5.8 million gain recognized from a land sale offset partially by a $3.7 million decrease in administration charges and production payments received from Canyon Fuel (these payments ceased as of the July 31, 2004 consolidation of Canyon Fuel in our financial statements).

     Net interest expense. The following table summarizes our net interest expense for the year ended December 31, 2004 and compares that information to the comparable information for the year ended December 31, 2003:

										Increase (Decrease)
		Year Ended December 31,								in Net Income
		2004				2003				$				%
		(Amounts in thousands)
Interest expense		$	(55,582	)		$	(44,681	)		$	(10,901	)			(24.4	)%
Interest income			20,570				14,638				5,932				40.5	%
		$	(35,012	)		$	(30,043	)		$	(4,969	)			16.5	%

     The increase in interest expense resulted from a higher average interest rate in the first six months of 2004 as compared to the same period in 2003 as well as a higher amount of average borrowings from August through December 2004 as compared to the prior year. In 2004, our outstanding borrowings consisted primarily of fixed rate borrowings, while borrowings in the first half of 2003 were primarily variable rate borrowings. Short-term interest rates in 2003 were lower than the fixed rate borrowing that made up the majority of average debt balances in 2004.

     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 as a receivable from Arch Coal. The receivable balance earns interest from Arch Coal at the prime interest rate. The increase in interest income results primarily from a higher average receivable balance in 2004 as compared to 2003.

     Other non-operating income and expense. The following table summarizes our other non-operating income and expense for the year ended December 31, 2004 and compares that information to the comparable information for the year ended December 31, 2003:

										Increase (Decrease)
		Year Ended December 31,								in Net Income
		2004				2003				$				%
		(Amounts in thousands)
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps		$	(14,295	)		$	(11,671	)		$	(2,624	)			(22.5	%)

     Amounts reported as non-operating consist of income or expense resulting from our financing activities other than interest. Our results of operations include expenses of $13.6 million for 2004 and $7.0 million for 2003 related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred. Additionally, we incurred expenses of $0.7 million in 2004 and $4.7 million in 2003 for early debt extinguishment costs.

     Cumulative Effect of Accounting Change. Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, which we refer to as FAS 143, which requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value at the time the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Application of FAS 143 resulted in a cumulative effect loss as of January 1, 2003 of $18.3 million.

     Liquidity and Capital Resources

     Our primary sources of cash include sales of our coal production to customers, sales of assets and debt 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, 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,
		2005				2004				2003
		(Amounts in thousands)
Cash provided by (used in):
Operating activities		$	38,518			$	(203,464	)		$	66,357
Investing activities			(39,652	)			(86,897	)			(40,018	)
Financing activities			(65	)			256,541				8,583

     The increase in cash provided by operating activities in 2005 resulted from improved operating performance, the inclusion of a full year of results for the contribution of the North Rochelle assets, which occurred on August 20, 2004, and to the consolidation of Canyon Fuel which occurred beginning July 31, 2004 and to the significant increase in our receivable from Arch Coal in 2004 which resulted from the borrowings that we made in 2004 that were loaned to Arch Coal. Cash used in operating activities during 2004 was $203.5 million, compared to cash provided by operating activities of $66.4 million during 2003. The decrease is primarily due to an increase in our receivable from Arch Coal. This decrease is also a result of increased cash used for working capital purposes. Trade accounts receivable increased $5.1 million (excluding amounts contributed with the North Rochelle assets) in 2004 due primarily to higher sales levels during the period, as revenues have increased approximately 47% in 2004 as compared to 2003. Additionally, inventory increased $5.0 million (excluding amounts contributed with the North Rochelle assets) in 2004.

     Cash used in investing activities decreased during 2005 compared to 2004 as a result of the sale of the rail spur, rail loadout and idle office complex described earlier which resulted in proceeds of $79.6 million. 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 used in investing activities for 2004 consisted of capital expenditures of $78.3 million and additions to prepaid royalties of $14.6 million. Cash used in investing activities for the year ended December 31, 2003 consisted of capital expenditures of $27.3 million and additions to prepaid royalties of $12.7 million. The increase in capital expenditures was primarily at our Black Thunder Mine, which was comprised of equipment from the North Rochelle integration and certain assets that were bought out of lease arrangements.

     Cash provided by financing activities in 2004 consisted primarily of proceeds from the issuance of senior notes of $261.9 million (as described more fully below). Cash provided by financing activities in 2003 represents the net proceeds resulting from the issuance of the $700.0 million of senior notes and the repayment of our term loans (as described below).

      Capital expenditures are made 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 2006 will range from $200 to $250 million. This estimate includes capital expenditures related to development work at certain of our mining operations, including the development of the North Lease of the Skyline mine in Utah. Also, 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, cash generated from operations and, if necessary, cash from Arch Coal.

     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. The receivable from Arch Coal was $869.1 million at December 31, 2005, $677.9 million at December 31, 2004 and $351.9 million at December 31, 2003. The receivable is interest bearing and is payable on demand by us. However, we do not intend to demand payment of the receivable within the next year. Therefore, the receivable is classified on the consolidated balance sheets as long-term.

     On August 20, 2004, we borrowed $100.0 million under our term loan facility, which was established on September 19, 2003. The $100.0 million was loaned to Arch Coal to help fund the Triton acquisition that occurred on August 20, 2004.

     On October 22, 2004, Arch Western Finance, LLC, on of our subsidiaries, issued $250 million of 6-3/4% senior notes due 2013 at a price of 104.75% of par. The notes form a single series with Arch Western Finance’s existing 6-3/4% senior notes due 2013, except that the new notes are subject to certain transfer restrictions and are not fully fungible with the existing notes. The net proceeds of the offering were used to repay and retire the outstanding indebtedness under our $100.0 million term loan maturing in 2007, with the remainder loaned to Arch Coal.

     On June 25, 2003, Arch Western Finance completed the offering of $700 million of senior notes and utilized the proceeds of the offering to repay our term loans. The senior notes bear a fixed rate of interest of 6.75% and are due in full on July 1, 2013. Interest on the senior notes is payable on January 1 and July 1 each year commencing January 1, 2004. The senior notes are guaranteed by us and certain of our subsidiaries and are secured by a security interest in our receivable from Arch Coal. The terms of the senior notes contain restrictive covenants that limit our ability to, among other things, incur additional debt, sell or transfer assets, and make investments.

     The terms of our operating agreement provide for a preferred return distribution in an amount equal to 4% of the preferred capital account balance, which was $2.4 million for each of the years ended December 31, 2005, 2004 and 2003. Preferred distributions made during the years ended December 31, 2005, 2004 and 2003 were $0.1 million in each year. Except for the preferred return distribution, distributions may generally be made at such times and in such amounts as our managing member determines. We made no distributions other than the preferred return in the years ended December 31, 2005, 2004 and 2003.

     Contractual Obligations

     The following is a summary of our significant contractual obligations as of December 31, 2005:

		Payments Due by Period
		2006				2007-2008				2009-2010				After 2010
		(Amounts in thousands)
Long-term debt, including related interest		$	—			$	—			$	—			$	960,246
Operating leases			18,667				34,139				21,003				28,948
Royalty leases			4,120				3,574				3,062				7,632
Unconditional purchase obligations			108,358				—				—				—
Total contractual obligations		$	131,145			$	37,713			$	24,065			$	996,826

     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.

     We believe that our on-hand cash balance, cash generated from operations and, if necessary, cash from Arch Coal will be sufficient to meet these obligations and our requirements for working capital and capital expenditures.

     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 bank letters of credit and 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, corporate guarantees (i.e. self bonds) and letters of credit to secure our financial obligations for reclamation, workers’ compensation, postretirement benefits, coal lease obligations and other obligations as follows as of December 31, 2005 (dollars in millions):

										Workers’
		Reclamation								Compensation				Retiree Healthcare
		Obligations				Lease Obligations				Obligations				Obligations				Other				Total
Self bonding		$	229.2			$	—			$	—			$	—			$	—			$	229.2
Surety bonds			68.1				22.3				0.1				—				8.7				99.2

     Contingencies

     The Federal Surface Mining Control and Reclamation Act of 1977 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 FAS 143. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at deep 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 other claims 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. Note 2 to our consolidated financial statements provides a description of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity:

Asset Retirement Obligations

     Our asset retirement obligations arise from the federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. We account for the costs of our reclamation activities in accordance with the provisions of FAS 143. We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. We determine estimates of disturbed acreage based on approved mining plans and related engineering data. We base our cost estimates on historical internal or third-party costs depending on how we expect to perform the work. We base productivity assumptions on historical experience with the equipment that we expect to utilize in the reclamation activities. In accordance with the provisions of FAS 143, we determine the fair value of our asset retirement obligations. In order to determine fair value, we must also estimate a discount rate and third-party margin. Each estimate is discussed in further detail below:

	•		Discount rate — FAS 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of FAS 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.
	•		Third-party margin — FAS 143 requires the measurement of an obligation to be based upon the amount a third-party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, we add a third-party margin to the estimated costs of these activities. We estimate this margin based on our historical experience with contractors performing certain types of reclamation activities. The inclusion of this margin results in a recorded obligation that exceeds our estimated cost to perform the reclamation activities with internal resources. If our cost estimates are accurate, we record the excess of the recorded obligation over the cost incurred to perform the work as a gain at the time that we complete the reclamation work.

     On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revisions to cost estimates and productivity assumptions, to reflect current experience. At December 31, 2005, we had recorded asset retirement obligation liabilities of $144.4 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2005, we estimate that the aggregate undiscounted cost of final mine closure is approximately $310.9 million.

Derivative Financial Instruments

     Derivative financial instruments are accounted for in accordance with Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, which we refer to as FAS 133. FAS 133 requires all derivative financial instruments to be reported on the balance sheet at fair value. Changes in fair value are recognized either in earnings or equity, depending on whether the transaction qualifies for hedge accounting, and if so, the nature of the underlying exposure being hedged and how effective the derivatives are at offsetting price movements in the underlying exposure.

     We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking various hedge transactions. We evaluate the effectiveness of our hedging relationships both at the hedge inception and on an ongoing basis. Any ineffectiveness is recorded in the Consolidated Statements of Income.

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 their 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 their postretirement plans.

     The impact of a 1/2% change in any of these assumptions would not be significant to our results of operations.

Accounting Standards Issued and Not Yet Adopted

     In November 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 151, Inventory Costs, an amendment of ARB No. 43, Chapter 4. This statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). Provisions of this statement are effective for fiscal years beginning after June 15, 2005. We do not expect the adoption of this statement to have a material impact on our financial statements.

     In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123 (revised 2004). Share-Based Payment, which we refer to as FAS 123R. FAS 123R requires all public companies to measure compensation cost in the income statement for all share-based payments (including employee stock options) at fair value for interim and annual periods. On April 14, 2005, the Securities and Exchange Commission delayed the implementation of FAS 123R from its original implementation date by six months for most registrants, requiring all public companies to adopt FAS 123R no later than the beginning of the first fiscal year beginning after June 15, 2005. Certain of our employees are granted share-based awards under the Arch Coal Plans. We adopted FAS 123R on January 1, 2006 using the modified-prospective method. Under this method, companies are required to recognize compensation cost for share-based payments to employees based on their grant-date fair value from the beginning of the fiscal period in which the recognition provisions are first applied. Measurement and recognition of compensation cost for awards that were granted prior to, but not vested as of, the date FAS 123R is adopted would be based on the same estimate of the grant-date fair value and the same recognition method used previously under FAS 123. FAS 123R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption. The effect of FAS 123R will not be significant.

     On March 30, 2005, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force on 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 have associated stripping costs at our surface mining operations with the cost of tons of coal uncovered and have classified tons uncovered buy not yet extracted as coal inventory. The guidance in this issue is effective for fiscal years beginning after December 15, 2005 for which the cumulative effect of adoption should be recognized as an adjustment to the beginning balance of retained earnings during the period. We adopted the change on January 1, 2006 and, accordingly, recognized an adjustment to the beginning balance of retained earnings of $37.6 million.

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

     We are exposed to market risk associated with interest rates. At December 31, 2005, 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 outstanding term loans. The swap agreements essentially convert variable-rate debt to fixed-rate debt. These agreements required the exchange of amounts based on variable interest rates for amounts based on fixed rates overt the life of the agreement. We terminated these swaps in the fourth quarter of 2005. The discussion below presents the sensitivity of the market value of our financial instruments to selected changes in market rates and prices. The range of changes reflects our view of changes that are reasonably possible over a one-year period. Market values are the present value of projected future cash flows based on the market rates and prices chosen. The major accounting policies for these instruments are described in Note 2 to our consolidated financial statements.

Item 8. Financial Statements and Supplementary Data.

     Reference is made to Part IV, Item 15 of this Annual Report on Form 10-K for the information required by Item 8.

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, 2005. 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, 2005 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 and Executive Officers of the Registrant.

     The information contained under the caption “Management” in “Business” in Part I, Item 1 of this Annual Report on Form 10-K is hereby incorporated by reference.

     The following is a list of directors of Arch Coal, Inc. other than Messrs. Eaves and Leer, whose biographical information is contained under the caption “Management” in “Business” in Part I, Item 1 of this Annual Report on Form 10-K, their ages and biographical information:

     James R. Boyd, 59, Chairman of the Board, has been a director of Arch Coal, Inc. since 1990. 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 The Farmers Bank of Lynchburg, Tennessee.

     Frank M. Burke, 66, has been a director of Arch Coal, Inc. 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.), and Crosstex Energy, Inc., and is a member of the National Petroleum Council.

     Patricia F. Godley, 57, has been a director of Arch Coal, Inc. 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, 52, has been a director of Arch Coal, Inc. 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.

     Thomas A. Lockhart, 70, has been a director of Arch Coal, Inc. 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, 69, has been a director of Arch Coal, Inc. 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, 66, has been a director of Arch Coal, Inc. 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, 60, has been a director of Arch Coal, Inc. 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, 63, 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.

     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 $869.1 million at December 31, 2005 and $677.9 million at December 31, 2004. This amount earns interest from Arch Coal at the prime interest rate. Interest earned was $44.8 million in 2005, $20.5 million in 2004 and $14.6 million in 2003. 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.

      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, 2004 and 2003 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 paid production royalties of $23.2 million in 2005, $11.5 million in 2004 and $9.2 million in 2003 to Arch Coal under sublease agreements.

      Amounts charged to the intercompany account for our allocated portion of pension and postretirement contributions totaled $12.9 million in 2005, $11.3 million in 2004 and $9.2 million in 2003.

     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 $24.0 million in 2005, $17.2 million in 2004 and $15.7 million in 2003. Such amounts are reported as selling, general and administrative expenses in the 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 and $8.5 million during 2003 in connection with these arrangements.

     Through 2003, we leased certain assets at our Thunder Basin mining complex from Little Thunder Leasing Company, a subsidiary of BP p.l.c. We paid Little Thunder Leasing Company $3.3 million during 2003 in connection with this lease.

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, Inc. 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 following consolidated financial statements and consolidated financial statement schedule are filed with this report beginning on page F-1:

     Consolidated Statements of Income – Years Ended December 31, 2005, 2004 and 2003

     Consolidated Balance Sheets – December 31, 2005 and 2004

     Consolidated Statements of Cash Flows – Years Ended December 31, 2005, 2004 and 2003

     Consolidated Statements of Non-Redeemable Members’ Equity – Years Ended December 31, 2005, 2004 and 2003

     Notes to Consolidated Financial Statements

     Schedule of Valuation and Qualifying Accounts.

     All other schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted.

     Exhibits filed as part of this Annual Report on Form 10-K are as follows:

Exhibit		Description
3.1		Certificate of Formation (incorporated herein by reference to Exhibit 3.3 to the Registration Statement on Form S-4 (Reg. No. 333-107569) filed by Arch Western Finance, LLC on August 1, 2003).
3.2		Limited Liability Company Agreement (incorporated herein by reference to Exhibit 3.4 to the Registration Statement on Form S-4 (Reg. No. 333-107569) filed by Arch Western Finance, LLC on August 1, 2003).
4.1		Indenture, dated as of June 25, 2003, by and among Arch Western Finance, LLC, Arch Coal, Inc., Arch Western Resources, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C., Thunder Basin Coal Company, L.L.C. and The Bank of New York, as trustee (incorporated herein by reference to Exhibit 4.1 to the Registration Statement on Form S-4 (Reg. No. 333-107569) filed by Arch Western Finance, LLC on August 1, 2003).
4.2		First Supplemental Indenture, dated October 22, 2004, by and among Arch Western Finance, LLC, Arch Western Resources, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C., Thunder Basin Coal Company, L.L.C. and The Bank of New York, as trustee (incorporated herein by reference to Exhibit 4.4 of the Current Report on Form 8-K filed by the registrant on October 23, 2004).
4.3		Form of 63/4% Senior Notes due 2013 (included in Exhibit 4.1).
4.4		Form of Guarantee of 63/4% Senior Notes due 2013 (included in Exhibit 4.1).
4.5		Registration Rights Agreement, dated October 22, 2004, among Arch Coal, Inc., Arch Western Resources, LLC, Arch Western Finance, LLC, Triton Coal Company, LLC, Arch Western Bituminous Group, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C. and Thunder Basin Coal Company, L.L.C. and Citigroup Global Markets Inc., J.P. Morgan Securities Inc. and Morgan Stanley & Co. Incorporated, as representatives of the initial purchasers named therein (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by the registrant on October 23, 2004).

Exhibit		Description
10.1		Federal Coal Lease dated as of June 24, 1993 between the United States Department of the Interior and Southern Utah Fuel Company (incorporated herein by reference to Exhibit 10.17 of Arch Coal, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1998).
10.2		Federal Coal Lease between the United States Department of the Interior and Utah Fuel Company (incorporated herein by reference to Exhibit 10.18 of Arch Coal, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1998).
10.3		Federal Coal Lease dated as of July 19, 1997 between the United States Department of the Interior and Canyon Fuel Company, LLC (incorporated herein by reference to Exhibit 10.19 of Arch Coal, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1998).
10.4		Federal Coal Lease dated as of January 24, 1996 between the United States Department of the Interior and the Thunder Basin Coal Company (incorporated herein by reference to Exhibit 10.20 of Arch Coal, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1998).
10.5		Federal Coal Lease Readjustment dated as of November 1, 1967 between the United States Department of the Interior and the Thunder Basin Coal Company (incorporated herein by reference to Exhibit 10.21 of Arch Coal, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1998).
10.6		Federal Coal Lease effective as of May 1, 1995 between the United States Department of the Interior and Mountain Coal Company (incorporated herein by reference to Exhibit 10.22 of Arch Coal, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1998).
10.7		Federal Coal Lease dated as of January 1, 1999 between the Department of the Interior and Ark Land Company (incorporated herein by reference to Exhibit 10.23 of Arch Coal, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1998).
10.8		Federal Coal Lease dated as of October 1, 1999 between the United States Department of the Interior and Canyon Fuel Company, LLC (incorporated herein by reference to Exhibit 10 of Arch Coal, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999).
10.9		Federal Coal Lease effective as of March 1, 2005 by and between the United States of America and Ark Land LT, Inc. covering the tract of land known as “Little Thunder” in Campbell County, Wyoming (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed by Arch Coal, Inc. on February 10, 2005).
10.10		Modified Coal Lease (WYW71692) executed January 1, 2003 by and between the United States of America, through the Bureau of Land Management, as lessor, and Triton Coal Company, LLC, as lessee, covering a tract of land known as “North Rochelle” in Campbell County, Wyoming (incorporated by reference to Exhibit 10.24 to Arch Coal, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004).
10.11		Coal Lease (WYW71692) executed January 1, 1998 by and between the United States of America, through the Bureau of Land Management, as lessor, and Triton Coal Company, LLC, as lessee, covering a tract of land known as “North Roundup” in Campbell County, Wyoming (incorporated by reference to Exhibit 10.24 to Arch Coal, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004).
10.12		Master Lease and Sublease Agreement, dated effective as of April 1, 2005, by and between Ark Land Company, Ark Land LT, Inc., Thunder Basin Coal Company, L.L.C. and Triton Coal Company, LLC.
10.13		Amendment No. 1 to Master Lease and Sublease Agreement, dated effective as of December 30, 2005, by and between Ark Land Company, Ark Land LT, Inc., Thunder Basin Coal Company, L.L.C. and Triton Coal Company, LLC.
21.1		Subsidiaries of the registrant.
31.1		Rule 13a-14(a)/15d-14(a) Certification of Paul A. Lang.
31.2		Rule 13a-14(a)/15d-14(a) Certification of Robert J. Messey.
32.1		Section 1350 Certification of Paul A. Lang.

Exhibit		Description
32.2		Section 1350 Certification of Robert J. Messey.

Signatures

     Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		Arch Western Resources, LLC
		By:		/s/ Robert J. Messey
				Robert J. Messey
				Vice President
		March 30, 2006

     KNOW ALL PERSONS BY THESE PRESENTS: That each of the undersigned directors and the undersigned director/officer of Arch Western Resources, LLC, a Delaware limited liability company, hereby constitutes and appoints Robert G. Jones and Gregory A. Billhartz, and each of them, his or her true and lawful attorneys-in-fact and agents, with full power to act without the other, to sign Arch Western Resources, LLC’s Annual Report on Form 10-K for the year ended December 31, 2005, to be filed with the Securities and Exchange Commission under the provisions of the Securities Exchange Act of 1934, as amended; to file such Annual Report and the exhibits thereto and any and all other documents in connection therewith, including without limitation, amendments thereto, with the Securities and Exchange Commission; and to do and perform any and all other acts and things requisite and necessary to be done in connection with the foregoing as fully as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the dates indicated.

Signatures		Capacity		Date
/s/ Paul A. Lang		President
Paul A. Lang		(Principal Executive Officer)		March 30, 2006
/s/ Robert J. Messey         Robert J. Messey		Vice President (Principal Financial and Accounting Officer)		March 30, 2006
Arch Western Acquisition Corporation		Sole Managing Member		March 30, 2006

By:		/s/ Robert J. Messey
		Robert J. Messey, Vice President

Financial Statements and Supplementary Data

     The consolidated financial statements of Arch Western Resources, LLC and subsidiaries and related notes thereto and report of independent registered public accounting firm follow.

Index to Financial Statements of Arch Western Resources, LLC and Subsidiaries

Report of Independent Registered Public Accounting Firm		F-2
Consolidated Statements of Income for the Years Ended December 31, 2005, 2004 and 2003		F-3
Consolidated Balance Sheets at December 31, 2005 and 2004		F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		F-5
Consolidated Statements of Non-Redeemable Members’ Equity at December 31, 2005, 2004 and 2003		F-6
Notes to Consolidated Financial Statements		F-7
Financial Statement Schedule		F-30

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 (the Company) as of December 31, 2005 and 2004, and the related consolidated statements of income, non-redeemable membership interest and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

     In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Arch Western Resources, LLC at December 31, 2005 and 2004, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

				/s/ Ernst & Young LLP

St. Louis, Missouri
March 1, 2006

ARCH WESTERN RESOURCES, LLC

CONSOLIDATED STATEMENTS OF INCOME

		Year Ended December 31,
		2005				2004				2003
		(In thousands of dollars)
Revenues
Coal sales		$	1,126,742			$	735,162			$	500,555
Costs and Expenses
Cost of coal sales			865,760				577,660				392,840
Depreciation, depletion and amortization			98,347				80,703				63,053
Selling, general and administrative expenses			23,958				17,168				15,686
			988,065				675,531				471,579
Other Operating Income
Income from equity investment			—				8,410				19,707
Gain on sale of Powder River Basin assets			43,297				—				—
Other operating income			4,087				15,234				14,027
			47,384				23,644				33,734
Income from operations			186,061				83,275				62,710
Interest expense, net:
Interest expense			(65,543	)			(55,582	)			(44,681	)
Interest income, primarily from Arch Coal, Inc.			45,233				20,570				14,638
			(20,310	)			(35,012	)			(30,043	)
Other non-operating expense:
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps			(12,688	)			(14,295	)			(11,671	)
Income before cumulative effect of accounting change and minority interest			153,063				33,968				20,996
Minority interest			(24,219	)			(1,022	)			—
Cumulative effect of accounting change			—				—				(18,278	)
Net income		$	128,844			$	32,946			$	2,718
Net income attributable to redeemable membership interest		$	644			$	165			$	14
Net income attributable to non-redeemable membership interest		$	128,200			$	32,781			$	2,704