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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

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

For the fiscal year ended December 31, 2007

Commission file number: 333-107569-03

Arch Western Resources, LLC

(Exact name of registrant as specified in its charter)


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

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

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

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

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

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

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

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

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

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


Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ (Do not check if a smaller reporting company)		Smaller Reporting Company o

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

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

Table of Contents


	Page
Part I		1
Item 1. Business		1
Item 1A. Risk Factors		18
Item 1B. Unresolved Staff Comments		24
Item 2. Properties		24
Item 3. Legal Proceedings		26
Item 4. Submission of Matters to a Vote of Security Holders		26

Part II		26
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		26
Item 6. Selected Financial Data		27
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
Item 7A. Quantitative and Qualitative Disclosures About Market Risk		36
Item 8. Financial Statements and Supplementary Data		36
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		36
Item 9A(T). Controls and Procedures		36
Item 9B. Other Information		36

Part III		37
Item 10. Directors, Executive Officers and Corporate Governance		37
Item 11. Executive Compensation		38
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		38
Item 13. Certain Relationships and Related Transactions, and Director Independence		38
Item 14. Principal Accounting Fees and Services		39

Part IV		39
Item 15. Exhibits and Financial Statement Schedule		39
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

Cautionary Statements Regarding Forward-Looking Information

This document contains “forward-looking statements” — that is, statements related to future, not past, events. In this context, forward-looking statements often address our expected future business and financial performance, and often contain words such as “anticipates,” “believes,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “predicts,” “projects,” “seeks,” “should,” “will” or other comparable words and phrases. Forward-looking statements by their nature address matters that are, to different degrees, uncertain. We believe that the factors that could cause our actual results to differ materially include the factors that we describe under the heading “Risk Factors” beginning on page 18. Those risks and uncertainties include but are not limited to the following:

	•		market demand for coal and electricity;

	•		geologic conditions, weather and other inherent risks of coal mining that are beyond our control;

	•		availability and price of mining and other industrial supplies;

	•		availability of skilled employees and other workforce factors;

	•		our ability to acquire or develop coal reserves in an economically feasible manner;

	•		defects in title or the loss of a leasehold interest;

	•		railroad, barge, truck and other transportation performance and costs;

	•		our ability to successfully integrate the operations that we acquire;

	•		our ability to secure new coal supply arrangements or to renew existing coal supply arrangements;

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

	•		our ability to service our outstanding indebtedness;

	•		our ability to comply with the restrictions imposed by our financing arrangements;

	•		the availability and cost of surety bonds;

	•		terrorist attacks, military action or war;

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

	•		our ability to obtain and renew mining permits;

	•		future legislation and changes in regulations, governmental policies and taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxides, nitrogen oxides, particular matter or greenhouse gases;

	•		the accuracy of our estimates of reclamation and other mine closure obligations; and

	•		the existence of hazardous substances or other environmental contamination on property owned or used by us.

These factors should not be construed as exhaustive and should be read in conjunction with the other cautionary statements included in this document. These risks and 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.

Glossary of Selected Mining Terms

Certain terms that we use in this document are specific to the coal mining industry and may be technical in nature. The following is a list of selected mining terms and the definitions we attribute to them.


Assigned reserves		Recoverable reserves designated for mining by a specific operation.

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

Compliance coal		Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus, requiring no blending or other sulfur dioxide reduction technologies in order 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.

Dragline		A large machine used in surface mining to remove the overburden, or layers of earth and rock, covering a coal seam. The dragline has a large bucket, suspended by cables from the end of a long boom, which is able to scoop up large amounts of overburden as it is dragged across the excavation area and redeposit the overburden in another area.

Longwall mining		One of two major underground coal mining methods, generally employing two rotating drums pulled mechanically back and forth across a long face of coal.

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

Preparation plant		A facility used for crushing, sizing and washing coal to remove impurities and to prepare it for use by a particular customer.

Probable reserves		Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced.

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

Reclamation		The restoration of land and environmental values to a mining site after the coal is extracted. The process commonly includes “recontouring” or shaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers.

Recoverable reserves		The amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods and under current law.

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

Room-and-pillar mining		One of two major underground coal mining methods, utilizing continuous miners creating a network of “rooms” within a coal seam, leaving behind “pillars” of coal used to support the roof of a mine.

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

iii

PART I

Item 1. Business.

Introduction

We are a subsidiary of Arch Coal, Inc., one of the largest coal producers in the United States. At December 31, 2007, we operated six active mines located in two of the three major low-sulfur coal-producing regions of the United States. Federal and state environmental regulations affect the demand for certain types of coal by limiting the amount of sulfur dioxide that may be emitted as a result of combustion. Due to these regulations, we believe demand for low-sulfur coal exceeds demand for other types of coal. Consequently, we focus on mining, processing and marketing coal with low sulfur content. At December 31, 2007, we estimate that our proven and probable coal reserves had an average heat value of approximately 9,311 Btus and an average sulfur content of approximately 0.33%. As such, we estimate that approximately 95.0% of our proven and probable coal reserves consists of compliance coal.

We sell substantially all of our coal to power plants and industrial facilities. For the year ended December 31, 2007, we sold approximately 115.7 million tons of coal. The following chart shows the breakdown of our coal production by region for 2007, expressed as a percentage of the total tons we produced:

2007 Coal Production, by Region

In 2007, we sold approximately 74% of our coal under contracts with a term of more than one year. At December 31, 2007, the average volume-weighted remaining term of our long-term contracts was approximately four years, with remaining terms ranging from one to ten years. At December 31, 2007, we had a sales backlog, including a backlog subject to price reopener or extension provisions, of approximately 357.8 million tons.

We believe that rapid economic expansion in developing nations, particularly China and India, has increased global demand for coal. We expect coal exports from the United States to increase in response to growing global coal demand, particularly as some of the traditional coal export nations experience mine, port, rail and labor challenges. We estimate that higher domestic demand for coal and higher U.S. coal exports will positively influence domestic coal demand. Additionally, we expect decreased production, particularly in the Central Appalachian region of the United States, to adversely impact domestic coal supply in the coming years. We anticipate continuing demand growth and weaker coal supplies to exert upward pressure on coal pricing in the future. As a result, we have not yet priced a portion of the coal we plan to produce over the next several years in order to take advantage of expected price increases.

Our History

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

On July 31, 2004, Arch Coal purchased the 35% interest in Canyon Fuel Company, LLC not 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 a 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 owned all of the common equity of Triton Coal Company, LLC, and all of the preferred units of Triton for a purchase price of $382.1 million, including transaction costs and working capital adjustments. Following the acquisition, Arch Coal contributed the assets and liabilities of Triton’s North Rochelle mine (excluding coal reserves) to us. Following that contribution, we integrated the operations of the North Rochelle mine with our existing Black Thunder mine in the Powder River Basin.

On December 30, 2005, we sold to Peabody Energy Corp. 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

Global Coal Supply and Demand. Because of its availability, stability and affordability, coal is a major contributor to the global energy supply, providing approximately 40% of the world’s electricity, according to the World Coal Institute, which we refer to as the WCI. Coal is also used in producing approximately 64% of the world’s steel supply, according to the WCI. Coal reserves can be found in almost every country in the world, and approximately 50 countries are currently mining coal.

Coal is traded worldwide and can be transported to demand centers by ship and by rail. Worldwide coal production approximated 5.9 billion tons in 2006 and 5.4 billion tons in 2005, according to the WCI. China produces more coal than any other country in the world. Historically, Australia has been the world’s largest coal exporter, exporting more than 200 million tons in each of the last three years, according to the WCI. China, Indonesia and South Africa have also historically been significant exporters in the global coal markets, however, growing demand in China has resulted in declining coal exports and increasing coal imports. These trends have caused China to become a less significant seaborne coal supply source. In 2007, coal supply from other regions was similarly affected because of mine disruptions, train derailments and port congestion.

Growing demand for coal for power generation in many Asian countries has begun to strain global coal supplies. Seaborne coal trade increased 4.6% to approximately 806.9 million metric tons in 2007, according to SSY Consultancy & Research, Ltd. Seaborne trade into Asia increased approximately 9.1%, while European trade decreased approximately 4.3%. Demand in China is expected to grow rapidly, as the demand for electricity and the need for steel used in construction and automobile production increase.

U.S. Coal Consumption. In the United States, coal is used primarily by power plants to generate electricity, by steel companies to produce coke for use in blast furnaces and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. Coal consumption in the United States has increased from 398.1 million tons in 1960 to approximately 1.2 billion tons in 2007, based on information provided by the Energy Information Administration, which we refer to as the EIA.

Throughout the United States, coal has long been favored as a fuel to produce electricity because of its cost advantage and its availability. Since 1970, the use of coal to generate electricity in the United States has nearly tripled in response to growing electricity demand. According to the EIA, coal accounted for approximately 50% of U.S. electricity generation in 2007 and is projected to account for approximately 55% in 2030. By comparison, generation from natural gas is expected to peak at approximately 21% in 2018 before slowly declining. The following chart shows U.S. electricity generation by fuel source from 1980 through 2007 and the projected generation through 2030:

Electricty Generation by Fuel, 1980-2030
(in billion kilowatthours)

Source: EIA

According to the National Mining Association, which we refer to as the NMA, coal is the lowest-cost fossil fuel used in producing electricity. We estimate that the cost of generating electricity from coal is less than one-third of the cost of generating electricity from other fuels. According to the EIA, the average delivered cost of coal to electric power generators during the first ten months of 2007 was $1.77/mm Btus, which was $6.39/mm Btus less expensive than residual fuel oil and $5.28/mm Btus less expensive than natural gas.

The EIA projects that power plants will increase their demand for coal as demand for electricity increases. The EIA estimates that electricity demand will increase by at least 40% by 2030, despite continuing efforts throughout the United States to become more energy efficient. Coal consumption has generally grown at the pace of electricity growth because coal-fueled electricity generation is used in most cases to meet baseload requirements. We estimate that coal consumption for power generation increased approximately 1.7% in 2007 as a result of average economic growth and more favorable weather than in 2006. Historically, demand for electricity has generally grown in proportion to U.S. economic growth, as measured by gross domestic product. In 2007, real gross domestic product increased 2.2%, according to the U.S. Department of Commerce.

Demand for coal is broadly influenced by weather. Weather patterns requiring greater use of air-conditioning or heating translate into greater demand for coal-based electricity generation. According to the EIA, coal stockpiles at power plants represented an approximate 53-day supply at the end of 2007, compared to coal stockpiles representing an approximate 50-day supply at the end of 2006. We believe that some domestic power plants seek to protect against future supply disruptions by maintaining higher stockpile levels.

We believe that demand growth from new coal-fueled power plants represents an important element to the long-term outlook for coal. Planned new domestic coal-fueled electricity generation capacity announcements exceeded 24 gigawatts at December 31, 2007, equating to more than 84 million tons of additional annual coal demand, based on information obtained from the National Energy Technology Laboratory, which we refer to as the NETL, and our internal estimates. The NETL also estimates that, at December 31, 2007, approximately 17 gigawatts of generating capacity was under construction or in advanced stages of development in the United States at December 31, 2007. We expect a majority of these plants to be built over the next five years, translating into as much as 55 million tons of additional incremental annual coal demand.

Coal is expected to remain the fuel of choice for domestic power generation through at least 2030, according to the EIA. Through that time, we expect new technologies intended to lower emissions of mercury, sulfur dioxide, nitrogen oxide and particulate matter will be introduced into the power generation industry. We believe these technological advancements will help coal retain its role as a key fuel for electric power generation well into the future.

The other major market for coal is the steel industry. Coal is essential for iron and steel production. According to the WCI, approximately 64% of all steel is produced from iron made in blast furnaces that use coal. The steel industry uses metallurgical coal, which is distinguishable from other types of coal because of its high carbon content, low expansion pressure, low sulfur content and various other chemical attributes. As such, the price offered by steel makers for metallurgical coal is generally higher than the price offered by power plants and industrial users for steam coal. Rapid economic expansion in China, India and other parts of southeast Asia has significantly increased the demand for steel in recent years.

Prices for oil and natural gas in the United States have reached record levels because of increasing demand and tensions regarding international supply. Historically high oil and gas prices and global energy security concerns have increased government and private sector interest in converting coal into liquid fuel, a process known as liquefaction. Liquid fuel produced from coal can be refined further to produce transportation fuels, such as low-sulfur diesel fuel, gasoline and other oil products, such as plastics and solvents. Several coal-to-liquids projects are in the process of development. We also expect advances in technologies designed to convert coal into electricity through coal gasification processes and to capture and sequester carbon dioxide emissions from electricity generation and other sources. These technologies have garnered greater attention in recent years due to developing concerns about the impact of carbon dioxide on the global climate. We believe the advancement of coal-conversion and other technologies represents a positive development for the long-term demand for coal.

U.S. Coal Production. The United States produces approximately one-fifth of the world’s coal production and is the second largest coal producer in the world, exceeded only by China. Coal in the United States represents approximately 94% of the domestic fossil energy reserves with over 250 billion tons of recoverable coal, according to the U.S. Geological Survey. The U.S. Department of Energy estimates that current domestic recoverable coal reserves could supply enough electricity to satisfy domestic demand for more than 200 years. Coal production in the United States has increased from 434.3 million tons in 1960 to approximately 1.2 billion tons in 2007 based on information provided by EIA.

Western region — The western region includes, among other areas, the Powder River Basin and the Western Bituminous region. The Powder River Basin is located in northeastern Wyoming and southeastern Montana. Coal from this region has a very low sulfur content and a low heat value. The price of Powder River Basin coal is generally less than that of coal produced in other regions because Powder River Basin coal exists in greater abundance, is easier to mine and thus has a lower cost of production. In addition, Powder River Basin coal is generally lower in heat value, which requires some electric power generation facilities to blend it with higher Btu coal or retrofit some existing coal plants to accommodate lower Btu coal. The Western Bituminous region includes western Colorado, eastern Utah and southern Wyoming. Coal from this region typically has a low sulfur content and varies in heat value. According to the EIA, coal produced in the western United States increased from 408.3 million tons in 1994 to 618.3 million tons in 2007 as regulations limiting sulfur dioxide emissions have increased demand for low-sulfur coal over this period.

Appalachian region — The Appalachian region is divided into the north, central and southern Appalachian regions. Central Appalachia includes eastern Kentucky, Virginia and southern West Virginia. Coal mined from this region generally has a high heat value and low sulfur content. Northern Appalachia includes Maryland, Ohio, Pennsylvania and northern West Virginia. Coal from this region generally has a high heat value and a high sulfur content. According to the EIA, coal produced in the Appalachian region decreased from 445.4 million tons in 1994 to 379.6 million tons in 2007, primarily as a result of the depletion of economically attractive reserves, permitting issues and increasing costs of production.

Interior region — The Illinois basin includes Illinois, Indiana and western Kentucky and is the major coal production center in the interior region of the United States. Coal from the Illinois basin varies in heat value and has high sulfur content. Despite its high sulfur content, coal from the Illinois basin can generally be used by some electric power generation facilities that have installed pollution control devices, such as scrubbers, to reduce emissions. We anticipate that Illinois basin coal will play an increasingly vital role in the U.S. energy markets in future periods. Other coal-producing states in the interior region include Arkansas, Kansas, Louisiana, Mississippi, Missouri, North Dakota, Oklahoma and Texas. According to the EIA, coal produced in the interior region decreased from 179.9 million tons in 1994 to 150.2 million tons in 2007.

U.S. Coal Exports and Imports. Coal exports decreased from 71.4 million tons in 1994 to 58.6 million tons in 2007. As discussed above, as global consumption for coal has increased in recent years, countries such as China, Indonesia, South Africa and Russia have decided to retain a greater percentage of their coal production for

domestic consumption. This development, together with port congestion in Australia, historically the largest coal exporter in the world, and a weak U.S. dollar, has caused U.S. coal to become more attractive in global markets. We expect this trend to continue as global coal consumption continues to increase.

Historically, coal imported from abroad has represented a negligible share of total U.S. coal consumption. According to the EIA, coal imports increased from 8.9 million tons in 1994 to 36.3 million tons in 2007. Coal is imported into the United States primarily from Colombia, Indonesia 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 expect coal imports into the United States to decrease due to increasing demand in Europe.

Coal Mining Methods

The geological characteristics of our coal reserves largely determine the coal mining method we employ. We use two primary methods of mining coal: surface mining and underground mining.

Surface Mining. We use surface mining when coal is found close to the surface. We have included the identity and location of our surface mining operations in the table on page 7. In 2007, approximately 83% of the coal that we produced came from surface mining operations.

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

The following diagram illustrates a typical dragline surface mining operation:

Underground Mining. We use underground mining methods when coal is located deep beneath the surface. We have included the identity and location of our underground mining operations in the table on page 7. In 2007, approximately 17% of the coal that we produced came from underground mining operations.

Our underground mines are typically operated using longwall mining techniques. Longwall mining involves using mechanical shearers to extract coal from long rectangular blocks of medium to thick coal seams. Ultimate seam recovery using longwall mining techniques can exceed 75%. In longwall mining, we use continuous miners to develop access to these long rectangular coal blocks. Hydraulically powered supports temporarily hold up the roof of the mine while a rotating drum mechanically advances across the face of the coal seam, cutting the coal

from the face. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface. Once coal is extracted from an area, the roof is allowed to collapse in a controlled fashion. In 2007, approximately 17% of the coal that we produced came from underground mining operations generally using longwall mining techniques.

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

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

The treatments we employ depend on the properties of the extracted coal and its intended use. To remove impurities, we crush raw coal and classify it into various sizes. For the largest size fractions, we use dense media vessel separation techniques in which we float coal in a tank containing a liquid of specific gravity. Since coal is lighter than its impurities, it floats, and we can separate it from rock and shale. We treat fine and intermediate sized particles with dense medium cyclones, in which a liquid is spun at high speeds to separate coal from rock. Ultra fine coal is recovered by using screens that separate smaller coal particles from larger impurities. To minimize the moisture content in coal, we may process certain coal through a centrifuge. A centrifuge spins coal very quickly, causing water accompanying the coal to separate.

Our Mining Operations

At December 31, 2007, we operated six active mines at seven mining complexes located in the United States. We have two reportable business segments, which are based on the low-sulfur coal producing regions in the United States in which we operate — the Powder River Basin and the Western Bituminous region. These geographically distinct areas are characterized by geology, coal transportation routes to consumers, regulatory environments and coal quality. These regional similarities have caused market and contract pricing environments to develop by coal region and form the basis for the segmentation of our operations.

The following map shows the locations of our mining operations:

The following table provides a summary of information regarding our mining complexes at December 31, 2007, the total sales associated with these complexes for the years ended December 31, 2005, 2006 and 2007 and the total reserves associated with these complexes at December 31, 2007. The amount disclosed below for the total cost of property, plant and equipment of each mining complex does not include the costs of the coal reserves that we have assigned to an individual complex:


										Total Cost
										of Property,
										Plant and
				Tons Sold						Equipment
		Mining								at December		Assigned
Mining Complex	Mines	Equipment	Railroad	2005		2006		2007		31, 2007		Reserves
						(Million tons)				($ in millions)		(Million tons)
Powder River Basin:
Black Thunder	S	D, S	UP/BN		87.6		92.5		86.2	$	598.8		1,314.6
Coal Creek ⁽¹⁾	S	D, S	UP/BN		¾		3.1		10.2		143.0		214.4
Western Bituminous:
Arch of Wyoming ⁽²⁾	¾	¾	UP		¾		¾		¾		24.5		19.6
Dugout Canyon	U	LW, C	UP		4.9		4.2		4.0		122.0		29.0
Skyline ⁽¹⁾	U	LW, C	UP		¾		1.5		2.4		154.2		22.8
Sufco	U	LW, C	UP		7.5		7.4		6.7		229.0		51.3
West Elk	U	LW, C	UP		5.9		5.0		6.2		253.8		78.8

Totals					105.9		113.7		115.7	$	1,525.3		1,730.5


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


⁽¹⁾		In 2006, we resumed mining at our Coal Creek and Skyline complexes. We had idled the Coal Creek complex in 2000 and the Skyline complex in 2004.

⁽²⁾		The inactive surface mines at the Arch of Wyoming complex are in the final process of reclamation and bond release.

Powder River Basin. Our operations in the Powder River Basin are located in Wyoming and include two surface mining complexes. During 2007, these complexes sold approximately 96.4 million tons of compliance coal. We control approximately 1.8 billion tons of proven and probable coal reserves in the Powder River Basin.


Black Thunder		Black Thunder is a surface mining complex located on approximately 24,300 acres in Campbell County, Wyoming. We control a significant portion of the coal reserves through federal and state leases. The complex currently consists of six active pit areas, one owned loadout facility and one leased loadout facility. We ship all of the coal raw to our customers via the Burlington Northern Santa Fe and Union Pacific railroads. We do not process the coal mined at this complex. Each of the loadout facilities can load a 15,000-ton train in less than three hours.

Coal Creek		Coal Creek is a surface mining complex located on approximately 7,400 acres in Campbell County, Wyoming. We control a significant portion of the coal reserves through federal and state leases. The complex currently consists of two active pit areas and a loadout facility. We ship all of the coal raw to our customers via the Burlington Northern Santa Fe and Union Pacific railroads. We do not process the coal mined at this complex. The loadout facility can load a 15,000-ton train in less than three hours.

Western Bituminous. Our operations in the Western Bituminous region are located in southern Wyoming, Colorado and Utah and include four underground mining complexes and one surface mining complex that includes four inactive surface mines. During 2007, the mining complexes in the Western Bituminous region sold approximately 19.3 million tons of compliance coal. We control approximately 459.9 million tons of proven and probable coal reserves in the Western Bituminous region.


Arch of Wyoming		Arch of Wyoming is a surface mining complex located in Carbon County, Wyoming. The complex currently consists of four inactive surface mines located on approximately 29,900 acres that are in the final process of reclamation and bond release. In 2006, we began preliminary development of a new mining area located on approximately 30,100 acres. We control a significant portion of the coal reserves associated with this complex through federal, state and private leases. During 2007, we produced a minimal amount of coal attributable to the development of the new mining area.

Dugout Canyon		Dugout Canyon mine is an underground mining complex located on approximately 18,200 acres in Carbon County, Utah. We control a significant portion of the coal reserves through federal and state leases. The complex currently consists of a longwall, two continuous miner sections and a truck loadout facility. We ship all of the coal to our customers via the Union Pacific railroad or by highway trucks. We wash a portion of the coal we produce at a 400-ton-per-hour preparation plant. The loadout facility can load approximately 20,000 tons of coal per day into highway trucks. Coal shipped by rail is loaded through a third-party facility capable of loading an 11,000-ton train in less than three hours.

Skyline		Skyline is an underground mining complex located on approximately 12,400 acres in Carbon and Emery Counties, Utah. We control a significant portion of the coal reserves through federal leases and smaller portions through county and private leases. The complex currently consists of a longwall, a continuous miner section and a loadout facility. We ship all of the coal raw to our customers via the Union Pacific railroad or by highway trucks. We do not process the coal mined at this complex. The loadout facility can load a 12,000-ton train in less than four hours.

Sufco		Sufco is an underground mining complex located on approximately 25,200 acres in Sevier County, Utah. We control a significant portion of the coal reserves through federal and state leases. The complex currently consists of a longwall, three continuous miner sections and a loadout facility located approximately 80 miles from the mine. We ship all of the coal raw to our customers via the Union Pacific railroad or by highway trucks. We do not process the coal mined at this complex. The loadout facility can load an 11,000-ton train in less than three hours.


West Elk		West Elk is an underground mining complex located on approximately 17,900 acres in Gunnison County, Colorado. We control a significant portion of the coal reserves through federal and state leases. The complex currently consists of a longwall, three continuous miner sections and a loadout facility. We ship all of the coal raw to our customers via the Union Pacific railroad. We do not process the coal mined at this complex. The loadout facility can load an 11,000-ton train in less than three hours.

We also incorporate by reference the information about the operating results of each of our segments for the years ended December 31, 2007, 2006 and 2005 contained in Note 18 – Segment Information to our consolidated financial statements beginning on page F-1.

Transportation

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

Sales, Marketing and Customers

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

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

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

Long-Term Coal Supply Arrangements

We sell coal both under long-term contracts, the terms of which are more than one year, and on a current market or spot basis with terms of one year or less. In 2007, we sold approximately 74% of our coal under long-term supply arrangements. At December 31, 2007, the average volume-weighted remaining term of our long-term contracts was approximately four years, with remaining terms ranging from one to ten years.

We expect to sell a significant portion of our coal under long-term supply arrangements. We selectively renew or enter into new long-term supply arrangements when we can do so at prices that we believe are favorable. When our coal sales contracts expire or are terminated, we are exposed to the risk of having to sell coal into the spot market, where demand is variable and prices are subject to greater volatility.

Provisions permitting renegotiation or modification of coal sale prices are present in some of our more recently negotiated long-term contracts and usually occur midway through a contract or every two to three years,

depending upon the length of the contract. In some circumstances, either we have or our customer has the option to terminate the contract if the parties cannot agree on a new price.

Competition

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

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

Geographic Data

We market our coal principally to power plants and industrial facilities located in the United States. Coal sales to foreign customers for 2007, 2006 and 2005 were insignificant.

Safety and Environmental Regulations

Our operations, like operations of other coal companies, are subject to regulation, primarily by federal and state authorities, on matters such as: air quality standards; reclamation and restoration activities involving our mining properties; mine permits and other licensing requirements; water pollution; employee health and safety; the discharge of materials into the environment; management of materials generated by mining operations; storage of petroleum products; protection of wetlands and endangered plant and wildlife protection. Many of these regulations require registration, permitting, compliance, monitoring and self-reporting and may impose civil and criminal penalties for non-compliance.

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 over time. The possibility exists that new legislation or regulations may be adopted or that the enforcement of existing laws could become more stringent, causing coal to become a less attractive fuel source and reducing the percentage of electricity generated from coal. Future legislation or regulation or more stringent enforcement of existing laws may have a significant impact on our mining operations or our customers’ ability to use coal.

While it is not possible to accurately 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 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 business:

Clean Air Act. The federal Clean Air Act and similar state and local laws that regulate air emissions affect coal mining directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and/or emissions control requirements relating to particulate matter which may include controlling fugitive dust. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the emissions of fine particulate matter measuring 2.5 micrometers in diameter or smaller, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fueled power plants and industrial boilers, which are the largest end-users of our coal. Continued tightening of the already stringent regulation of emissions and regulation of additional emissions such as carbon dioxide or other greenhouse gases from coal-fueled power plants and industrial boilers could eventually reduce the demand for coal.

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

•

Acid Rain. Title IV of the Clean Air Act imposes a two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and applies to all coal-fueled power plants with a

			capacity of more than 25-megawatts. Generally, the affected power plants have sought to comply with these requirements by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading sulfur dioxide emissions allowances. Although we cannot accurately predict the future effect of this Clean Air Act provision on our operations, we believe that implementation of Phase II has resulted in, and will continue to result in, an upward pressure on the price of lower sulfur coals as coal-fueled power plants continue to comply with the more stringent restrictions of Title IV.
	•		Fine Particulate Matter. The Clean Air Act requires the U.S. Environmental Protection Agency, which we refer to as the EPA, to set national ambient air quality standards, which we refer to as NAAQS, for certain pollutants associated with the combustion of coal, including sulfur dioxide, particulate matter, nitrogen oxides and ozone. Areas that are not in compliance with these standards, referred to as non-attainment areas, must take steps to reduce emissions levels. For example, NAAQS currently exist for particulate matter measuring 10 micrometers in diameter or smaller (PM10) and for fine particulate matter measuring 2.5 micrometers in diameter or smaller (PM2.5). The EPA designated all or part of 225 counties in 20 states as well as the District of Columbia as non-attainment areas with respect to the PM2.5 NAAQS. Those designations have been challenged. Individual states must identify the sources of emissions and develop emission reduction plans. These plans may be state-specific or regional in scope. Under the Clean Air Act, individual states have up to twelve years from the date of designation to secure emissions reductions from sources contributing to the problem. Future regulation and enforcement of the new PM2.5 standard will affect many power plants, especially coal-fueled power plants, and all plants in non-attainment areas.

	•		Ozone. Significant additional emission control expenditures will be required at coal-fueled power plants to meet the current NAAQS for ozone. Nitrogen oxides, which are a byproduct of coal combustion, are classified as an ozone precursor. As a result, emissions control requirements for new and expanded coal-fueled power plants and industrial boilers will continue to become more demanding in the years ahead. For example, in 2004, the EPA designated counties in 32 states as non-attainment areas under the new standard. These states had until June 2007 to develop plans, referred to as state implementation plans, or SIPs, for pollution control measures that allow them to comply with the standards. The EPA described the action that states must take to reduce ground-level ozone in a final rule promulgated in November 2005. The rule is subject to judicial challenge, however, making its impact difficult to assess. In July 2007, the EPA proposed to make the current standard more stringent. If the EPA’s current rules are upheld and the EPA finalizes a more stringent ozone NAAQS, additional emission control expenditures will likely be required at coal-fueled power plants.

	•		NOx SIP Call. The NOx SIP Call program was established by the EPA in October 1998 to reduce the transport of ozone on prevailing winds from the Midwest and South to states in the Northeast, which said that they could not meet federal air quality standards because of migrating pollution. The program is designed to reduce nitrous oxide emissions by one million tons per year in 22 eastern states and the District of Columbia. Phase II reductions were required by May 2007. As a result of the program, many power plants have been or will be required to install additional emission control measures, such as selective catalytic reduction devices. Installation of additional emission control measures will make it more costly to operate coal-fueled power plants, thereby making coal a less attractive fuel.

	•		Clean Air Interstate Rule. The EPA finalized the Clean Air Interstate Rule, which we refer to as CAIR, in March 2005. CAIR calls for power plants in 29 eastern states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrous oxide. The rule requires states to regulate power plants under a cap and trade program similar to the system now in effect for acid deposition control and to that proposed by the Clean Skies Initiative. When fully implemented, the rule is expected to reduce regional sulfur dioxide emissions by over 70% and nitrogen oxides emissions by over 60% from 2003 levels. The stringency of the cap may require some coal-fueled power plants to install additional pollution control equipment, such as wet scrubbers, which could decrease the demand for low-sulfur coal at these plants and thereby potentially reduce market prices for low-sulfur coal. Emissions are permanently capped and cannot increase. The rule is also subject to judicial challenge, which makes its impact difficult to assess.

	•		Mercury. In February 2008, the United States Court of Appeals for the District of Columbia Circuit vacated the EPA’s Clean Air Mercury Rule, which we refer to as CAMR, and remanded it to the EPA for reconsideration. The EPA is reviewing the court decision and evaluating its impacts. Before the court

			decision, some states had either adopted CAMR or adopted state-specific rules to regulate mercury emissions from power plants that are more stringent than CAMR. CAMR, as promulgated, would have permanently capped and reduced mercury emissions from coal-fueled power plants by establishing mercury emissions limits from new and existing coal-fueled power plants and creating a market-based cap-and-trade program that was expected to reduce nationwide emissions of mercury in two phases. Under CAMR, coal-fueled power plants would have had until 2010 to cut mercury emission levels to 38 tons a year from 48 tons and until 2018 to bring that level down to 15 tons, a 69% reduction. Regardless of how the EPA responds on reconsideration or how states implement their state-specific mercury rules, rules imposing stricter limitations on mercury emissions from power plants will likely be promulgated and implemented. Any such rules may adversely affect the demand for coal.

	•		Carbon Dioxide. In February 2003, a number of states notified the EPA that they planned to sue the agency to force it to set new source performance standards for electric utility emissions of carbon dioxide and to tighten existing standards for sulfur dioxide and particulate matter for utility emissions. In April 2007, the U.S. Supreme Court rendered its decision in Massachusetts v. EPA, finding that the EPA has authority under the Clean Air Act to regulate carbon dioxide emissions from automobiles and can decide against regulation only if the EPA determines that carbon dioxide does not significantly contribute to climate change and does not endanger public health or the environment. The EPA’s final regulations in response to the decision are not expected until December 2008. In other actions, following the Massachusetts v. EPA decision, the U.S. Court of Appeals for the District of Columbia Circuit remanded to the EPA new source performance standards for utility and industrial boilers promulgated in 2006 for further proceedings in light of the Massachusetts v. EPA decision. In June 2006, the U.S. Court of Appeals for the Second Circuit heard oral argument in a public nuisance action filed by eight states (Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York, and Vermont) and New York City to curb carbon dioxide emissions from power plants. The parties have filed post-argument briefs on the impact of the Massachusetts v. EPA decision, and a decision is currently pending. If as a result of these actions the EPA were to set emission limits for carbon dioxide from electric utilities, the amount of coal our customers purchase from us could decrease.

	•		Regional Haze. The EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks, particularly those located in the southwest and southeast United States. This program may result in additional emissions restrictions from new coal-fueled power plants whose operation may impair visibility at and around federally protected areas. This program may also require certain existing coal-fueled power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could affect the future market for coal.

Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act, which we refer to as SMCRA, establishes mining, environmental protection, reclamation and closure standards for all aspects of surface mining as well as many aspects of underground mining. Mining operators must obtain SMCRA permits and permit renewals from the Office of Surface Mining, which we refer to as OSM, or from the applicable state agency if the state agency has obtained primacy. A state agency may achieve primacy if the state regulatory agency develops a mining regulatory program that is no less stringent than the federal mining regulatory program under SMCRA.

SMCRA permit provisions include a complex set of requirements which include, among other things, coal prospecting; mine plan development; topsoil or growth medium removal and replacement; selective handling of overburden materials; mine pit backfilling and grading; disposal of excess spoil; protection of the hydrologic balance; subsidence control for underground mines; surface runoff and drainage control; establishment of suitable post mining land uses; and revegetation.

The mining permit application preparation process is initiated by collecting baseline data to adequately characterize the pre-mining environmental conditions of the permit area. This work is typically conducted by third-party consultants with specialized expertise and includes surveys and/or assessments of the following: cultural and historical resources; geology; soils; vegetation; aquatic organisms; wildlife; potential for threatened, endangered or other special status species; surface and ground water hydrology; climatology; riverine and riparian habitat; and wetlands. The geologic data is used to define and characterize the rock structures that will be encountered during the mining process. The geologic data and information derived from the other surveys and/or

assessments are used to develop the mining and reclamation plans presented in the permit application. The mining and reclamation plans address the provisions and performance standards of the state’s equivalent SMCRA regulatory program, and are also used to support applications for other authorizations and/or permits required to conduct coal mining activities. Also included in the permit application is information used for documenting surface and mineral ownership, variance requests, access roads, bonding information, mining methods, mining phases, other agreements that may relate to coal, other minerals, oil and gas rights, water rights, permitted areas, and ownership and control information required to determine compliance with Office of Surface Mining’s Applicant Violator System, including the mining and compliance history of officers, directors and principal owners of the entity.

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

In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund, which was created by SMCRA, requires a fee on all coal produced. The proceeds of the fee are used to restore mines closed or abandoned prior to SMCRA’s adoption in 1977. The current fee is $0.315 per ton of coal produced from surface mines and $0.135 per ton of coal produced from underground mines. In 2007, we recorded $35.4 million of expense related to these reclamation fees.

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

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

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

Surety Bonds. Mine operators are often required by federal and/or state laws to assure, usually through the use of surety bonds, payment of certain long-term obligations including mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other miscellaneous obligations. Although surety bonds are usually noncancelable during their term, many of these bonds are renewable on an annual basis. The costs of these bonds have fluctuated in recent years while the market terms of surety bonds have generally become more unfavorable to mine operators. These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. In order to address some of these uncertainties, we use self-bonding to secure performance of certain obligations in Wyoming. As of December 31, 2007, we have self-bonded an aggregate of $304.3 million and have posted an aggregate of $87.9 million in surety

bonds for reclamation purposes. In addition, we had approximately $41.1 million of surety bonds and letters of credit outstanding at December 31, 2007 to secure coal lease and other obligations.

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

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

	•		Wastewater Discharge. Section 402 of the Clean Water Act creates a process for establishing effluent limitations for discharges to streams that are protective of water quality standards through the National Pollutant Discharge Elimination System, which we refer to as the NPDES, or an equally stringent program delegated to a state regulatory agency. Regular monitoring, reporting and compliance with performance standards are preconditions for the issuance and renewal of NPDES permits that govern the discharge into waters of the United States. The imposition of future restrictions on the discharge of certain pollutants into waters of the United States could affect the permitting process, increase the costs and difficulty of obtaining and complying with NPDES permits and could adversely affect our coal production.

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

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

Mine Health and Safety Laws. Stringent safety and health standards have been imposed by federal legislation since Congress adopted the Mine Safety and Health Act of 1969. The Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed comprehensive safety and health standards on all aspects of mining operations. In addition to federal regulatory programs, all of the states in which we operate also have programs for mine safety and health regulation and enforcement. In reaction to several mine accidents in recent years, federal and state legislatures and regulatory authorities have increased scrutiny of mine safety matters and passed more stringent laws governing mining. For example, in 2006, Congress enacted the Mine Improvement and New Emergency Response Act of 2006, which we refer to as the MINER Act. The MINER Act imposes additional obligations on coal operators including, among other things, the following:

	•		development of new emergency response plans that address post-accident communications, tracking of miners, breathable air, lifelines, training and communication with local emergency response personnel;

	•		establishment of additional requirements for mine rescue teams;

	•		notification of federal authorities in the event of certain events;

	•		increased penalties for violations of the applicable federal laws and regulations; and

•

requirement that standards be implemented regarding the manner in which closed areas of underground mines are sealed.

Various states have also enacted new laws to address many of the same subjects. The full financial impact of the new regulations is not yet known. However, the cost of implementation of the new safety and health regulations at the federal and state level may be substantial. In addition to the cost of implementation, there are increased penalties for violations which may also be substantial. Expanded enforcement could result in a proliferation of litigation regarding citations and orders issued as a result of the regulations.

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on production of up to $1.10 per ton for coal mined in underground operations and up to $0.55 per ton for coal mined in surface operations. These amounts may not exceed 4.4% of the gross sales price. This excise tax does not apply to coal shipped outside the United States. In 2007, we recorded $57.2 million of expense related to this excise tax.

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 trigger 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.

Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, which we refer to as RCRA, may affect coal mining operations by establishing requirements for the proper management, handling, transportation and disposal of hazardous wastes. Currently, certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management. Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion products generated at electric utility and independent power producing facilities, such as coal ash. In May 2000, the EPA concluded that coal combustion products do not warrant regulation as hazardous waste under RCRA. The EPA is retaining the hazardous waste exemption for these wastes. However, the EPA has determined that national non-hazardous waste regulations under RCRA Subtitle D are needed for coal combustion products disposed in surface impoundments and landfills and used as mine-fill. The Office of Surface Mining and EPA have recently proposed regulations regarding the management of coal combustion products. The EPA also concluded beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. As long as this exemption remains in effect, it is not anticipated that regulation of coal combustion waste will have any material effect on the amount of coal used by electricity generators. Most state hazardous waste laws also exempt coal combustion products, and instead treat it as either a solid waste or a special waste. Any costs associated with handling or disposal of hazardous wastes would increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of ash can lead to material liability.

Climate Change. One by-product of burning coal is carbon dioxide, which is considered a greenhouse gas and is a major source of concern with respect to global warming. In November 2004, Russia ratified the Kyoto Protocol to the 1992 Framework Convention on Global Climate Change, which establishes a binding set of emission targets for greenhouse gases. With Russia’s accedence, the Kyoto Protocol became binding on all those countries that had ratified it in February 2005. To date, the United States has refused to ratify the Kyoto Protocol. Although the targets vary from country to country, if the United States were to ratify the Kyoto Protocol our nation would be required to reduce greenhouse gas emissions to 93% of 1990 levels from 2008 to 2012.

Future regulation of greenhouse gases in the United States could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act, federal or state adoption of a greenhouse gas regulatory scheme, or otherwise. In 2002, the Conference of New England Governors and Eastern Canadian Premiers adopted a Climate Change Action Plan, calling for reduction in regional greenhouse emissions to 1990 levels by 2010, and a further reduction of at least 10% below 1990 levels by 2020. In December 2005, seven northeastern states (Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York, and Vermont) signed the Regional Greenhouse Gas Initiative agreement, which we refer to as RGGI, calling for a 10% reduction of carbon dioxide emissions by 2019, with compliance to begin January 1, 2009. Maryland signed onto RGGI in July 2006. The RGGI final model rule was issued in August 2006, and the participating states are developing their state rules.

Climate change developments are also taking place in western states. In September 2006, California adopted greenhouse gas legislation that prohibits long-term baseload generators from having a greenhouse gas emissions rate greater than that of combined cycle natural gas generator and that allows for long-term deals with generators that sequester carbon emissions. In January 2007, the California Public Utility Commission adopted interim greenhouse gas standards requiring all new long-term power contracts to serve baseload capacity in California to have emissions no higher than a combined-cycle gas turbine plant. In February 2007, the governors of Arizona, California, New Mexico, Oregon and Washington launched the Western Climate Initiative in an effort to develop a regional strategy for addressing climate change. The goal of the Western Climate Initiative is to identify, evaluate and implement collective and cooperative methods of reducing greenhouse gases in the region. In the spring of 2007, the governor of Utah and the premiers of British Columbia and Manitoba joined the initiative, and other states and provinces participate as observers.

In January 2007, eight midwestern states (Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri, Ohio and Wisconsin) agreed to support a voluntary registry for greenhouse gases. In November 2007, the governors of Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Ohio, South Dakota and Wisconsin and the premier of Manitoba signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions. These and other state climate change rules will likely require additional controls on coal-fueled power plants and industrial boilers and may even cause some users of coal to switch from coal to a lower carbon fuel. There can be no assurance at this time that a carbon dioxide cap and trade program, a carbon tax or other regulatory regime, if implemented by the states in which our customers operate, will not affect the future market for coal in those regions. Increased efforts to control greenhouse gas emissions could result in reduced demand for coal.

Endangered Species. The Endangered Species Act and other related federal and state statutes protect species threatened or endangered with possible extinction. Protection of threatened, endangered and other special status 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 or other related laws or regulations. 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. We have been able to continue our operations within the existing spatial, temporal and other restrictions associated with special status species. Should more stringent protective measures be applied to threatened, endangered or other special status species or to their critical habitat, then we could experience increased operating costs or difficulty in obtaining future mining permits. The federal government is currently considering whether to add polar bears to the list of endangered species. If the polar bear is listed as an endangered species, then that action could result in regulation of carbon dioxide emissions to address global warming. Limits on emissions of carbon dioxide could result in coal becoming a less attractive fuel source and could reduce the amount of coal our customers purchase from us.

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 Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. We believe that we are in substantial compliance with all applicable environmental laws.

Employees

At March 15, 2008, we employed a total of approximately 2,460 persons. We believe that our relations with all employees are good.

Executive Officers

Our managing member is an indirect, wholly-owned subsidiary of Arch Coal. As a result, we are effectively managed by the management of Arch Coal. The following is a list of executive officers of Arch Coal, their ages as of March 15, 2008 and their positions and offices during the last five years:


Name	Age		Position
C. Henry Besten, Jr		59	Mr. Besten has served as Arch Coal’s Senior Vice President-Strategic Development since 2002.

John W. Eaves		50	Mr. Eaves has served as Arch Coal’s President and Chief Operating Officer since April 2006. Mr. Eaves has also been a director of Arch Coal since February 2006. From 2002 to April 2006, Mr. Eaves served as Arch Coal’s Executive Vice President and Chief Operating Officer. Mr. Eaves also serves on the board of directors of ADA-ES, Inc.

Sheila B. Feldman		53	Ms. Feldman has served as Arch Coal’s Vice President-Human Resources since February 2003. From 1997 to February 2003, Ms. Feldman was the Vice President-Human Resources and Public Affairs of Solutia Inc. On December 17, 2003, Solutia Inc. and its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York.

Robert G. Jones		51	Mr. Jones has served as Arch Coal’s Vice President-Law, General Counsel and Secretary since 2000.

Paul A. Lang		47	Mr. Lang has served as Arch Coal’s Senior Vice President-Operations since December 2006. Mr. Lang served as President of Western Operations from July 2005 through December 2006 and President and General Manager of Thunder Basin Coal Company, L.L.C. from November 1998 through July 2005.

Steven F. Leer		55	Mr. Leer has served as Arch Coal’s Chairman and Chief Executive Officer since April 2006. Mr. Leer served as Arch Coal’s President and Chief Executive Officer from 1992 to April 2006. Mr. Leer also serves on the board of directors of the Norfolk Southern Corporation, USG Corp., the Western Business Roundtable and the University of the Pacific and is chairman of the Coal Industry Advisory Board. Mr. Leer is a past chairman and continues to serve on the board of directors of the Center for Energy and Economic Development, the National Coal Council and the National Mining Association.

Robert J. Messey		62	Mr. Messey has served as Arch Coal’s Senior Vice President and Chief Financial Officer since 2000. Mr. Messey also serves on the board of directors of Baldor Electric Company and Stereotaxis, Inc.

David B. Peugh		53	Mr. Peugh has served as Arch Coal’s Vice President-Business Development since 1995.

Deck S. Slone		44	Mr. Slone has served as Arch Coal’s Vice President-Investor Relations and Public Affairs since 2001.

David N. Warnecke		52	Mr. Warnecke has served as Arch Coal’s Vice President-Marketing and Trading since August 2005. From June 2005 until March 2007, Mr. Warnecke served as President of Arch Coal Sales Company, Inc., and from April 2004 until June 2005, Mr. Warnecke served as Executive Vice President of Arch Coal Sales Company, Inc. Prior to June 2004, Mr. Warnecke was Senior Vice President-Sales, Trading and Transportation of Arch Coal Sales Company, Inc.

Available Information

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

Item 1A. Risk Factors.

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

Risks Related to Our Business

A substantial or extended decline in coal prices could negatively affect our profitability and the value of our coal reserves.

Our profitability and the value of our coal reserves depend upon the prices we receive for our coal. In turn, the prices we receive for our coal depend upon factors beyond our control, including the following:

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

	•		the demand for electricity and steel;

	•		domestic and foreign governmental regulations and taxes, including those establishing air emission standards for coal-fueled power plants;

	•		regulatory, administrative and judicial decisions, including those affecting future mining permits;

	•		the proximity, capacity and cost of transportation facilities;

	•		the availability and price of alternative fuels, such as natural gas, and alternative energy sources, such as hydroelectric, wind and solar power;

	•		technological developments, including those intended to convert coal to liquid or gas and those aimed at capturing and sequestering carbon; and

	•		the effects of worldwide energy conservation measures.

Declines in the prices we receive for our coal could adversely affect our profitability and the value of our coal reserves.

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

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

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

	•		changes or 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;

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

	•		shortage of qualified labor;

	•		unexpected or accidental surface subsidence from underground mining;

	•		accidental mine water discharges, fires, explosions or similar mining accidents; and

	•		regulatory issues involving the plugging of and mining through oil and gas wells that penetrate the coal seams we mine.

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

Increases in the costs of mining and other industrial supplies, including steel-based supplies, diesel fuel and rubber tires, or the inability to obtain a sufficient quantity of those supplies, could negatively affect our operating costs or disrupt or delay our production.

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

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

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

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

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

In addition to the availability of additional coal reserves, our future performance depends on the accuracy with which we estimate the quantity and quality of the coal included within those reserves. We base our estimates of reserve information on engineering, economic and geological data assembled, analyzed and reviewed by internal and third-party engineers and consultants. The quantity and quality of the coal we are ultimately able to recover within our coal reserves may differ materially from our estimates. Inaccuracies in our estimates could result in revenue that is lower than we expect or operating costs that are higher than we expect.

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

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

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

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

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

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

	•		uncertainties in assessing the value, risks, profitability and liabilities (including environmental liabilities) associated with certain businesses or assets;

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

	•		the possibility that operating and financial synergies expected to result from an acquisition do not develop;

	•		problems arising from the integration of an acquired business; and

	•		unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the rationale for a particular acquisition.

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

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

Because we sell a portion of our coal production under long-term coal supply agreements, our ability to capitalize on more favorable market prices may be limited. Conversely, at any given time we are subject to fluctuations in market prices for the quantities of coal that we have produced but which we have not committed to sell. As described above under “A substantial or extended decline in coal prices could negatively affect our profitability and the value of our coal reserves,” the market prices for coal may be volatile and may depend upon factors beyond our control. Our profitability may be adversely affected if we are unable to sell uncommitted production at favorable prices or at all. For more information about our long-term coal supply agreements, you should see “Long-Term Coal Supply Arrangements” beginning on page 9.

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

For the year ended December 31, 2007, we derived approximately 31.7% of our total coal revenues from sales to our three largest customers, Tennessee Valley Authority, Ameren Corporation and Intermountain Power Agency, and approximately 58.4% of our total coal revenues from sales to our ten largest customers. At December 31, 2007, we had coal supply agreements with those ten customers that expire at various times from 2008 to 2017. We expect to renew, extend or enter into new long-term coal supply agreements with those and other customers. However, we may be unsuccessful in obtaining long-term coal supply agreements with those customers, and those customers may discontinue purchasing coal from us. If any of those customers, particularly any of our three largest customers, was to significantly reduce the quantities of coal it purchases from us, or if we are unable to sell coal to those customers on terms as favorable to us as the terms under our current long-term coal supply agreements, our profitability could suffer significantly. We have limited protection during adverse economic conditions and may face economic penalties if we are unable to satisfy certain quality specifications under our long-term coal supply agreements.

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

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

At December 31, 2007, we had consolidated indebtedness of approximately $1.0 billion. We also have significant lease and royalty obligations. Our ability to satisfy our debt, lease and royalty obligations, and our ability to refinance our indebtedness, will depend upon our future operating performance. Our ability to satisfy our financial obligations may be adversely affected if we incur additional indebtedness in the future. In addition, the amount of indebtedness we have incurred could significantly affect:

	•		our ability to satisfy debt covenants and debt service, lease payment and other obligations;

	•		our ability to generate cash flow from operations or to obtain additional financing;

	•		our credit ratings;

	•		our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete; and

	•		our competitiveness when compared to competitors with less debt.

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

The agreements governing our financing arrangements 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 borrow the full amount under our those facilities, effect acquisitions or dispositions and incur additional debt and require us to comply with various other financial covenants. Our ability to comply with these restrictions may be affected by events beyond our control and, as a result, we may be unable to comply with these restrictions. A failure to comply with these restrictions could adversely affect our ability to borrow

under those facilities or result in an event of default under these agreements. In the event of a default, our lenders and the counterparties to our other financing arrangements could terminate their commitments to us and declare all amounts borrowed, together with accrued interest and fees, immediately due and payable. If this were to occur, we might not be able to pay these amounts, or we might be forced to seek an amendment to our financing arrangements which could make the terms of these arrangements more onerous for us. For more information about some of the restrictions contained in our leases and other financial arrangements, you should see “Liquidity and Capital Resources” beginning on page 32.

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

Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations. We generally reprice these bonds annually, however, they are not cancellable by the surety. Surety bond issuers and holders may increase premiums on the bonds or impose other less favorable terms upon those renewals. The ability of surety bond issuers and holders to demand additional collateral or other less favorable terms has increased as the number of companies willing to issue these bonds has decreased over time. Our failure to maintain, or our inability to acquire, surety bonds required by federal and state law could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.

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

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

Risks Related to Environmental and Other Regulations

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

Governmental regulations, including those related to the matters listed below, have significant effects on the coal mining industry:

	•		employee health and safety;

	•		mine permitting and licensing requirements;

	•		reclamation and restoration of mining properties after mining is completed;

	•		air quality standards;

	•		water pollution;

	•		the discharge of materials into the environment;

	•		management of materials generated by mining operations;

	•		surface subsidence from underground mining;

	•		statutorily mandated benefits for current and retired coal miners;

	•		protection of wetlands;

	•		endangered plant and wildlife protection;

	•		limitations on land use;

	•		storage and disposal of petroleum products and substances that are regarded as hazardous under applicable laws; and

	•		management of electrical equipment containing PCBs.

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

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

You should see “Safety and Environmental Regulations” beginning on page 10 for more information about the various governmental regulations affecting us.

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

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

The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion or utilization. As a result, coal users may switch to other fuels, which could affect the volume of our sales and the price of our products.

Coal contains impurities, including but not limited to sulfur, mercury, chlorine, carbon and other elements or compounds, many of which are released into the air when coal is burned. Stricter environmental regulations of emissions from coal-fueled power plants could increase the costs of using coal thereby reducing demand for coal as a fuel source and the volume and price of our coal sales. Stricter regulations could make coal a less attractive fuel alternative in the planning and building of power plants in the future.

Proposed reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases may require the installation of costly emission control technology or the implementation of other measures, including trading of emission allowances and switching to other fuels. For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from power plants, coal users may need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), blend high sulfur coal with low-sulfur coal or switch to other fuels. Reductions in mercury emissions required by certain states will likely require some power plants to install new equipment, at substantial cost, or discourage the use of certain coals containing higher levels of mercury. Recent and new proposals calling for reductions in emissions of carbon dioxide and other greenhouse gases could significantly increase the cost of operating existing coal-fueled power plants and could inhibit construction of new coal-fueled power plants. Existing or proposed legislation focusing on emissions enacted by the United States or individual states could make coal a less attractive fuel alternative for our customers and could impose a tax or fee on the producer of the coal. If our customers decrease the volume of coal they purchase from us or switch to alternative fuels as a result of existing or future environmental regulations aimed at reducing emissions, our operations and financial results could be adversely impacted.

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

SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of underground mining. We base our estimates of reclamation and mine closure liabilities on permit requirements and our engineering expertise related to these requirements. Our management and engineers periodically review these estimates. The estimates can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, which we refer to as Statement No. 143, requires us to record these obligations as liabilities at fair value. In estimating fair value, we considered the estimated current costs of reclamation and mine closure and applied inflation rates and a third-party profit, as required by Statement No. 143. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf. If actual costs differ from our estimates, our profitability could be negatively affected.

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

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

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

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

At December 31, 2007, we owned or controlled primarily through long-term leases approximately 100,300 acres of coal land in Wyoming, 61,100 acres of coal land in Utah, 21,800 acres of coal land in New Mexico and 18,500 acres of coal land in Colorado. We sublease a significant portion of our coal land from Arch Coal. Arch Coal leases a portion of that property from the federal government or from various state governments. Those governmental leases are subject to readjustment and/or extension and to earlier termination for failure to meet diligent development requirements. Certain of our loadout facilities are located on properties held under leases which expire at varying dates over the next 30 years. Most of the leases contain options to renew. Our remaining loadout facilities are located on property owned by Arch Coal or for which we have a special use permit.

Our Reserves

We estimate that we owned or controlled approximately 2.2 billion tons of proven and probable recoverable reserves at December 31, 2007. 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 our estimated assigned and unassigned recoverable coal reserves at December 31, 2007:

Total Assigned Reserves
(Tons in millions)


	Total						Sulfur Content																Past Reserve
	Assigned						(lbs. per million Btus)								Reserve Control				Mining Method				Estimates
	Recoverable												As Received								Under-
	Reserves		Proven		Probable		<1.2		1.2-2.5		>2.5		Btus per lb. ⁽¹⁾		Leased		Owned		Surface		ground		2005		2006
Wyoming		1,549		1,508		41		1,504		45		—		8,856		1,534		15		1,549		—		1,748		1,655
Utah		103		60		43		91		12		—		11,399		102		1		—		103		108		110
Colorado		79		60		19		79		—		—		11,695		78		1		—		79		74		67

Total		1,731		1,628		103		1,674		57		—		9,137		1,714		17		1,549		182		1,930		1,832


⁽¹⁾		As received Btus per lb. includes the weight of moisture in the coal on an as sold basis.

Total Unassigned Reserves
(Tons in millions)


	Total
	Unassigned						Sulfur Content
	Recoverable						(lbs. per million Btus)						As Received		Reserve Control				Mining Method
	Reserves		Proven		Probable		<1.2		1.2-2.5		>2.5		Btus per lb. ⁽¹⁾		Leased		Owned		Surface		Underground
Wyoming		398		301		97		351		47		—		9,653		307		91		224		174
Utah		35		16		19		31		4		—		10,842		34		1		—		35
Colorado		49		39		10		47		2		—		11,597		48		1		—		49

Total		482		356		126		429		53		—		9,937		389		93		224		258


⁽¹⁾		As received Btus per lb. includes the weight of moisture in the coal on an as sold basis.

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

Federal and state legislation controlling air pollution affects the demand for certain types of coal by limiting the amount of sulfur dioxide which may be emitted as a result of fuel combustion and encourages a greater demand for low-sulfur coal. All of our identified coal reserves have been subject to preliminary coal seam analysis to test sulfur content. Of these reserves, approximately 95.0% consist of compliance coal, or coal which emits 1.2 pounds or less of sulfur dioxide per million Btus upon combustion, while an additional 2.7% could be sold as low-sulfur coal. Most of our reserves are suitable for the domestic steam coal markets.

The carrying cost of our coal reserves at December 31, 2007 was $423.5 million, consisting of $4.2 million of prepaid royalties and a net book value of coal lands and mineral rights of $419.3 million.

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.

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. We are not currently aware of matters

which would significantly hinder our ability to obtain future mining permits or governmental approvals with respect to our reserves.

Arch Coal periodically engages third parties to review our reserve estimates. The most recent third-party review of our reserve estimates was conducted by Weir International Mining Consultants in February 2008.

Item 3. Legal Proceedings.

We are involved in various claims and legal actions arising in the ordinary course of business, including employee injury claims. 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.

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
	2007		2006		2005		2004		2003
			^{(1) (2)}		^{(1) (3)}		⁽⁴⁾		⁽⁵⁾
	(Amounts in thousands, except per ton data)
Statement of Operations Data:
Coal sales revenue	$	1,541,066	$	1,491,362	$	1,126,742	$	735,162	$	500,555
Income from operations		197,271		314,263		186,061		83,275		62,710
Income before cumulative effect of accounting change		201,165		287,013		128,844		32,946		20,996
Cumulative effect of accounting change		—		—		—		—		(18,278	)

Net income		201,165		287,013		128,844		32,946		2,718

Balance Sheet Data:
Cash and cash equivalents	$	248	$	186	$	152	$	1,351	$	35,171
Receivable from Arch Coal, Inc.		1,427,833		1,152,102		869,056		677,934		351,866
Total assets		2,852,187		2,557,772		2,215,376		2,013,436		1,411,515
Total debt		1,032,473		958,881		960,247		961,613		700,000
Redeemable membership interests		8,000		6,934		5,647		4,971		4,746
Non-redeemable membership interests		1,147,184		934,545		677,795		543,058		471,890

Cash Flow Data:
Cash provided by operating activities	$	324,764	$	539,666	$	225,798	$	115,302	$	129,045
Depreciation, depletion and amortization		135,294		108,272		98,347		80,703		63,053
Capital expenditures		147,423		260,368		108,600		78,313		27,322

Operating Data:
Tons sold		115,743		113,759		105,796		86,264		69,541
Tons produced		115,841		114,928		106,554		91,466		69,361
Average sales price per ton	$	13.31	$	13.11	$	10.65	$	8.52	$	7.20


⁽¹⁾		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 final longwall equipment. We estimate that the idling resulted in $30.0 million of lost profits during the first quarter of 2006, in addition to the effect of the idling and fire-fighting costs incurred during the fourth quarter of 2005 of $33.3 million. We recognized insurance recoveries related to the event of $41.9 million during the year ended December 31, 2006. We have reflected these insurance recoveries as a reduction of our cost of coal sales for the year ended December 31, 2006.

⁽²⁾		On January 1, 2006, we adopted the provisions of Emerging Issues Task Force Issue No. 04-6, Accounting for Stripping Costs in the Mining Industry. The cumulative effect of adoption was to reduce inventory by $37.6 million and deferred development cost by $2.0 million with a corresponding decrease to membership interests.

⁽³⁾		On December 30, 2005, we sold to Peabody Energy Corporation a rail spur, rail loadout and an idle office complex located in the Powder River Basin, for a purchase price of $79.6 million. As a result of the transaction, we recognized a gain of $43.3 million which we recorded as a component of other operating income.

⁽⁴⁾		During 2004, Arch Coal contributed the North Rochelle mine in the Powder River Basin to the Company. Arch Coal also purchased the remaining 35% interest in Canyon Fuel that we did not own and we began consolidating Canyon Fuel in our financial statements as of July 31, 2004.

⁽⁵⁾		On January 1, 2003, we adopted Statement No. 143 resulting in a cumulative effect of accounting change of $18.3 million.

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

Overview

Arch Western Resources, LLC is a subsidiary of Arch Coal, Inc., one of the largest coal producers in the United States. For the year ended December 31, 2007, we sold approximately 115.7 million tons of coal. Since federal and state environmental regulations limit the amount of sulfur dioxide that power plants may emit, we believe demand for low sulfur coal exceeds demand for other types of coal. As a result, we focus on mining, processing and marketing coal with low sulfur content for sale to domestic power plants and industrial facilities.

In 2007, we estimate that U.S. coal consumption rose by approximately 2% to 1.2 billion tons, according to estimates provided by the EIA. Conversely, according to the EIA, domestic coal production declined by approximately 1.5% in 2007. In 2008, we expect continued growth in electricity demand, although at lower levels than in 2007 given the forecast for slower U.S. economic growth. In addition, we expect strengthening global demand for coal to increase U.S. coal exports, particularly as traditional coal export countries, such as Australia, China and South Africa experience mine, port, rail and labor challenges. We estimate that higher domestic coal demand and higher coal exports, together with decreased production particularly in the Central Appalachia region of the United States, will adversely affect the availability of domestic coal in the coming years and result in upward pressure on domestic coal prices in all coal-producing regions. As such, we have not yet priced a portion of the coal we plan to produce over the next several years in order to take advantage of expected price increases.

The locations of our mines enable us to ship coal to most of the major coal-fired power plants in the United States. Our reportable business segments 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 Powder River Basin is located in northeastern Wyoming and southeastern Montana. The coal we mine from surface operations in this region has a very low sulfur content and a low heat value compared to other coal-producing regions. The price of Powder River Basin coal is generally less than that of coal produced in other regions because Powder River Basin coal exists in greater abundance, is easier to mine and thus has a lower cost of production. Because Powder River Basin coal is generally lower in heat value, some power plants must blend it with higher Btu coal or retrofit existing coal plants to accommodate Powder River Basin coal. The Western Bituminous region includes western Colorado, eastern Utah and southwestern Wyoming. Coal we mine from underground mines in this region typically has a low sulfur content and varies in heat value.

In 2007, we continued the efforts we had begun in prior periods aimed at positioning our operations for increasing global and domestic coal demand. During the first half of 2007, we installed a replacement longwall at our Sufco mining complex in Utah. In addition, we began construction of a new loadout facility at our Black Thunder mining complex in Wyoming. This facility, which we have strategically located in relation to the direction of our mining activities, will replace the facility that we currently lease from a third party under an agreement set to expire within the next year. In 2007, we also continued development of a new reserve area at our West Elk mining complex in Colorado.

Items Affecting Comparability of Reported Results

The comparability of our operating results for the years ended December 31, 2007, 2006 and 2005 is affected by the following significant items:

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

West Elk combustion event - A combustion-related event at our West Elk mine in Colorado in October 2005 caused the idling of the mine into the first quarter of 2006. We estimate that the idling resulted in $30.0 million in lost profits during the first quarter of 2006, in addition to the effect of the idling and fire-fighting costs incurred during the fourth quarter of 2005 of $33.3 million. We recognized insurance recoveries related to the event of $41.9 million during the year ended December 31, 2006. We have reflected these insurance recoveries as a reduction of our cost of coal sales for the year ended December 31, 2006.

Accounting for pit inventory - On January 1, 2006, we adopted the provisions of Emerging Issues Task Force Issue No. 04-6, Accounting for Stripping Costs in the Mining Industry. This issue applies to stripping costs incurred in the production phase of a mine for the removal of overburden or waste materials for the purpose of obtaining access to coal that will be extracted. Under the issue, stripping costs incurred during the production phase of the mine are variable production costs that are included in the cost of inventory produced and extracted during the period the stripping costs are incurred. Prior to 2006, we recorded stripping costs associated with the tons of coal uncovered and not yet extracted (pit inventory) at our surface mining operations as coal inventory.

The cumulative effect of adoption was to reduce inventory by $37.6 million and deferred development cost by $2.0 million with a corresponding decrease to membership interests. This accounting change creates volatility in our results of operations, as cost increases or decreases related to fluctuations in pit inventory can only be attributed to tons extracted from the pit.

Results of Operations

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Summary. Our results during 2007 when compared to 2006 were affected by increased sales volume and an increase in interest income offset by the impacts of higher depreciation, depletion and amortization, higher cash costs in the Powder River Basin and the net effect of the insurance proceeds we recorded in 2006 related to the West Elk idling and the effect of the idling in the first quarter of 2006.

Revenues. The following table summarizes information about coal sales during the year ended December 31, 2007 and compares those results to the comparable information for the year ended December 31, 2006:


	Year Ended December 31				Increase
	2007		2006		Amount		%
	(Amounts in thousands, except per ton data)
Coal sales	$	1,541,066	$	1,491,362	$	49,704		3.3	%
Tons sold		115,743		113,759		1,984		1.7
Coal sales realization per ton sold	$	13.31	$	13.11	$	0.20		1.5	%

Coal sales. Coal sales increased from 2006 to 2007 primarily due to higher sales volume and higher average coal sales realization per ton sold. A portion of the increase in the average coal sales realization per ton is due to a change in the regional segment mix. A decrease in Powder River Basin sales volumes and an increase in Western Bituminous region sales volumes as a percentage of total sales volume resulted in a higher average sales price because Powder River Basin coal has a lower average sales price per ton than Western Bituminous region coal. We have provided more information about the tons sold and the coal sales realizations per ton by operating segment under the heading “Operating segment results” on page 30.

Expenses, costs and other. The following table summarizes expenses, costs and other operating income, net for the year ended December 31, 2007 and compares those results to the comparable information for the year ended December 31, 2006:


							Increase (Decrease)
	Year Ended December 31						in Net Income
	2007			2006			$			%
	(Dollars in thousands)
Cost of coal sales	$	1,192,348		$	1,049,429		$	(142,919	)		(13.6	)%
Depreciation, depletion and amortization		135,294			108,272			(27,022	)		(25.0	)
Selling, general and administrative expenses		26,298			23,466			(2,832	)		(12.1	)
Other operating income, net		(10,145	)		(4,068	)		6,077			149.4

Total	$	1,343,795		$	1,177,099		$	(166,696	)		(14.2	)%

Cost of coal sales. Cost of coal sales increased from 2006 to 2007 primarily due to higher unit costs in the Powder River Basin, reflecting higher commodity and supplies costs, and higher unit costs in the Western Bituminous region. Higher unit costs in the Western Bituminous region were primarily due to the impact of insurance proceeds we recognized in 2006 related to the West Elk combustion-related event, which more than offset the impact of the idling in the first quarter of 2006. We have provided more information about our operating segments under the heading “Operating segment results” on page 30.

Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization expense from 2006 to 2007 is due primarily to the costs of ongoing capital improvement and mine development projects that we capitalized in 2006 and 2007 and a decrease in the amortization of deferred gains on acquired sales contracts. We have provided additional information concerning our capital spending in the section entitled “Liquidity and Capital Resources” beginning on page 32.

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

Other operating income, net. The increase in other operating income, net in 2007 compared to 2006 is primarily the result of a $6.0 million gain in 2007 on the sale of non-core reserves in the Powder River Basin.

Operating segment results. The following table shows results by operating segment for the year ended December 31, 2007 and compares those amounts to the comparable information for the year ended December 31, 2006:


	Year Ended December 31				Increase (Decrease)
	2007		2006		Amount			%
	(Amounts in thousands, except per ton data)
Powder River Basin
Tons sold		96,418		95,637		781			0.8	%
Coal sales realization per ton sold ⁽¹⁾	$	10.36	$	10.78	$	(0.42	)		(3.9	)%
Operating margin per ton sold ⁽²⁾	$	1.15	$	2.22	$	(1.07	)		(48.2	)%

Western Bituminous
Tons sold		19,325		18,122		1,203			6.6	%
Coal sales realization per ton sold ⁽¹⁾	$	24.70	$	22.42	$	2.28			10.2	%
Operating margin per ton sold ⁽²⁾	$	5.11	$	6.87	$	(1.76	)		(25.6	)%


⁽¹⁾		Coal sales prices per ton exclude certain transportation costs that we pass through to our customers. We use these financial measures because we believe the amounts as adjusted better represent the coal sales prices we achieved within our operating segments. Since other companies may calculate coal sales prices per ton differently, our calculation may not be comparable to similarly titled measures used by those companies. For the year ended December 31, 2007, transportation costs per ton billed to customers were $0.04 for the Powder River Basin and $3.17 for the Western Bituminous region. Transportation costs per ton billed to customers for the year ended December 31, 2006 were $0.02 for the Powder River Basin and $2.91 for the Western Bituminous region.

⁽²⁾		Operating margin per ton is calculated as the result of coal sales revenues less cost of coal sales and depreciation, depletion and amortization divided by tons sold.

Powder River Basin — Sales volume in the Powder River Basin increased slightly in 2007 over 2006 levels due to increased shipments from the Coal Creek mine, which was restarted during 2006. These volumes were partially offset by a decrease at the Black Thunder mining complex due to planned volume reductions in response to the weaker market conditions in 2007, as well as weather-related shipment challenges and an unplanned belt outage that occurred in the first quarter of 2007. Decreases in sales prices during 2007 when compared with 2006 primarily reflect the higher volumes from the Coal Creek mining complex, which has a lower per-unit price for its coal due to its lower heat content, and lower sulfur dioxide emission allowance adjustments. On a per-ton basis, operating margins in 2007 decreased from 2006 due in part to the decrease in per-ton coal sales prices and an increase in per-ton costs. The increase in per-ton costs resulted primarily from higher diesel fuel prices and higher labor, tire and leasing costs.

Western Bituminous — In the Western Bituminous region, sales volume increased during 2007 when compared with 2006, reflecting a full year of production at the West Elk and Skyline mining complexes. The West Elk mining complex was idle during the first quarter of 2006 after the combustion-related event in the fourth quarter of 2005, and the Skyline longwall commenced mining in a new reserve area in the second quarter of 2006. These increases were partially offset by the lower volumes from planned volume reductions in response to the weaker market conditions in 2007. Higher sales prices during 2007 represent higher base pricing resulting from the roll-off of lower-priced legacy contracts. Operating margins per ton for 2007 decreased from 2006 primarily due to the impact of insurance proceeds we recognized in 2006 related to the West Elk combustion-related event and higher depreciation, depletion and amortization costs resulting from the impact of the installation of a new longwall at the Sufco mining complex. These factors offset the impact of the improved per-ton coal sales prices. The $41.9 million of insurance proceeds we recognized in 2006 offset the estimated $30.0 million adverse effect of the idling in the first quarter of 2006.

Net interest income. The following table summarizes our net interest income for the year ended December 31, 2007 and compares that information to the comparable information for the year ended December 31, 2006:


							Increase
	Year Ended December 31						in Net Income
	2007			2006			$		%
	(Amounts in thousands)
Interest expense	$	(72,147	)	$	(72,273	)	$	126		0.2	%
Interest income		99,683			81,853			17,830		21.8

Total	$	27,536		$	9,580		$	17,956		187.4	%

Interest expense consists of interest on our 6³/4% senior notes, the discount on trade accounts receivable sold to Arch Coal under Arch Coal’s accounts receivable securitization program and interest on our commercial paper. See further discussion of our outstanding debt in “Liquidity and Capital Resources” beginning on page 32. Interest related to commercial paper issued in 2007 was offset by lower costs related to the accounts receivable securitization program and an increase in capitalized interest in 2007 when compared with 2006.

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 during 2007 when compared to 2006.

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

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

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

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


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

Coal sales increased during 2006 when compared to 2005 due to higher contract prices in both of our segments and higher volumes in our Powder River Basin segment. We have provided more information about the tons sold and the coal sales realizations per ton by operating segment under the heading “Operating segment results” on page 32.

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


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

Total	$	1,177,099		$	940,681		$	(236,418	)		(25.1	)%

Cost of coal sales. Our cost of coal sales increased from 2005 to 2006 primarily due to increased sales volume in the Powder River Basin, and higher costs, primarily production taxes and coal royalties, which we pay as a percentage of coal sales. We have provided more information about our operating segments under the heading “Operating segment results” on page 32.

Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization from 2005 to 2006 is due primarily to capital improvements associated with development projects. We have provided additional information concerning our capital spending during 2006 in the section entitled “Liquidity and Capital Resources” beginning on page 32.

Gain on sale. You should see “Items Affecting Comparability of Reported Results” beginning on page 28 for more information about the gains on the sale of our Powder River Basin assets.

Operating segment results. The following table shows results by operating segment for the year ended December 31, 2006 and compares those amounts to the comparable information for the year ended December 31, 2005:


	Year Ended December 31				Increase (Decrease)
	2006		2005		Amount			%
	(Amounts in thousands, except per ton data)
Powder River Basin
Tons sold		95,637		87,597		8,040			9.2	%
Coal sales realization per ton sold ⁽¹⁾	$	10.78	$	8.20	$	2.58			31.5	%
Operating margin per ton sold ⁽²⁾	$	2.22	$	1.19	$	1.03			86.6	%

Western Bituminous
Tons sold		18,122		18,199		(77	)		(0.4	)%
Coal sales realization per ton sold ⁽¹⁾	$	22.42	$	19.01	$	3.41			17.9	%
Operating margin per ton sold ⁽²⁾	$	6.87	$	3.27	$	3.60			110.1	%


⁽¹⁾		Coal sales prices per ton exclude certain transportation costs that we pass through to our customers. We use these financial measures because we believe the amounts as adjusted better represent the coal sales prices we achieved within our operating segments. Since other companies may calculate coal sales prices per ton differently, our calculation may not be comparable to similarly titled measures used by those companies. For the year ended December 31, 2006, transportation costs per ton billed to customers were $0.02 for the Powder River Basin and $2.91 for the Western Bituminous region. Transportation costs per ton billed to customers for the year ended December 31, 2005 were $0.07 for the Powder River Basin and $3.10 for the Western Bituminous region.

⁽²⁾		Operating margin per ton is calculated as the result of coal sales revenues less cost of coal sales and depreciation, depletion and amortization divided by tons sold.

Powder River Basin — Sales volume increased in the Powder River Basin as a result of the restart of the Coal Creek mining complex in the second quarter of 2006 and rail service that improved during 2006 when compared to 2005. The increase in coal sales prices in 2006 in the Powder River Basin resulted from higher contract pricing when compared to 2005, due primarily to the expiration of lower-priced legacy contracts. On a per-ton basis, operating margins in 2006 increased significantly from 2005 primarily due to the increase in per-ton coal sales realizations, partially offset by increased production taxes and coal royalties that we pay as a percentage of coal sales realizations, higher repair and maintenance activity and higher diesel, tire and explosives costs during 2006 compared to 2005.

Western Bituminous — In the Western Bituminous region, the effect of an extended longwall move at the Dugout Canyon mining complex offset a portion of the 1.5 million tons sold from our Skyline mining complex, which commenced production in a new reserve area in the second quarter of 2006. The increase in coal sales prices in the Western Bituminous region in 2006 resulted from higher contract pricing when compared to 2005, due primarily to the expiration of lower-priced legacy contracts. Operating margins per ton in 2006 increased from 2005 primarily due to higher per ton sales prices and insurance recoveries related to the West Elk thermal event of $41.9 million, partially offset by higher costs resulting from the idling of the West Elk complex in the first quarter of 2006, an extended longwall move at our Dugout Canyon mining complex, higher coal royalties and production taxes, which we pay as a percentage of sales, and higher repair and supplies costs.

Net interest income (expense). The following table summarizes our net interest income (expense) for the year ended December 31, 2006 and compares that information to the comparable information for the year ended December 31, 2005:


							Increase (Decrease)
	Year Ended December 31						in Net Income
	2006			2005			$			%
	(Amounts in thousands)
Interest expense	$	(72,273	)	$	(65,543	)	$	(6,730	)		(10.3	)%
Interest income		81,853			45,233			36,620			81.0

Total	$	9,580		$	(20,310	)	$	29,890			147.2	%

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

Arch Coal manages our cash transactions. Cash paid to or from us that is not considered a distribution or a contribution is recorded in an Arch Coal receivable account. The receivable earns interest at the prime rate. The increase in interest income on the receivable from Arch Coal results from a higher average receivable balance in 2006 as compared to 2005, including the effect of amounts related to the sale of trade accounts receivable to Arch Coal.

Liquidity and Capital Resources

Our primary sources of cash include sales of our coal production to customers, sales of assets, our new commercial paper program and debt related to significant transactions. Excluding any significant mineral reserve acquisitions, we generally satisfy

our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations and, if necessary, cash from Arch Coal. Our ability to satisfy debt service obligations, to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control.

Arch Coal manages our cash transactions. Cash paid to or from us that is not considered a distribution or a contribution is recorded in an Arch Coal receivable account.

The 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
	2007			2006			2005
	(Amounts in thousands)
Cash provided by (used in):
Operating activities	$	324,764		$	539,666		$	225,798
Investing activities		(399,459	)		(539,617	)		(226,932	)
Financing activities		74,757			(15	)		(65	)

Cash provided by operating activities decreased $214.9 million in 2007 compared to 2006, due to a decrease in earnings and the commencement of Arch Coal’s accounts receivable securitization program in the first quarter of 2006, which resulted in a substantial decrease in our trade receivables in 2006. Under the program, we sell our receivables to Arch Coal without recourse at a discount based on the prime rate and days sales outstanding. During 2007, we sold $1.5 billion of trade accounts receivable to Arch Coal, at a total discount of $9.8 million. During 2006, we sold $1.5 billion of trade accounts receivable to Arch Coal, at a total discount of $10.5 million.

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

Cash used in investing activities in 2007 was $140.2 million less than in 2006, primarily due to a decrease in capital spending of $112.9 million in 2007 when compared 2006. See further discussion of major capital projects below. In addition, cash flows from investing activities in 2007 included a recovery of $18.3 million from the lease of equipment in the Powder River Basin. We had previously made deposits to purchase the equipment, primarily in the fourth quarter of 2006.

We make capital expenditures to improve and replace existing mining equipment, expand existing mines, develop new mines and improve the overall efficiency of mining operations. The major projects comprising our capital spending in 2007 included the ongoing development of a new reserve area at the West Elk mining complex in Colorado, remaining payments for the replacement longwall now in service at our Sufco mining complex in Utah and costs to construct the Black Thunder mining complex’s new loadout. In 2006, our capital projects included the restart of the Coal Creek mining complex and the commencement of mining in a new reserve area at our Skyline mining complex, as well as progress payments related to the purchase of the replacement longwall at our Sufco mining complex.

We used $312.7 million more cash in investing activities in 2006 than in 2005, due to increased capital expenditures and a decrease of $81.5 million in proceeds from dispositions of property, plant and equipment. Higher spending at our Powder River Basin operations related to the restart of the Coal Creek mine and progress payments related to the purchase of a replacement longwall at our Sufco mining complex resulted in an increase in capital expenditures in 2006 compared to 2005. The decrease in proceeds is a result of the sale in 2005 of the railspur, rail loadout and idle office complex in the Powder River Basin described in “Items Affecting Comparability of Reported Results,” beginning on page 28.

We anticipate that capital expenditures during 2008 will range from approximately $250 million to $280 million. The 2008 estimate includes capital expenditures related to development work at certain of our mining operations, including the development of a new seam, with a new longwall, at the West Elk mining complex and continuing work on the new loadout at Black Thunder. We anticipate that we will fund these capital expenditures with cash generated from operations.

Cash provided by financing activities increased $74.8 million in 2007 compared to 2006. The increase results primarily from the commencement of our commercial paper program. We entered into the commercial paper placement program on August 15, 2007 to provide short-term financing at rates that are generally lower than the rates available under Arch Coal’s revolving credit facility. Under the program, as amended, we may sell up to $75.0 million in interest-bearing or discounted short-term unsecured debt obligations with maturities of no more than 270 days. The commercial paper placement program is supported by an unsecured $75.0 million revolving credit facility with a maturity date of June 7, 2008. As of December 31, 2007, we had $75.0 million outstanding under the agreement with a weighted-average interest rate of 5.08% and maturity dates ranging from two to 81 days.

Contractual Obligations

The following is a summary of our significant contractual obligations as of December 31, 2007:


	Payments Due by Period
	2008		2009-2010		2011-2012		After 2012		Total
	(Amounts in thousands)
Long-term debt, including related interest	$	139,584	$	128,250	$	128,250	$	982,063	$	1,378,147
Operating leases		24,429		45,047		32,713		28,973		131,162
Coal lease rights		1,534		2,846		2,554		7,925		14,859
Unconditional purchase obligations		186,959		10,376		—		—		197,335

Total contractual obligations	$	352,506	$	186,519	$	163,517	$	1,018,961	$	1,721,503

Coal lease rights represent non-cancelable royalty lease agreements. Unconditional purchase obligations include open purchase orders, which have not been recognized as a liability. The commitments in the table above relate to commitments for the purchase of materials and supplies, payments for services and capital expenditures.

The table above excludes our asset retirement obligations. Our consolidated balance sheet reflects a liability of $195.7 million for asset retirement obligations that arise from SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The determination of the fair value of asset retirement obligations involves a number of estimates, as discussed in the section below entitled “Critical Accounting Policies”, including the timing of payments to satisfy asset retirement obligations. The timing of payments to satisfy asset retirement obligations is based on numerous factors, including mine closure dates. You should see the notes to our consolidated financial statements for more information about our asset retirement obligations.

The contractual obligations table included above also excludes certain other obligations reflected in our consolidated balance sheet, including an allocated portion of liabilities under Arch Coal’s pension and postretirement benefit plans and obligations under our self-insured workers’ compensation program. We are not obligated to make contributions to Arch Coal’s plans, but we are charged through the intercompany account for an allocated portion of Arch Coal’s contributions. The timing of payments may vary based on changes in the fair value of the plan’s assets (for pension obligations) and actuarial assumptions, and benefit payments. See the section entitled “Critical Accounting Policies” for more information about these assumptions. See Notes 11 and 12 to our consolidated financial statements for more information about the amounts we have recorded for workers’ compensation and pension and postretirement benefit obligations

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include 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 and corporate guarantees (e.g., self bonds) to secure our financial obligations for reclamation, lease obligations and other obligations as follows as of December 31, 2007:


	Reclamation		Lease
	Obligations		Obligations		Other		Total
	(Amounts in thousands)
Self bonding	$	304,302	$	—	$	—	$	304,302
Surety bonds		87,889		31,105		9,998		128,992

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 our 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 Arch Coal’s audit committee on a periodic basis. Actual results may differ from the estimates used under different assumptions or conditions. We have provided a description of all significant accounting policies in the notes to our consolidated financial statements. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity:

Asset Retirement Obligations

Our asset retirement obligations arise from SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. Our asset

retirement obligations are initially recorded at fair value, or the amount at which the obligations could be settled in a current transaction between willing parties. This involves determining the present value of estimated future cash flows on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage and reclamation costs and assumptions regarding productivity. We estimate disturbed acreage based on approved mining plans and related engineering data. Since we plan to use internal resources to perform the majority of our reclamation activities, our estimate of reclamation costs involves estimating third-party profit margins, which we base on our historical experience with contractors that perform certain types of reclamation activities. We base productivity assumptions on historical experience with the equipment that we expect to utilize in the reclamation activities. In order to determine fair value, we must also discount our estimates of cash flows to their present value. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.

On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the actual cost of reclamation and the fair value will be recorded as a gain or loss when the obligation is settled. We expect our actual cost to reclaim our properties will be less than the expected cash flows used to determine the asset retirement obligation. At December 31, 2007, we had recorded asset retirement obligation liabilities of $195.7 million, including amounts classified as a current liability. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2007, we estimate that the aggregate undiscounted cost of final mine closure is approximately $482.4 million.

Employee Benefit Plans

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

We also currently provide certain postretirement medical and life insurance coverage for eligible employees 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 benefit 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. During 2007, the postretirement benefit plans were amended to improve benefits to participants. As a result of the amendment, annual retiree contribution increases have been limited so as not to exceed 25% of the previous year’s total contribution. Prior to the amendment, all medical cost increases were passed on to the retirees and had no impact on the plan. Arch Coal reports separately on the assumptions used in the determination of net periodic benefit costs and benefit obligation associated with its postretirement plans.

Actuarial assumptions are required to determine the amounts reported by us related to Arch Coal’s defined benefit pension plan and the postretirement benefit plan. The impact of lowering the expected long-term rate of return on pension plan assets 0.5% in 2007 would have been an increase in expense of approximately $0.5 million. The impact of lowering the discount rate 0.5% in 2007 would have been an increase in net periodic pension and postretirement costs of approximately $1.6 million.

Accounting Standards Issued and Not Yet Adopted

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements, which we refer to as Statement No. 157. Statement No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Statement No. 157 applies under other accounting pronouncements that require or permit fair value measurements. Statement No. 157 is effective prospectively for fiscal years beginning after November 15, 2007, and interim periods within that fiscal year. The FASB deferred the effective date of Statement No. 157 for one year for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. We do not expect the impact of adoption will be material.

regarding the interests of the parent and its noncontrolling interest. Statement No. 160 is effective for fiscal years beginning on or after December 15, 2008. Early adoption is not allowed. We are still analyzing Statement No. 160 to determine what the impact of adoption will be.

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

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

We are also exposed to the risk of fluctuations in cash flows related to our purchase of diesel fuel. We use approximately 38 million gallons of diesel fuel annually in our operations. Arch Coal enters into heating oil swaps and options to reduce volatility in the price of diesel fuel for our operations. The swap agreements essentially fix the price paid for diesel fuel by requiring us to pay a fixed heating oil price and receive a floating heating oil price. The call options protect against increases in diesel fuel by granting us the right to participate in increases in heating oil prices. The settlements related to these swaps and options are allocated to us through the Arch Coal intercompany account.

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At December 31, 2007, with the exception of our outstanding commercial paper, all of our outstanding debt bore interest at fixed rates.

Item 8. Financial Statements and Supplementary Data.

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

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

None.

Item 9A(T). 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, 2007. 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, 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Our managing member is an indirect, wholly-owned subsidiary of Arch Coal. As a result, we are effectively managed by the management of Arch Coal. You should see the list of Arch Coal’s executive officers and related information under “Executive Officers” beginning on page 17.

The following is a list of directors of Arch Coal, other than Messrs. Eaves and Leer, whose biographical information is contained under “Executive Officers” beginning on page 17, their ages on March 15, 2008 and biographical information:


			Director of
			Arch Coal
Name	Age		Since		Occupation and Other Information
James R. Boyd		61		1990	Mr. Boyd served as chairman of the board of directors of Arch Coal from 1998 to April 2006, when he was appointed Arch Coal’s lead director. Mr. Boyd served as Senior Vice President and Group Operating Officer of Ashland Inc. from 1989 until his retirement in 2002. Mr. Boyd also serves on the board of directors of Halliburton Inc.

Frank M. Burke		68		2000	Mr. Burke 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 also serves on the board of directors of Corrigan Investments, Inc. and is a member of the National Petroleum Council.

Patricia F. Godley		59		2004	Since 1998, Ms. Godley has been a partner with the law firm of Van Ness Feldman, practicing in the areas of economic and environmental regulation of electric utilities and natural gas companies. Ms. Godley is also a director of the United States Energy Association.

Douglas H. Hunt		55		1995	Since 1995, Mr. Hunt has served as Director of Acquisitions of Petro-Hunt, LLC, a private oil and gas exploration and production company.

Brian J. Jennings		47		2006	Since April 2007, Mr. Jennings has served as Chief Financial Officer of Energy Transfer Partners GP, L.P., the general partner of Energy Transfer Partners, L.P., a publicly-traded partnership owning and operating a portfolio of midstream energy assets. From March 2004 to December 2006, Mr. Jennings served as Senior Vice President - - Corporate Finance and Development and Chief Financial Officer of Devon Energy Corporation. Mr. Jennings served as Senior Vice President - - Corporate Finance and Development of Devon Energy Corporation from 2001 to March 2004.

Thomas A. Lockhart		72		2003	Mr. Lockhart has been a member of the Wyoming State House of Representatives since 2000. Mr. Lockhart also serves on the board of directors of First Interstate Bank of Casper, Wyoming and Blue Cross Blue Shield of Wyoming.

A. Michael Perry		71		1998	Mr. Perry served as Chairman of Bank One, West Virginia, N.A. from 1993 and as its Chief Executive Officer from 1983 until his retirement in 2001. Mr. Perry also serves on the board of directors of Champion Industries, Inc. and Portec Rail Products, Inc.

Robert G. Potter		68		2001	Mr. Potter was Chairman and Chief Executive Officer of Solutia, Inc. from 1997 until his retirement in 1999. Mr. Potter also serves on the board of directors of Stepan Company.


			Director of
			Arch Coal
Name	Age		Since		Occupation and Other Information
Theodore D. Sands		62		1999	Since 1999, Mr. Sands has served as President of HAAS Capital, LLC, a private consulting and investment company. Mr. Sands also serves on the board of directors of Protein Sciences Corporation and Terra Nitrogen Corporation.

Wesley M. Taylor		65		2005	Mr. Taylor was President of TXU Generation, a company engaged in electricity infrastructure ownership and management. Mr. Taylor served at TXU for 38 years prior to his retirement in 2004. Mr. Taylor also serves on the board of directors of First Energy Corporation.

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

Item 11. Executive Compensation.

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


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

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

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

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

Our cash transactions are managed by Arch Coal. Cash paid to or from us that is not considered a distribution or a contribution is recorded in an Arch Coal receivable account. In addition, any amounts owed between us and Arch Coal are recorded in the account. The receivable from Arch Coal was $1.4 billion at December 31, 2007 and $1.2 billion at December 31, 2006. This amount earns interest from Arch Coal at the prime interest rate. Interest earned was $99.2 million in 2007, $81.2 million in 2006 and $44.8 million in 2005. 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 noncurrent.

We mine on tracts that are owned or leased by Arch Coal and subleased to us. Certain subleases required an annual advance royalty payment of $10.0 million for the year ended December 31, 2005 which are 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 revised agreement. We incurred production royalties of $35.8 million in 2007, $41.4 million in 2006 and $23.2 million in 2005 under sublease agreements with Arch Coal.

Amounts charged to the intercompany account for our allocated portion of pension and postretirement contributions totaled $1.4 million in 2007, $17.0 million in 2006 and $12.9 million in 2005.

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 $26.3 million in 2007, $23.5 million in 2006 and $24.0 million in 2005. Such amounts are reported as selling, general and administrative expenses in our statements of income.

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

Item 14. Principal Accounting Fees and Services.

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

PART IV

Item 15. Exhibits and Financial Statement Schedules

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

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

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The consolidated financial statements of Arch Western Resources, LLC and subsidiaries and reports of its independent registered public accounting firm and management follow.

Index to Consolidated Financial Statements


Report of Independent Registered Public Accounting Firm			F-2
Management’s Report on Internal Control over Financial Reporting			F-3
Consolidated Statements of Income for the Years Ended December 31, 2007, 2006 and 2005			F-4
Consolidated Balance Sheets at December 31, 2007 and 2006			F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005			F-6
Consolidated Statements of Non-Redeemable Membership Interest for the Years Ended December 31, 2007, 2006 and 2005			F-7
Notes to Consolidated Financial Statements			F-8
Financial Statement Schedule			F-28

F-1

Report of Independent Registered Public Accounting Firm

The Members
Arch Western Resources, LLC

We have audited the accompanying consolidated balance sheets of Arch Western Resources, LLC and subsidiaries (the Company) as of December 31, 2007 and 2006, 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, 2007. Our audits also included the financial statement schedule listed in the index at Item 15. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Arch Western Resources, LLC and subsidiaries at December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for stripping costs effective January 1, 2006. As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for pension and other postretirement benefits effective December 31, 2006.

/s/ Ernst & Young LLP

St. Louis, Missouri
March 27, 2008

F-2

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management Arch Western Resources, LLC (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Securities Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Company’s management, including its principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the criteria set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, management concluded that the Company’s internal control over financial reporting is effective as of December 31, 2007.

This annual report does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.



Paul A. Lang		Robert J. Messey
President		Senior Vice President and Chief
		Financial Officer

F-3

ARCH WESTERN RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME


	Year Ended December 31
	2007			2006			2005
	(In thousands)
Revenues
Coal sales	$	1,541,066		$	1,491,362		$	1,126,742
Costs, expenses and other
Cost of coal sales		1,192,348			1,049,429			865,760
Depreciation, depletion and amortization		135,294			108,272			98,347
Selling, general and administrative expenses		26,298			23,466			23,958
Other operating income
Gain on sale of certain Powder River Basin assets		—			—			(43,297	)
Other income		(10,145	)		(4,068	)		(4,087	)

		1,343,795			1,177,099			940,681

Income from operations		197,271			314,263			186,061
Interest income (expense), net
Interest expense		(72,147	)		(72,273	)		(65,543	)
Interest income, primarily from Arch Coal, Inc.		99,683			81,853			45,233

		27,536			9,580			(20,310	)

Other non-operating expense
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps		(3,146	)		(7,928	)		(12,688	)

Income before minority interest		221,661			315,915			153,063
Minority interest		(20,496	)		(28,902	)		(24,219	)

Net income	$	201,165		$	287,013		$	128,844

Net income attributable to redeemable membership interest	$	1,006		$	1,435		$	644
Net income attributable to non-redeemable membership interest	$	200,159		$	285,578		$	128,200

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

F-4

ARCH WESTERN RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31
	2007			2006
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	248		$	186
Trade accounts receivable		388			985
Other receivables		3,171			14,733
Inventories		141,626			94,828
Other		27,128			27,403

Total current assets		172,561			138,135

Property, plant and equipment
Coal lands and mineral rights		762,939			762,819
Plant and equipment		1,127,416			973,359
Deferred mine development		398,453			357,736

		2,288,808			2,093,914
Less accumulated depreciation, depletion and amortization		(1,062,815	)		(860,068	)

Property, plant and equipment, net		1,225,993			1,233,846

Other assets
Receivable from Arch Coal, Inc.		1,427,833			1,152,102
Other		25,800			33,689

Total other assets		1,453,633			1,185,791

Total assets	$	2,852,187		$	2,557,772

LIABILITIES AND MEMBERS’ INTERESTS
Current liabilities
Accounts payable	$	82,254		$	110,725
Accrued expenses		128,754			129,495
Commercial paper		74,959			—

Total current liabilities		285,967			240,220
Long-term debt		957,514			958,881
Accrued postretirement benefits other than pension		36,805			31,036
Asset retirement obligations		194,190			174,902
Accrued workers’ compensation		8,784			10,027
Other noncurrent liabilities		30,725			38,705

Total liabilities		1,513,985			1,453,771


Redeemable membership interest		8,000			6,934

Minority interest		183,018			162,522
Non-redeemable membership interest		1,147,184			934,545

Total liabilities and membership interests	$	2,852,187		$	2,557,772

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

F-5

ARCH WESTERN RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31
	2007			2006			2005
	(In thousands)
Operating Activities
Net income	$	201,165		$	287,013		$	128,844
Adjustments to reconcile to cash provided by operating activities
Depreciation, depletion and amortization		135,294			108,272			98,347
Prepaid royalties expensed		3,784			5,264			12,722
Net (gain) loss on dispositions of property, plant and equipment		(6,125	)		221			(44,525	)
Minority interest		20,496			28,902			24,219
Other non-operating expense		3,146			7,928			12,688
Changes in operating assets and liabilities
Trade and other receivables		12,159			97,723			(28,496	)
Inventories		(46,798	)		(33,904	)		(20,577	)
Accounts payable and accrued expenses		(29,306	)		38,767			35,054
Accrued postretirement benefits other than pension		2,772			5,817			2,344
Asset retirement obligations		20,451			11,917			6,143
Accrued workers’ compensation		488			(420	)		(1,149	)
Other		7,238			(17,834	)		184

Cash provided by operating activities		324,764			539,666			225,798

Investing Activities
Capital expenditures		(147,423	)		(260,368	)		(108,600	)
Increase in receivable from Arch Coal, Inc.		(276,370	)		(279,135	)		(187,280	)
Additions to prepaid royalties		(532	)		(409	)		(12,807	)
Proceeds from dispositions of property, plant and equipment		6,541			295			81,755
Reimbursement of deposit on equipment		18,325			—			—

Cash used in investing activities		(399,459	)		(539,617	)		(226,932	)

Financing Activities
Net proceeds from commercial paper		74,959			—			—
Debt financing costs		(202	)		(15	)		(65	)

Cash provided by (used in) financing activities		74,757			(15	)		(65	)

Increase (decrease) in cash and cash equivalents		62			34			(1,199	)
Cash and cash equivalents, beginning of year		186			152			1,351

Cash and cash equivalents, end of year	$	248		$	186		$	152

Supplemental cash flow information:
Cash paid during the year for interest	$	65,282		$	64,125		$	65,423

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

F-6

ARCH WESTERN RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF NON-REDEEMABLE MEMBERSHIP INTEREST

Three years ended December 31, 2007


	Non-redeemable
	Common
	Membership
	Interest
	(In thousands)
Balance at January 1, 2005	$	543,058
Comprehensive income
Net income		128,200
Net losses on derivatives reclassified to income		12,625
Pension, postretirement and other post-employment benefits adjustment		(6,116	)

Total comprehensive income		134,709
Contribution by BP p.l.c.		120
Unearned compensation		3
Dividends on preferred membership interest		(95	)


Balance at December 31, 2005		677,795
Comprehensive income
Net income		285,578
Net losses on derivatives reclassified to income		7,888
Pension, postretirement and other post-employment benefits adjustment		1,694

Total comprehensive income		295,160
Effect of adoption of EITF 04-6		(39,401	)
Effect of adoption of Statement No. 158		994
Employee stock-based compensation expense		89
Dividends on preferred membership interest		(92	)


Balance at December 31, 2006		934,545
Comprehensive income
Net income		200,159
Net losses on derivatives reclassified to income		3,130
Pension, postretirement and other post-employment benefits adjustment		7,773
Net pension, postretirement and other post-employment benefits adjustments reclassified to income		1,762

Total comprehensive income		212,824
Employee stock-based compensation expense		(93	)
Dividends on preferred membership interest		(92	)


Balance at December 31, 2007	$	1,147,184

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

F-7

ARCH WESTERN RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Formation of the Company

On June 1, 1998, Arch Coal, Inc. (“Arch Coal”) acquired the Colorado and Utah coal operations of Atlantic Richfield Company (“ARCO”) and simultaneously combined the acquired ARCO operations and Arch Coal’s Wyoming operation with ARCO’s Wyoming operations in a new joint venture named Arch Western Resources, LLC (the “Company”). ARCO was acquired by BP p.l.c. (formerly BP Amoco) in 2000. Arch Coal has a 99.5% common membership interest in the Company, while BP p.l.c. has a 0.5% common membership interest and a 0.5% preferred membership interest in the Company. Net profits and losses are allocated only to the common membership interests on the basis of 99.5% to Arch Coal and 0.5% to BP p.l.c. In accordance with the membership agreement of the Company, no profit or loss is allocated to the preferred membership interest of BP p.l.c. Except for a preferred return, distributions to members are allocated on the basis of 99.5% to Arch Coal and 0.5% to BP p.l.c. The preferred return entitles BP p.l.c. to receive an annual distribution from the common membership interests equal to 4% of the preferred capital account balance at the end of the year. The preferred return is payable at the Company’s discretion.

In connection with the formation of the Company, Arch Coal agreed to indemnify BP p.l.c. against certain tax liabilities in the event that such liabilities arise as a result of certain actions taken by Arch Coal or the Company prior to June 1, 2013. The provisions of the indemnification agreement may restrict the Company’s ability to sell or dispose of certain properties, repurchase certain of its equity interests or reduce its indebtedness.

2. Accounting Policies

Basis of Presentation

The consolidated financial statements include the accounts of the Company and its subsidiaries and controlled entities. The Company’s primary business is the production of steam coal from surface and underground mines for sale to utility and industrial markets. The Company’s mines are located in Wyoming, Colorado and Utah. Intercompany transactions and accounts have been eliminated in consolidation.

Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost. Cash equivalents consist of highly-liquid investments with an original maturity of three months or less when purchased.

Allowance for Uncollectible Receivables

The Company’s allowance for uncollectible receivables reflects the amounts of its trade accounts receivable and other receivables that are not expected to be collected, based on past collection history, the economic environment and specified risks identified in the receivables portfolio. Receivables are considered past due if the full payment is not received by the contractual due date. No allowance was considered necessary at December 31, 2007. At December 31, 2006 the allowance was $1.0 million.

Inventories

Coal and supplies inventories are valued at the lower of average cost or market. Coal inventory costs include labor, supplies, equipment costs, transportation costs prior to title transfer to customers and operating overhead. Prior to the adoption of Emerging Issues Task Force Issue No. 04-6, Accounting for Stripping Costs in the Mining Industry (“EITF 04-6”), the Company had classified

F-8

stripping costs associated with the tons of coal uncovered and not yet extracted (pit inventory) at its surface mining operations as coal inventory. As a result of the adoption of EITF 04-6 on January 1, 2006, stripping costs incurred during the production phase of the mine are considered variable production costs and are included in the cost of inventory extracted during the period the stripping costs are incurred. The effect of adopting EITF 04-6 was a reduction of $37.6 million and $2.0 million in inventory and deferred development costs, respectively, with a corresponding decrease to membership interests of $39.6 million.

Prepaid Royalties

Rights to leased coal lands are often acquired through royalty payments. Where royalty payments represent prepayments recoupable against future production, they are recorded as a prepaid asset, with amounts expected to be recouped within one year classified as current. As mining occurs on these leases, the prepayment is charged to cost of coal sales.

Coal Supply Agreements

Acquisition costs allocated to coal supply agreements (sales contracts) are capitalized and amortized over the tons of coal shipped during the term of the contract. Value is allocated to coal supply agreements based on discounted cash flows attributable to the difference between the contract price and the prevailing market price at the date of acquisition. The net book value of the Company’s above-market coal supply agreements was $3.5 million and $3.8 million at December 31, 2007 and 2006, respectively. These amounts are recorded in other current assets and other assets in the accompanying Consolidated Balance Sheets. The net book value of the below-market coal supply agreements was $1.3 million and $3.2 million at December 31, 2007 and 2006, respectively. These amounts are recorded in accrued expenses and other noncurrent liabilities in the accompanying Consolidated Balance Sheets. Amortization expense on all above-market coal supply agreements was $0.3 million, $1.0 million and $8.0 million in 2007, 2006 and 2005, respectively. Amortization income on all below-market coal supply agreements was $1.9 million, $11.8 million and $16.0 million in 2007, 2006 and 2005, respectively.

Property, Plant and Equipment

Plant and Equipment

Plant and equipment are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. During the years ended December 31, 2007, 2006 and 2005, interest costs of $4.3 million, $3.6 million and $1.6 million, respectively, were capitalized. Expenditures that extend the useful lives of existing plant and equipment or increase the productivity of the asset are capitalized. The cost of maintenance and repairs that do not extend the useful life or increase the productivity of the asset are expensed as incurred. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets, which generally range from three to 30 years, except for preparation plants and loadouts. Preparation plants and loadouts are depreciated using the units-of-production method over the estimated recoverable reserves, subject to a minimum level of depreciation.

Deferred Mine Development

Costs of developing new mines or significantly expanding the capacity of existing mines are capitalized and amortized using the units-of-production method over the estimated recoverable reserves that are associated with the property being benefited. Costs may include construction permits and licenses; mine design; construction of access roads, shafts, slopes and main entries; and removing overburden to access reserves in a new pit. Additionally, deferred mine development includes the costs associated with asset retirement obligations.

Coal Lands and Mineral Rights

Amounts paid to acquire the Company’s coal reserves are capitalized and depleted over the life of proven and probable reserves. A significant portion of the Company’s coal reserves are controlled through leasing arrangements. The cost of coal lease rights are depleted using the units-of-production method, and the rights are assumed to have no residual value. The leases are generally long-term in nature (original terms range from 10 to 50 years), and substantially all of the leases contain provisions that allow for automatic extension of the lease term as long as mining continues. The net book value of the Company’s leased coal interests was $419.3 million and $452.9 million at December 31, 2007 and 2006, respectively.

F-9

Impairment

If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed for recoverability. If this review indicates that the carrying amount of the asset will not be recoverable through projected undiscounted cash flows related to the asset over its remaining life, then an impairment loss is recognized by reducing the carrying value of the asset to its fair value.

Deferred Financing Costs

The Company capitalizes costs incurred in connection with borrowings or establishment of credit facilities and issuance of debt securities. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using the interest method. Deferred financing costs were $11.9 million and $13.9 million at December 31, 2007 and 2006, respectively. These amounts are recorded in other assets in the accompanying Consolidated Balance Sheets. Amounts classified as current were $2.3 million and $2.2 million at December 31, 2007 and 2006, respectively. These amounts are recorded in other current assets in the accompanying Consolidated Balance Sheets.

Revenue Recognition

Coal sales revenues include sales to customers of coal produced at Company operations. The Company recognizes revenue from coal sales at the time risk of loss passes to the customer at contracted amounts. Transportation costs are included in cost of coal sales and amounts billed by the Company to its customers for transportation are included in coal sales.

Other Operating Income

Other operating income in the accompanying Consolidated Statements of Income reflects income and expense from sources other than coal sales, primarily gains and losses from dispositions of long-term assets.

Asset Retirement Obligations

The Company’s legal obligations associated with the retirement of long-lived assets are recognized at fair value at the time the obligations are incurred. Obligations are incurred at the time development of a mine commences for underground and surface mines or construction begins for support facilities, refuse areas and slurry ponds. The obligation’s fair value is determined using discounted cash flow techniques and is accreted over time to its expected settlement value. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying amount of the related long-lived asset. Amortization of the related asset is recorded on a units-of-production basis over the mine’s estimated recoverable reserves. See additional discussion in Note 13, “Asset Retirement Obligations.”

Derivative Financial Instruments

The Company has used derivative financial instruments to manage exposures to interest rates. Derivative financial instruments are recognized in the balance sheet at fair value. Changes in fair value are recognized in earnings if they are not eligible for hedge accounting or in other comprehensive income if they qualify for cash flow hedge accounting. Amounts in other comprehensive income are reclassified to earnings when the hedged transaction affects earnings.

In the fourth quarter of 2005, the Company terminated certain interest rate swap agreements that at one time had been designated as a hedge of interest rate volatility on floating rate debt. The amounts that had been deferred in accumulated other comprehensive income were amortized as additional expense over the contractual terms of the swap agreements prior to their termination. For the years ended December 31, 2007, 2006 and 2005, the Company recognized $3.1 million, $7.9 million and $12.7 million of other non-operating expense, respectively, related to the amortization of the balance in other comprehensive income.

Income Taxes

The financial statements do not include a provision for income taxes as the Company is treated as a partnership for income tax purposes and does not incur federal or state income taxes. Instead, its earnings and losses are included in the members’ separate income tax returns.

F-10

Related Party 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 the Company’s results of operations. See Note 14, “Related Party Transactions” for discussion of various transactions with Arch Coal.

Benefit Plans

Essentially all of the Company’s employees are covered by Arch Coal’s defined benefit pension plan. The benefits are based on the employee’s age and compensation. The Company also provides certain postretirement medical and life insurance benefits for eligible employees under Arch Coal’s plans. The employee postretirement medical and life plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The Company reflects its actuarially-determined allocation of benefit cost, benefit obligation and other comprehensive income in its consolidated financial statements. See further discussion in Note 12, “Employee Benefit Plans.”

On December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (“Statement No. 158”). Statement No. 158 requires that an employer recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) and other postemployment benefits determined on an actuarial basis as an asset or liability in its balance sheet and to recognize changes in the funded status though comprehensive income when they occur. Statement No. 158 also requires an employer to measure the funded status of a plan as of the date of its year-end balance sheet. Statement No. 158 is applicable to our pneumoconiosis obligations under the Federal Mine Safety and Health Act of 1969, as subsequently amended. See Note 11, “Accrued Workers’ Compensation” for additional disclosures relating to these obligations. The actuarially-determined allocation of benefit cost, benefit obligation and other comprehensive income related to the pension and postretirement benefits under Arch Coal’s plans are determined in accordance with Statement No. 158.

Accounting Standards Issued and Not Yet Adopted

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements (“Statement No. 157”). Statement No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements under other accounting pronouncements that require or permit fair value measurements. Statement No. 157 is effective prospectively for fiscal years beginning after November 15, 2007, and interim periods within that fiscal year. The FASB deferred the effective date of Statement No. 157 for one year for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. The Company does not expect adoption of Statement No. 157 to have a material impact on the Company’s financial position or results of operations.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Liabilities — Including an amendment of FASB Statement No. 115 (“Statement No. 159”). Statement No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Statement No. 159 is effective prospectively for fiscal years beginning after November 15, 2007. The Company does not expect adoption of Statement No. 159 to have a material impact on the Company’s financial position or results of operations.

In December 2007, the FASB issued Statement on Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (“Statement No. 160”). Statement No. 160 requires that a noncontrolling interest (minority interest) in a consolidated subsidiary be displayed in the consolidated balance sheet as a separate component of equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the consolidated statement of income. Statement No. 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. Statement No. 160 is effective for fiscal years beginning on or after December 15, 2008. Early adoption is not allowed. The Company is still analyzing Statement No. 160 to determine what the impact of adoption will be.

F-11

3. Redeemable Membership Interest

The terms of the Company’s membership agreement grant a put right to BP p.l.c., where BP p.l.c. may require Arch Coal to purchase its membership interest. The terms of the agreement state that the price of the membership interest shall be determined by mutual agreement between the members. In the absence of an agreed-upon price, the price is equal to the sum of the preferred membership interest of $2.4 million and BP p.l.c.’s common membership interest, as defined in the agreement. In addition, Arch Coal has a call right, which allows Arch Coal to purchase BP p.l.c.’s members’ interest as long as it pays damages as set forth in the agreement between the members. It is the members’ intention at this point to continue the joint venture.

The following table presents the components of and changes in BP p.l.c.’s membership interest:


						Total
	Common			Preferred		Redeemable
	Membership			Membership		Membership
	Interest			Interest		Interest
	(In thousands)
Balance at January 1, 2005	$	2,572		$	2,399	$	4,971
Net income attributable to BP p.l.c. common membership interest		644			—		644
Other comprehensive income attributable to BP p.l.c. common membership interest		33			—		33
Dividends on preferred membership interest		(1	)		—		(1	)

Balance at December 31, 2005		3,248			2,399		5,647

Net income attributable to BP p.l.c. common membership interest		1,435			—		1,435
Other comprehensive income attributable to BP p.l.c. common membership interest		49			—		49
Effect of adoption of EITF 04-6		(198	)		—		(198	)
Effect of adoption of Statement No. 158		5			—		5
Dividends on preferred membership interest		(4	)		—		(4	)

Balance at December 31, 2006		4,535			2,399		6,934

Net income attributable to BP p.l.c. common membership interest		1,006			—		1,006
Other comprehensive income attributable to BP p.l.c. common membership interest		64			—		64
Dividends on preferred membership interest		(4	)		—		(4	)

Balance at December 31, 2007	$	5,601		$	2,399	$	8,000

4. Dispositions

On December 30, 2005, the Company sold to Peabody Energy Corporation a rail spur, rail loadout and an idle office complex located in the Powder River Basin for a purchase price of $79.6 million. In conjunction with the transactions, the Company will continue to lease the rail spur and loadout and office facilities through September 2008 while it mines adjacent reserves. The Company recognized a gain of $43.3 million on the transaction, after the deferral of $7.0 million of the gain, equal to the present value of the lease payments. The deferred gain will be recognized over the term of the lease. See further discussion in Note 16, “Leases.”

In 2007 we recognized a gain of $6.0 million on the sale of non-strategic reserves in the Powder River Basin, which is included in other operating income, net in the accompanying Consolidated Statements of Income.

5. Insurance Recoveries

A combustion-related event in October 2005 caused the idling of the Company’s West Elk mine in Colorado into the first quarter of 2006, which cost the Company an estimated $30.0 million in lost profits during the first quarter of 2006, in addition to the effect of the idling and fire-fighting costs incurred during the fourth quarter of 2005 of $33.3 million. The Company recorded insurance recoveries in 2006 related to the event of $41.9 million. Of these recoveries, $19.5 million was for business interruption. The insurance recoveries are reflected as a reduction of cost of coal sales in the accompanying Consolidated Statements of Income.

F-12

6. Accumulated Other Comprehensive Income (Loss)

Other comprehensive income (loss) items under Statement of Financial Accounting Standards No. 130, Reporting Comprehensive Income, are transactions recorded in membership interest during the year, excluding net income and transactions with members. Following are the items included in accumulated other comprehensive loss:


							Accumulated
				Pension, Postretirement			Other
	Financial			and Other Post-			Comprehensive
	Derivatives			Employment Benefits			Loss
	(In thousands)
Balance January 1, 2005	$	(23,762	)	$	(8,384	)	$	(32,146	)
2005 activity		12,688			(6,146	)		6,542

Balance December 31, 2005		(11,074	)		(14,530	)		(25,604	)
2006 activity		7,928			2,702			10,630

Balance December 31, 2006		(3,146	)		(11,828	)		(14,974	)
2007 activity		3,146			9,583			12,729

Balance December 31, 2007	$	—		$	(2,245	)	$	(2,245	)

7. Inventories

Inventories consist of the following:


	December 31
	2007		2006
	(In thousands)
Coal	$	42,942	$	31,350
Repair parts and supplies, net of allowance		98,684		63,478

	$	141,626	$	94,828

The repair parts and supplies are stated net of an allowance for slow-moving and obsolete inventories of $12.5 million and $12.1 million at December 31, 2007 and 2006, respectively.

The increase in repair parts and supplies is primarily the result of an increase in tire inventories and higher costs associated with materials and supplies.

8. Accrued Expenses

Accrued expenses consist of the following:


	December 31
	2007		2006
	(In thousands)
Payroll and employee benefits	$	20,208	$	20,361
Taxes other than income taxes		68,162		63,815
Interest		32,323		32,063
Asset retirement obligations		1,500		7,133
Other accrued expenses		6,561		6,123

	$	128,754	$	129,495

9. Debt and Financing Arrangements

On August 15, 2007, the Company entered into a commercial paper placement program, as amended, to provide short-term financing at rates that are generally lower than the rates available under Arch Coal’s revolving credit facility. Under the program, the Company may sell up to $75.0 million in interest-bearing or discounted short-term unsecured debt obligations with maturities of no more than 270 days. The commercial paper placement program is supported by a $75.0 million revolving credit facility with a maturity date of June 7, 2008. As of December 31, 2007, the weighted-average interest rate of the Company’s outstanding commercial paper was 5.08% and maturity dates ranged from 2 to 81 days.

F-13

Under an indenture dated June 25, 2003, the Company’s subsidiary, Arch Western Finance LLC (“Arch Western Finance”), issued $950.0 million of 6.75% Senior Notes due July 1, 2013. The senior notes are guaranteed by the Company and certain of the Company’s subsidiaries and are secured by a security interest in the Company’s receivable from Arch Coal. The terms of the senior notes contain restrictive covenants that limit the Company’s ability to, among other things, incur additional debt, sell or transfer assets, and make certain investments. Arch Western Finance issued $250.0 million of the Senior Notes at a premium of 104.75% of par. The premium is being amortized over the life of the bonds.

10. Fair Values of Financial Instruments

The following methods and assumptions were used by the Company in estimating its fair value disclosures for financial instruments:

Cash and cash equivalents: At December 31, 2007 and 2006, the carrying amounts of cash and cash equivalents approximate fair value.

Debt: The fair value of the Company’s debt was $1.0 billion and $950.5 million at December 31, 2007 and 2006, respectively.

11. Accrued Workers’ Compensation

The Company is liable under the Federal Mine Safety and Health Act of 1969, as subsequently amended, to provide for pneumoconiosis (occupational disease) benefits to eligible employees, former employees, and dependents. The Company is also liable under various states’ statutes for occupational disease benefits. The Company currently provides for federal and state claims principally through a self-insurance program. The occupational disease benefit obligation is determined by independent actuaries, at the present value of the actuarially computed present and future liabilities for such benefits over the employees’ applicable years of service.

In addition, the Company is liable for workers’ compensation benefits for traumatic injuries that are accrued as injuries are incurred. Traumatic claims are either covered through self-insured programs or through state-sponsored workers’ compensation programs.

Workers’ compensation expense consists of the following components:


	Year Ended December 31
	2007			2006			2005
	(In thousands)
Self-insured occupational disease benefits:
Service cost	$	651		$	347		$	266
Interest cost		435			390			423
Net amortization		(372	)		(513	)		(409	)

Total occupational disease		714			224			280
Traumatic injury claims and assessments		1,373			1,821			506

Total workers’ compensation expense	$	2,087		$	2,045		$	786

Net amortization represents the systematic recognition of actuarial gains or losses over a five-year period.

The reconciliation of changes in the benefit obligation of the occupational disease liability is as follows:


	December 31
	2007			2006
	(In thousands)
Beginning of year obligation	$	8,488		$	6,745
Service cost		651			347
Interest cost		435			390
Actuarial gain		(1,734	)		1,056
Benefit and administrative payments		(114	)		(50	)

Net obligation at end of year	$	7,726		$	8,488

At December 31, 2007 and 2006, accumulated gains of $2.4 million and $1.0 million, respectively, were not yet recognized in

F-14

occupational disease cost and were recorded in accumulated other comprehensive income. The accumulated gain that will be amortized from accumulated other comprehensive income into occupational disease cost in 2008 is $0.5 million.

The following table provides the assumptions used to determine the projected occupational disease obligation:


	Year Ended December 31
	2007			2006			2005
Weighted average assumptions:
Discount rate		6.50	%		5.90	%		5.80	%
Cost escalation rate		3.00	%		3.00	%		3.00	%

Summarized below is information about the amounts recognized in the accompanying Consolidated Balance Sheets for workers’ compensation benefits:


	December 31
	2007		2006
	(In thousands)
Occupational disease costs	$	7,726	$	8,488
Traumatic and other workers’ compensation claims		2,493		3,020

Total obligations		10,219		11,508
Less amount included in accrued expenses		1,435		1,481

Noncurrent obligations	$	8,784	$	10,027

12. Employee Benefit Plans

Defined Benefit Pension and Other Postretirement Benefit Plans

Essentially all of the Company’s employees are covered by Arch Coal’s defined benefit pension plan. The benefits are based on the employee’s age and compensation. Arch Coal funds the plans in an amount not less than the minimum statutory funding requirements or more than the maximum amount that can be deducted for federal income tax purposes. Arch Coal allocates a portion of the funding to the Company, which is charged to the intercompany balance. See Note 14, “Related Party Transactions” for further discussion.

The Company also provides certain postretirement medical/life insurance benefits for eligible employees 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 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 a portion of the funding to the Company, which is charged to the intercompany balance as benefits are paid.

The Company’s allocated expense related to these plans was $11.1 million, $13.1 million and $12.8 million for the years ended December 31, 2007, 2006 and 2005, respectively. The Company’s balance sheet reflects its allocated portion of Arch Coal’s liabilities and assets related to its benefit plans, including amounts recorded through other comprehensive income. The Company’s recorded balance sheet amounts are as follows:


	December 31
	2007			2006
	(In thousands)
Accrued benefit liabilities (current)	$	1,363		$	1,935
Accrued benefit liabilities (noncurrent)		37,010			35,153
Accumulated other comprehensive income (loss)		(4,646	)		12,828

Other Plans

Arch Coal sponsors savings plans which were established to assist eligible employees in providing for their future retirement needs. The Company’s expense related to the plans were $8.3 million in 2007, $7.3 million in 2006 and $5.7 million in 2005.

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13. Asset Retirement Obligations

The Company’s 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. The required reclamation activities to be performed are outlined in the Company’s mining permits. These activities include reclaiming the pit and support acreage at surface mines, sealing portals at underground mines, and reclaiming refuse areas and slurry ponds.

The Company accounts for its reclamation obligations in accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. The Company reviews its asset retirement obligation at least annually and makes necessary adjustments for permit changes as granted by state authorities and for revisions of estimates of the amount and timing of costs. For ongoing operations, adjustments to the liability result in an adjustment to the corresponding asset. For idle operations, adjustments to the liability are recognized as income or expense in the period the adjustment is recorded.

The following table describes the changes to the Company’s asset retirement obligations for the years ended December 31:


	2007			2006
	(In thousands)
Balance January 1 (including current portion)	$	182,035		$	144,444
Accretion expense		16,119			12,820
Adjustments to the liability from changes in estimates		(1,164	)		26,892
Liabilities settled		(1,300	)		(2,121	)

Balance at December 31		195,690			182,035
Current portion included in accrued expenses		(1,500	)		(7,133	)

Noncurrent liability	$	194,190		$	174,902

The adjustments from changes in estimates during the year ended December 31, 2006 resulted from changes in estimates of the timing of asset retirement costs and an increase in the cost estimates, primarily consumables such as tires.

As of December 31, 2007, the Company had $87.9 million in surety bonds outstanding and $304.3 million in self-bonding to secure reclamation obligations.

14. Related Party Transactions

The Company’s cash transactions are managed by Arch Coal. Cash paid to or from the Company that is not considered a distribution or a contribution is recorded in an Arch Coal receivable account. In addition, any amounts owed between the Company and Arch Coal are recorded in the account. At December 31, 2007 and 2006, the receivable from Arch Coal was $1.4 billion and $1.2 billion, respectively. This amount earns interest from Arch Coal at the prime interest rate. Interest earned for the years ended December 31, 2007, 2006 and 2005 was $99.2 million, $81.2 million and $44.8 million, respectively. The receivable is payable on demand by the Company; however, it is currently management’s intention to not demand payment of the receivable within the next year. Therefore, the receivable is classified on the accompanying Consolidated Balance Sheets as long-term.

On February 10, 2006, Arch Coal established an accounts receivable securitization program. Under the program, the Company sells its receivables to Arch Coal without recourse at a discount based on the prime rate and days sales outstanding. During both 2007 and 2006, the Company sold $1.5 billion of trade accounts receivable to Arch Coal, at a total discount of $9.8 million in 2007 and $10.5 million in 2006.

The Company mines on tracts that are owned or leased by Arch Coal and subleased to the Company. Certain subleases required an annual advance royalty payment of $10.0 million in the year ended December 31, 2005 which was fully recoupable against production through production royalties. All sublease agreements between the Company and Arch Coal were amended as of April 1, 2005 such that royalties on all properties leased from Arch Coal are 7.0% of the value of the coal mined and removed from the leased land, pursuant to Federal coal regulations. For the years ended December 31, 2007, 2006 and 2005, the Company incurred production royalties of $35.8 million, $41.4 million and $23.2 million, respectively, under sublease agreements with Arch Coal. No advance royalties are required under the revised agreements.

Amounts charged to the intercompany account for the Company’s allocated portion of cash contributions to Arch Coal’s pension and postretirement plans totaled $1.4 million, $17.0 million and $12.9 million for the years ended December 31, 2007, 2006 and 2005, respectively.

F-16

The Company is 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 behalf of the Company. Amounts allocated to the Company by Arch Coal were $26.3 million, $23.5 million and $24.0 million for the years ended December 31, 2007, 2006 and 2005, respectively. Such amounts are reported as selling, general and administrative expenses in the accompanying Consolidated Statements of Income.

15. Concentration of Credit Risk and Major Customers

The Company markets its coal principally to electric utilities in the United States. The Company has a formal written credit policy that establishes procedures to determine creditworthiness and credit limits for trade customers. Generally, credit is extended based on an evaluation of the customer’s financial condition. Collateral is not generally required, unless credit cannot be established. Credit losses are provided for in the financial statements and historically have been minimal.

The Company is committed under long-term contracts to supply coal that meets certain quality requirements at specified prices. These prices are generally adjusted based on indices. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer. The Company and its operating subsidiaries sold approximately 115.7 million tons of coal in 2007. Approximately 74% of this tonnage (representing approximately 76% of the Company’s revenue) was sold under long-term contracts (contracts having a term of greater than one year). Long-term contracts ranged in remaining life from one to 10 years. Some of these contracts include pricing which is above current market prices. Sales (including spot sales) to significant customers were as follows:


	Year Ended December 31
	2007		2006		2005
	(In thousands)
Tennessee Valley Authority	$	207,853	$	188,774	$	149,994
Ameren		162,802		136,647		73,381

Transportation

The Company depends upon rail, truck and belt transportation systems to deliver coal to its customers. Disruption of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair the Company’s ability to supply coal to its customers, resulting in decreased shipments. Disruptions in rail service in 2005 resulted in missed shipments and production interruptions.

16. Leases

The Company leases equipment, land and various other properties under non-cancelable long-term leases, expiring at various dates. Certain leases contain options that would allow the Company to extend the lease or purchase the leased asset at the end of the base lease term. Rental expense related to these operating leases amounted to $27.6 million in 2007, $21.0 million in 2006 and $16.1 million in 2005. In addition, the Company enters into various non-cancelable royalty lease agreements under which future minimum payments are due. Royalty expense was $200.1 million, $205.7 million and $140.3 million for the years ended December 31, 2007, 2006 and 2005, respectively, including $35.8 million, $41.4 million and $23.2 million, respectively, that were incurred under sublease agreements with Arch Coal. See Note 14, “Related Party Transactions” for further discussion.

Minimum payments due in future years under these agreements in effect at December 31, 2007 are as follows:


	Operating
	Leases		Royalties
	(In thousands)
2008	$	24,429	$	1,534
2009		23,965		1,510
2010		21,082		1,336
2011		18,240		1,289
2012		14,473		1,265
Thereafter		28,973		7,925

	$	131,162	$	14,859

F-17

On December 31, 2005, the Company sold its rail spur, rail loadout and idle office complex at its Thunder Basin mining complex in Wyoming, and agreed to lease them back for $0.2 million per month while it mines adjacent reserves. The lease contains an option for the Company to extend the lease on a month-to-month basis through September 2010. The Company deferred a gain on the sale, equal to the present value of the minimum lease payments, to be amortized over the term of the lease. At December 31, 2007 and 2006, the Company had deferred gains totaling $1.9 million and $4.5 million, respectively, related to the sale.

As of December 31, 2007, certain of the Company’s lease obligations were secured by outstanding surety bonds totaling $31.1 million.

17. Contingencies

The Company is a party to numerous claims and lawsuits with respect to various matters. The Company provides for costs related to contingencies 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 pending claims will not have a material adverse effect on the consolidated financial condition, results of operations or liquidity of the Company.

18. Segment Information

The Company has two reportable business segments, which are based on the major low-sulfur coal basins in which the Company operates. Both of these reportable business segments include a number of mine complexes. The Company manages its coal sales by coal basin, not by individual mine complex. Geology, coal transportation routes to customers, regulatory environments and coal quality are generally consistent within a basin. Accordingly, market and contract pricing have developed by coal basin. Mine operations are evaluated based on their per-ton operating costs (defined as including all mining costs but excluding pass-through transportation expenses), as well as on other non-financial measures, such as safety and environmental performance. The Company’s reportable segments are the Powder River Basin (PRB) segment, with operations in Wyoming, and the Western Bituminous (WBIT) segment, with operations in Utah, Colorado and southern Wyoming.

Operating segment results for the years ended December 31, 2007, 2006 and 2005 are presented below. Results for the operating segments include all direct costs of mining. Corporate, Other and Eliminations includes corporate overhead, land management, other support functions, and the elimination of intercompany transactions.


					Corporate,
					Other and
	PRB		WBIT		Eliminations			Consolidated
	(In thousands)
December 31, 2007
Coal sales	$	1,002,339	$	538,727	$	—		$	1,541,066
Income from operations		113,588		102,748		(19,065	)		197,271
Total assets		1,694,786		1,948,674		(791,273	)		2,852,187
Depreciation, depletion and amortization		69,288		66,006		—			135,294
Capital expenditures		48,141		99,282		—			147,423
December 31, 2006
Coal sales	$	1,032,416	$	458,946	$	—		$	1,491,362
Income from operations		214,821		128,874		(29,432	)		314,263
Total assets		1,584,483		1,841,104		(867,815	)		2,557,772
Depreciation, depletion and amortization		61,925		46,347		—			108,272
Capital expenditures		121,737		138,631		—			260,368
December 31, 2005
Coal sales	$	724,509	$	402,233	$	—		$	1,126,742
Income from operations		149,434		59,747		(23,120	)		186,061
Total assets		1,333,289		1,723,744		(841,657	)		2,215,376
Depreciation, depletion and amortization		64,983		33,364		—			98,347
Capital expenditures		30,668		77,932		—			108,600

F-18

Reconciliation of income from operations to net income:


	Year Ended December 31
	2007			2006			2005
	(In thousands)
Income from operations	$	197,271		$	314,263		$	186,061
Interest expense		(72,147	)		(72,273	)		(65,543	)
Interest income		99,683			81,853			45,233
Other non-operating expense		(3,146	)		(7,928	)		(12,688	)
Minority interest		(20,496	)		(28,902	)		(24,219	)

Net income	$	201,165		$	287,013		$	128,844

19. Supplemental Condensed Consolidating Financial Information

Pursuant to the indenture governing the Arch Western Finance senior notes, certain wholly-owned subsidiaries of the Company have fully and unconditionally guaranteed the senior notes on a joint and several basis. The following tables present condensed consolidating financial information for (i) the Company, (ii) the issuer of the senior notes (Arch Western Finance, LLC, a wholly-owned subsidiary of the Company), (iii) the Company’s wholly-owned subsidiaries (Thunder Basin Coal Company, LLC, Mountain Coal Company, LLC, and Arch of Wyoming, LLC), on a combined basis, which are guarantors under the Notes, and (iv) the Company’s majority-owned subsidiary (Canyon Fuel Company, LLC) which is not a guarantor under the Notes.

F-19

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
Year Ended December 31, 2007
(in thousands)


							Guarantor			Non-Guarantor
	Parent Company			Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Coal sales	$	—		$	—		$	1,166,872		$	374,194		$	—		$	1,541,066
Cost of coal sales		(1,086	)		—			924,960			270,867			(2,393	)		1,192,348
Depreciation, depletion and amortization		—			—			89,173			46,121			—			135,294
Selling, general and administrative expenses allocated from Arch Coal		26,298			—			—			—			—			26,298
Other operating income		(6,147	)		—			(2,686	)		(3,705	)		2,393			(10,145	)

		19,065			—			1,011,447			313,283			—			1,343,795
Income from investment in subsidiaries		219,151			—			—			—			(219,151	)		—

Income from operations		200,086			—			155,425			60,911			(219,151	)		197,271
Interest expense		(72,984	)		(60,631	)		(419	)		(2,226	)		64,113			(72,147	)
Interest income, primarily from Arch Coal		97,705			64,113			448			1,530			(64,113	)		99,683

		24,721			3,482			29			(696	)		—			27,536
Other non-operating expense		(3,146	)		—			—			—			—			(3,146	)
Minority interest		(20,496	)		—			—			—			—			(20,496	)

Net income	$	201,165		$	3,482		$	155,454		$	60,215		$	(219,151	)	$	201,165

F-20

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
Year Ended December 31, 2006
(in thousands)


							Guarantor			Non-Guarantor
	Parent Company			Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Coal sales	$	—		$	—		$	1,165,654		$	325,708		$	—		$	1,491,362
Cost of coal sales		3,759			—			813,825			231,310			535			1,049,429
Depreciation, depletion and amortization		—			—			80,626			27,646			—			108,272
Selling, general and administrative expenses allocated from Arch Coal		23,466			—			—			—			—			23,466
Other operating income		(124	)		—			(1,437	)		(1,972	)		(535	)		(4,068	)

		27,101			—			893,014			256,984			—			1,177,099
Income from investment in subsidiaries		343,437			—			—			—			(343,437	)		—

Income from operations		316,336			—			272,640			68,724			(343,437	)		314,263
Interest expense		(72,653	)		(61,309	)		(434	)		(1,946	)		64,069			(72,273	)
Interest income, primarily from Arch Coal		80,160			64,069			560			1,133			(64,069	)		81,853

		7,507			2,760			126			(813	)		—			9,580
Other non-operating expense		(7,928	)		—			—			—			—			(7,928	)
Minority interest		(28,902	)		—			—			—			—			(28,902	)

Net income	$	287,013		$	2,760		$	272,766		$	67,911		$	(343,437	)	$	287,013

F-21

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
Year Ended December 31, 2005
(in thousands)


							Guarantor			Non-Guarantor
	Parent Company			Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Coal sales	$	—		$	—		$	865,892		$	260,850		$	—		$	1,126,742
Cost of coal sales		1,410			—			670,340			194,539			(529	)		865,760
Depreciation, depletion and amortization		—			—			81,133			17,214			—			98,347
Selling, general and administrative expenses allocated from Arch Coal		23,958			—			—			—			—			23,958
Gain on sale of certain Powder River Basin assets		—			—			(43,297	)		—			—			(43,297	)
Other operating income		(823	)		—			(2,531	)		(1,262	)		529			(4,087	)

		24,545			—			705,645			210,491			—			940,681
Income from investment in subsidiaries		209,584			—			—			—			(209,584	)		—

Income from operations		185,039			—			160,247			50,359			(209,584	)		186,061
Interest expense		(64,063	)		(63,340	)		(2,207	)		—			64,067			(65,543	)
Interest income, primarily from Arch Coal		44,775			64,067			409			49			(64,067	)		45,233

		(19,288	)		727			(1,798	)		49			—			(20,310	)
Other non-operating expense		(12,688	)		—			—			—			—			(12,688	)
Minority interest		(24,219	)		—			—			—			—			(24,219	)

Net income	$	128,844		$	727		$	158,449		$	50,408		$	(209,584	)	$	128,844

F-22

CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2007
(in thousands)


						Guarantor			Non-Guarantor
	Parent Company			Issuer		Subsidiaries			Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	78		$	—	$	16		$	154	$	—		$	248
Trade accounts receivable		—			—		—			388		—			388
Other receivables		1,145			—		1,224			802		—			3,171
Inventories		—			—		98,638			42,988		—			141,626
Other		11,342			2,153		5,868			7,765		—			27,128

Total current assets		12,565			2,153		105,746			52,097		—			172,561


Property, plant and equipment, net		—			—		864,575			361,418		—			1,225,993

Investment in subsidiaries		2,140,722			—		—			—		(2,140,722	)		—
Receivable from Arch Coal, Inc.		1,399,046			—		(112	)		28,899		—			1,427,833
Intercompanies		(2,105,212	)		981,359		1,064,385			59,468		—			—
Other		802			9,617		11,611			3,770		—			25,800

Total other assets		1,435,358			990,976		1,075,884			92,137		(2,140,722	)		1,453,633

Total assets	$	1,447,923		$	993,129	$	2,046,205		$	505,652	$	(2,140,722	)	$	2,852,187

Accounts payable		3,434			—		62,504			16,316		—			82,254
Accrued expenses		2,863			32,063		83,515			10,313		—			128,754
Commercial paper		74,959			—		—			—		—			74,959
Total current liabilities		81,256			32,063		146,019			26,629		—			285,967
Long-term debt		—			957,514		—			—		—			957,514
Accrued postretirement benefits other than pension		24,482			—		2,485			9,838		—			36,805
Asset retirement obligations		—			—		182,101			12,089		—			194,190
Accrued workers’ compensation		4,293			—		1,053			3,438		—			8,784
Other noncurrent liabilities		(310	)		—		25,886			5,149		—			30,725

Total liabilities		109,721			989,577		357,544			57,143		—			1,513,985

Redeemable membership interest		8,000			—		—			—		—			8,000
Minority interest		183,018			—		—			—		—			183,018
Non-redeemable membership interest		1,147,184			3,552		1,688,661			448,509		(2,140,722	)		1,147,184

Total liabilities and membership interests	$	1,447,923		$	993,129	$	2,046,205		$	505,652	$	(2,140,722	)	$	2,852,187

F-23

CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2006
(in thousands)


						Guarantor			Non-Guarantor
	Parent Company			Issuer		Subsidiaries			Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—		$	—	$	161		$	25	$	—		$	186
Trade accounts receivable		—			—		—			985		—			985
Other receivables		1,007			—		13,453			273		—			14,733
Inventories		—			—		58,796			36,032		—			94,828
Other		11,439			2,154		8,883			4,927		—			27,403

Total current assets		12,446			2,154		81,293			42,242		—			138,135


Property, plant and equipment, net		—			—		879,211			354,635		—			1,233,846

Investment in subsidiaries		1,917,292			—		—			—		(1,917,292	)		—
Receivable from Arch Coal, Inc.		1,124,910			—		(2	)		27,194		—			1,152,102
Intercompanies		(1,903,278	)		977,096		910,676			15,506		—			—
Other		639			11,764		15,829			5,457					33,689

Total other assets		1,139,563			988,860		926,503			48,157		(1,917,292	)		1,185,791

Total assets	$	1,152,009		$	991,014	$	1,887,007		$	445,034	$	(1,917,292	)	$	2,557,772

Accounts payable		15,151			—		77,347			18,227		—			110,725
Accrued expenses		3,360			32,063		85,202			8,870		—			129,495
Total current liabilities		18,511			32,063		162,549			27,097		—			240,220
Long-term debt		—			958,881		—			—		—			958,881
Accrued postretirement benefits other than pension		18,981			—		2,485			9,570		—			31,036
Asset retirement obligations		—			—		163,832			11,070		—			174,902
Accrued workers’ compensation		5,262			—		1,236			3,529		—			10,027
Other noncurrent liabilities		5,254			—		27,757			5,694		—			38,705

Total liabilities		48,008			990,944		357,859			56,960		—			1,453,771

Redeemable membership interest		6,934			—		—			—		—			6,934
Minority interest		162,522			—		—			—		—			162,522
Non-redeemable membership interest		934,545			70		1,529,148			388,074		(1,917,292	)		934,545

Total liabilities and membership interests	$	1,152,009		$	991,014	$	1,887,007		$	445,034	$	(1,917,292	)	$	2,557,772

F-24

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
Year Ended December 31, 2007
(in thousands)


	Parent						Guarantor			Non-Guarantor
	Company			Issuer			Subsidiaries			Subsidiaries			Consolidated
Operating Activities
Cash provided by (used in) operating activities	$	(8,261	)	$	4,263		$	227,606		$	101,156		$	324,764
Investing Activities
Capital expenditures		—			—			(92,820	)		(54,603	)		(147,423	)
Increase in receivable from Arch Coal		(274,352	)		—			(2	)		(2,016	)		(276,370	)
Proceeds from dispositions of property, plant and equipment		6,000			—			455			86			6,541
Additions to prepaid royalties		—			—			—			(532	)		(532	)
Reimbursement of deposits on equipment		—			—			18,325			—			18,325

Cash used in investing activities		(268,352	)		—			(74,042	)		(57,065	)		(399,459	)
Financing Activities
Net proceeds from commercial paper		74,959			—			—			—			74,959
Debt financing costs		(202	)		—			—			—			(202	)
Transactions with affiliates, net		201,934			(4,263	)		(153,709	)		(43,962	)		—

Cash provided by (used in) financing activities		276,691			(4,263	)		(153,709	)		(43,962	)		74,757

Increase (decrease) in cash and cash equivalents		78			—			(145	)		129			62
Cash and cash equivalents, beginning of period		—			—			161			25			186

Cash and cash equivalents, end of period	$	78		$	—		$	16		$	154		$	248

F-25

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
Year Ended December 31, 2006
(in thousands)


	Parent						Guarantor			Non-Guarantor
	Company			Issuer			Subsidiaries			Subsidiaries			Consolidated
Operating Activities
Cash provided by operating activities	$	50,847		$	3,553		$	378,073		$	107,193		$	539,666
Investing Activities
Capital expenditures		—			—			(155,440	)		(104,928	)		(260,368	)
(Increase) decrease in receivable from Arch Coal		(251,943	)		—			2			(27,194	)		(279,135	)
Proceeds from dispositions of property, plant and equipment		—			—			91			204			295
Additions to prepaid royalties		—			—			—			(409	)		(409	)

Cash used in investing activities		(251,943	)		—			(155,347	)		(132,327	)		(539,617	)

Financing Activities
Debt financing costs		—			(15	)		—			—			(15	)
Transactions with affiliates, net		201,096			(3,538	)		(222,691	)		25,133			—

Cash provided by (used in) financing activities		201,096			(3,553	)		(222,691	)		25,133			(15	)

Increase (decrease) in cash and cash equivalents		—			—			35			(1	)		34
Cash and cash equivalents, beginning of period		—			—			126			26			152

Cash and cash equivalents, end of period	$	—		$	—		$	161		$	25		$	186

F-26

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
Year Ended December 31, 2005
(in thousands)


	Parent						Guarantor			Non-Guarantor
	Company			Issuer			Subsidiaries			Subsidiaries			Consolidated
Operating Activities
Cash provided by (used in) operating activities	$	(63,415	)	$	248		$	220,994		$	67,971		$	225,798
Investing Activities
Capital expenditures		—			—			(52,173	)		(56,427	)		(108,600	)
Increase in receivable from Arch Coal		(187,280	)		—			—			—			(187,280	)
Proceeds from dispositions of property, plant and equipment		—			—			81,117			638			81,755
Additions to prepaid royalties		—			—			(12,461	)		(346	)		(12,807	)

Cash provided by (used in) investing activities		(187,280	)		—			16,483			(56,135	)		(226,932	)

Financing Activities
Debt financing costs		(65	)					—			—			(65	)
Transactions with affiliates, net		250,760			(248	)		(238,536	)		(11,976	)		—

Cash provided by (used in) financing activities		250,695			(248	)		(238,536	)		(11,976	)		(65	)

Decrease in cash and cash equivalents		—			—			(1,059	)		(140	)		(1,199	)
Cash and cash equivalents, beginning of period		—			—			1,185			166			1,351

Cash and cash equivalents, end of period	$	—		$	—		$	126		$	26		$	152

F-27

ARCH WESTERN RESOURCES, LLC

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS


			Additions
	Balance at		Charged to Costs		Charged to				Balance at
	Beginning of Year		and Expenses		Other Accounts		Deductions(a)		End of Year
Year Ended Dec. 31, 2007
Reserves deducted from asset accounts
Other assets — other notes and accounts receivable	$	962	$	—	$	—	$	962	$	—
Current assets — repair parts and supplies inventories		12,076		663		—		242		12,497
Year Ended Dec. 31, 2006
Reserves deducted from asset accounts
Other assets — other notes and accounts receivable		962		—		—		—		962
Current assets — repair parts and supplies inventories		12,411		191		—		526		12,076
Year Ended Dec. 31, 2005
Reserves deducted from asset accounts
Other assets — other notes and accounts receivable		962		—		—		—		962
Current assets — repair parts and supplies inventories		12,441		377		—		407		12,411


(a)		Reserves utilized, unless otherwise indicated.

F-28

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

Paul A. Lang
President
March 28, 2008

KNOW ALL PERSONS BY THESE PRESENTS: That each of the undersigned member and officers 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, its or his true and lawful attorney-in-fact and agent, 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, 2007, 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 might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, or any of them, may lawfully do or cause to be done by virtue hereof.

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


Signatures	Capacity	Date
	Paul A. Lang	March 28, 2008
	President
	(Principal Executive Officer)


	Robert J. Messey	March 28, 2008
	Senior Vice President and Chief Financial
	Officer
	(Principal Financial Officer)

Arch Western Acquisition Corporation	Sole Managing Member	March 28, 2008

By:
Robert J. Messey, Vice President

Exhibit Index


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).

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).


Exhibit		Description

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 (WYW127221) 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 (incorporated by reference to Exhibit 10.12 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2005).

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 (incorporated by reference to Exhibit 10.13 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2005).

10.14		State Coal Lease executed October 1, 2004 by and between The State of Utah, Thru School & Institutional Trust Lands Admin, as lessor, and Ark Land Company and Arch Coal, Inc., as lessees, covering a tract of land located in Seiever County, Utah (incorporated by reference to Exhibit 10.20 to Arch Coal Inc.’s Annual Report on Form 10-K for the year ended December 31, 2006).

10.15		State Coal Lease executed September 1, 2000 by and between The State of Utah, Thru School & Institutional Trust Lands Admin, as lessor, and Canyon Fuel Company, LLC, as lessee, for lands located in Carbon County, Utah (incorporated by reference to Exhibit 10.21 to Arch Coal Inc.’s Annual Report on Form 10-K for the year ended December 31, 2006).

10.16		Federal Coal Lease executed September 1, 1996 by and between the Bureau of Land Management, as lessor, and Canyon Fuel Company, LLC, as lessee, covering a tract of land known as “The North Lease” in Carbon County, Utah (incorporated by reference to Exhibit 10.22 to Arch Coal Inc.’s Annual Report on Form 10-K for the year ended December 31, 2006).

10.17		Purchase and Sale Agreement, dated as of February 3, 2006, by and among various entities listed on Schedule I, as the originators, and Arch Coal, Inc. (incorporated by reference to Exhibit 10.17 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2006).

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.

32.2		Section 1350 Certification of Robert J. Messey.

exv21w1

Exhibit 21.1

Subsidiaries of the Company

The following is a complete list of the direct and indirect subsidiaries of Arch Western Resources, LLC, a Delaware limited liability company, including their respective states of incorporation or organization, as of March 15, 2008:


Arch Western Resources, LLC (Delaware)	99	%
Arch of Wyoming, LLC (Delaware)	100	%
Arch Western Finance LLC (Delaware)	100	%
Arch Western Bituminous Group LLC (Delaware)	100	%
Canyon Fuel Company, LLC (Delaware)	65	%*
Mountain Coal Company, LLC (Delaware)	100	%
Thunder Basin Coal Company, L.L.C. (Delaware)	100	%
Triton Coal Company, LLC (Delaware)	100	%


*		The remaining 35% interest in Canyon Fuel is owned by Arch Coal, Inc.

exv31w1

Exhibit 31.1

Certification

I, Paul A. Lang, certify that:

1. I have reviewed this annual report on Form 10-K of Arch Western Resources, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	(a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	(b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	(c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	(d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	(a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	(b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Paul A. Lang
President

Date: March 28, 2008

exv31w2

Exhibit 31.2

Certification

I, Robert J. Messey, certify that:

1. I have reviewed this annual report on Form 10-K of Arch Western Resources, LLC;

	(a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	(b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	(c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	(d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	(a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	(b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Robert J. Messey
Vice President

Date: March 28, 2008

exv32w1

Exhibit 32.1

Certification of Periodic Financial Reports

I, Paul A. Lang, President of Arch Western Resources, LLC, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Annual Report on Form 10-K for the year ended December 31, 2007 (the “Periodic Report”) which this statement accompanies fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of Arch Western Resources, LLC.

Paul A. Lang
President

Date: March 28, 2008

exv32w2

Exhibit 32.2

Certification of Periodic Financial Reports

I, Robert J. Messey, Vice President of Arch Western Resources, LLC, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Annual Report on Form 10-K for the year ended December 31, 2006 (the “Periodic Report”) which this statement accompanies fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of Arch Western Resources, LLC.

Robert J. Messey
Vice President

Date: March 28, 2008