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, 2011

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 of incorporation or organization)		(I.R.S. Employer 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 x

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

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 o No x

(Note: As a voluntary filer not subject to the filing requirements of Section 13 or 15(d) of the Exchange Act, the registrant has filed all reports pursuant to Section 13 or 15(d) of the Exchange Act during the preceding 12 months as if it were subject to such filing requirements.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.) Yes x 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 definition 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 x		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 x

At March 28, 2012, 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.

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TABLE OF CONTENTS

		Page

PART I		3

ITEM 1.	BUSINESS	3

ITEM 1A.	RISK FACTORS	22

ITEM 1B.	UNRESOLVED STAFF COMMENTS	29

ITEM 2.	PROPERTIES	29

ITEM 3.	LEGAL PROCEEDINGS	32

ITEM 4.	MINE SAFETY DISCLOSURES	32

PART II		33

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	33

ITEM 6.	SELECTED FINANCIAL DATA	33

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	33

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	41

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	41

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	41

ITEM 9A.	CONTROLS AND PROCEDURES	41

ITEM 9B.	OTHER INFORMATION	41

PART III		41

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	41

ITEM 11.	EXECUTIVE COMPENSATION	43

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	43

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	43

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	44

PART IV		44

ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	44

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If you are not familiar with any of the mining terms used in this report, we have provided explanations of many of them under the caption “Glossary of Selected Mining Terms” on page 21 of this report. Unless the context otherwise requires, all references in this report to “Arch Western,” “we,” “us,” or “our” are to Arch Western Resources, LLC and its subsidiaries.

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, such as our expected future business and financial performance, and are intended to come within the safe harbor protections provided by those sections. The words “anticipates,” “believes,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “predicts,” “projects,” “seeks,” “should,” “will” or other comparable words and phrases identify forward-looking statements, which speak only as of the date of this report. Forward-looking statements by their nature address matters that are, to different degrees, uncertain. Actual results may vary significantly from those anticipated due to many factors, including:

· market demand for coal and electricity;

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

· competition within our industry and with producers of competing energy sources;

· excess production and production capacity;

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

· inaccuracies in our estimates of our coal reserves;

· availability and price of mining and other industrial supplies;

· availability of skilled employees and other workforce factors;

· our ability to collect payments from our customers;

· 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;

· the deferral of contracted shipments of coal by 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;

· our ability to obtain and renew various permits, including permits authorizing the disposition of certain mining waste;

· existing and future legislation and regulations affecting both our coal mining operations and our customers’ coal usage, governmental policies and taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases;

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

· the existence of hazardous substances or other environmental contamination on property owned or used by us; and

· the other factors affecting our business described below under the caption “Risk Factors.”

All forward-looking statements in this report, as well as all other written and oral forward-looking statements attributable to us or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements contained in this section and elsewhere in this report. See Items 1A “Risk Factors,” 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and 7A “Quantitative and Qualitative Disclosures About Market Risk” for additional information about factors that may affect our businesses and operating results. These factors are not necessarily all of the important factors that could affect us. These risks and uncertainties, as well as other risks of which we are not aware or which we currently do not believe to be material, may cause our actual future results to be materially different than those expressed in our forward-looking statements. We

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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.

PART I

ITEM 1. BUSINESS.

Introduction

We are a subsidiary of Arch Coal, Inc., one of the world’s largest coal producers. For the year ended December 31, 2011, we sold approximately 131.9 million tons of coal, representing roughly 12% of the U.S. coal supply. We sell substantially all of our coal to power plants and industrial facilities. At December 31, 2011, we operated seven active mines located in two of the three major low-sulfur coal-producing regions of the United States.

Significant federal and state environmental regulations affect the demand for coal. Existing environmental regulations limiting the emission of certain impurities caused by coal combustion and new regulations have had and are likely to continue to have a considerable impact on our business. For example, certain federal and state environmental regulations currently limit the amount of sulfur dioxide that may be emitted as a result of combustion. As a result, we focus on mining, processing and marketing coal with low sulfur content.

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 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 October 1, 2009, Arch Coal acquired the Jacobs Ranch mining operations for a purchase price of $768.8 million including transaction costs and working capital adjustments. The acquisition included approximately 345 million tons of coal reserves located adjacent to our Black Thunder mining complex. Arch Coal contributed the acquired assets and liabilities (excluding coal reserves) to us, which we immediately merged with our Black Thunder mining operations. We lease the Jacobs Ranch coal reserves from a subsidiary of Arch Coal.

Coal Characteristics

In general, end users characterize coal as steam coal or metallurgical coal. Heat value, sulfur, ash, moisture content, and volatility in the case of metallurgical coal, are important variables in the marketing and transportation of coal. These characteristics help producers determine the best end use of a particular type of coal. The following is a description of these general coal characteristics:

Heat Value. In general, the carbon content of coal supplies most of its heating value, but other factors also influence the amount of energy it contains per unit of weight. The heat value of coal is commonly measured in Btus. Coal is generally classified into four categories, ranging from lignite, subbituminous, bituminous and anthracite, reflecting the progressive response of individual deposits of coal to increasing heat and pressure. Anthracite is coal with the highest carbon content and, therefore, the highest heat value, nearing 15,000 Btus per pound. Bituminous coal, used primarily to generate electricity and to make coke for the steel industry, has a heat value ranging between 10,500 and 15,500 Btus per pound. Subbituminous coal ranges from 8,300 to 13,000 Btus per pound and is generally used for electric power generation. Lignite coal is a geologically young coal which has the lowest carbon content and a heat value ranging between 4,000 and 8,300 Btus per pound.

Sulfur Content. Federal and state environmental regulations, including regulations that limit the amount of sulfur dioxide that may be emitted as a result of combustion, have affected and may continue to affect the demand for certain types of coal. The sulfur content of coal can vary from seam to seam and within a single seam. The chemical composition and concentration of sulfur in coal affects the amount of sulfur dioxide produced in combustion. Coal-fueled power plants can comply with sulfur dioxide

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emission regulations by burning coal with low sulfur content, blending coals with various sulfur contents, purchasing emission allowances on the open market and/or using sulfur-dioxide emission reduction technology.

All of our identified coal reserves have been subject to preliminary coal seam analysis to test sulfur content. Of these reserves, approximately 93.6% consist of compliance coal, while an additional 3.2% could be sold as low-sulfur coal. The balance is classified as high-sulfur coal. Higher sulfur coal can be burned in plants equipped with sulfur-dioxide emission reduction technology, such as scrubbers, and in facilities that blend compliance and noncompliance coal.

Ash. Ash is the inorganic residue remaining after the combustion of coal. As with sulfur, ash content varies from seam to seam. Ash content is an important characteristic of coal because it impacts boiler performance and electric generating plants must handle and dispose of ash following combustion. The composition of the ash, including the proportion of sodium oxide and fusion temperature, are important characteristics of coal and help determine the suitability of the coal to end users. The absence of ash is also important to the process by which metallurgical coal is transformed into coke for use in steel production.

Moisture. Moisture content of coal varies by the type of coal, the region where it is mined and the location of the coal within a seam. In general, high moisture content decreases the heat value and increases the weight of the coal, thereby making it more expensive to transport. Moisture content in coal, on an as-sold basis, can range from approximately 2% to over 30% of the coal’s weight.

The Coal Industry

Global Coal Supply and Demand. Recovery from the 2008 upheaval in the global financial markets remained uneven in 2011 with future prospects uncertain because of ongoing sovereign debt problems, mostly centered in the European Union. Economic growth rates were also uneven with emerging economies continuing to show relative strength, while advanced economies generally experienced only modest growth. International coal demand continued to show strength through the year; however, there were some signs of weakness toward the end of the year. The United States exported an estimated 107 million tons in 2011, based on Energy Information Administration data, the highest level since 1991.

Coal is traded globally and can be transported to demand centers by ship, rail, barge, and truck. Total hard coal production in 2010 increased 6.8% over 2009 to 6.2 billion tonnes, while global production of brown coal was relatively flat at 1.04 billion tonnes in 2010, according to the International Energy Agency (IEA). China remains the largest producer of coal in the world, producing over 3.16 billion tonnes in 2010, according to the IEA. The United States and India follow China with hard coal production of approximately 932 million tonnes and 538 million tonnes, respectively, in 2010. Despite being the largest producer of hard coal globally, China surpassed Japan in 2011 as the largest importer of coal with imports of more than 180 million tonnes. Japan imported 175 million tonnes, followed by South Korea with 125 tonnes. Total global cross-border hard coal trade rose in 2011 to over 1.2 billion tons.

Global coal demand grew by more than 11% in 2010. Power generation remains the main driver of global coal demand as projected in all of the IEA’s World Energy Outlook scenarios. China and India account for over 67% of the projected demand increase in the IEA’s New and Current Policies scenarios.

Among the nations principally supplying coal to the global power markets are Australia, historically the world’s largest coal exporter with exports of approximately 300 million tonnes in 2010, as well as Indonesia, Russia, United States, Colombia, and South Africa. Indonesia, in particular, has seen substantial growth in its coal exports in the last few years; however, its growing domestic energy demand may result in a decrease in exports as it moves toward greater self-sufficiency. Total United States exports continued to grow in 2011 as discussed below, up approximately 30% over 2010 as global economic conditions improved and pressure remained on global coal supply networks. We expect continued improvements in the demand for U.S. coal exports as economic growth continues, especially in the Asia-Pacific region, and as traditional supply movements adjust to meet the Asia-Pacific region’s demands.

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 or processing facilities. Coal consumption in the United States increased from 398.1 million tons in 1960 to approximately 1.0 billion tons in 2011, according to the Energy Information Administration’s (EIA) Short Term Energy Outlook. Although full-year data for 2011 is not yet available, coal consumption has improved over what was lost during the global downturn that affected U.S. coal consumption in 2009. In 2010, coal consumption in the United States improved through stronger electricity demand driven by both a recovering economy and favorable weather.

The following chart shows historical and projected demand trends for U.S. coal by consuming sector for the periods indicated, according to the EIA:

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	Actual	Estimated	Forecast			Annual Growth
Sector	2006	2011	2012	2020	2035	2009-2035
	(Tons, in millions)
Electric power	1,027	945	925	989	1,119	0.7	%
Other industrial	59	49	48	49	47	0.1	%
Coke plants	23	24	24	22	18	0.6	%
Residential/commercial	3	3	4	3	3	-0.2	%
Coal-to-liquids	—	—	—	13	128	n/a
Total U.S. coal consumption	1,112	1,020	1,002	1,076	1,315	1.1	%

Source:

EIA Annual Energy Outlook 2011

EIA Short Term Energy Outlook (January 2012)

EIA Monthly Energy Review (December 2011)

According to the EIA, coal accounted for approximately 42% of U.S. electricity generation from January through November 2011, and based on a projected 25% growth in electricity demand, coal consumption by the electric industry is expected to grow about 18% by 2035, reaching 1.1 billion tons. These amounts assume no future federal or state carbon emissions legislation is enacted and do not take into account subsequent market conditions. Historically, coal has been considerably less expensive than natural gas or oil.

The following chart shows the breakdown of U.S. electricity generation by energy source for January through November 2011, according to the EIA:

Source: EIA Electric Power Monthly (January 2012).

The average spot price for West Texas Intermediate oil in the United States averaged $94.86/barrel in 2011, and, according to the EIA, will increase to $100.25/barrel in 2012. Historically, volatile oil prices and global energy security concerns have increased interest in converting coal into liquid fuel, a process known as liquefaction. Liquid fuel produced from coal can be further refined to produce transportation fuels, such as low-sulfur diesel fuel, gasoline and other oil products, such as plastics and solvents. Currently, there are only a limited number of projects moving forward at this time.

U.S. Coal Production. The United States is the second largest coal producer in the world, exceeded only by China. According to the EIA, there is over 200 billion tons of recoverable coal in the United States. The U.S. Department of Energy estimates that current domestic recoverable coal reserves could supply enough electricity to satisfy domestic demand for approximately 200 years. Annual coal production in the United States has increased from 434 million tons in 1960 to approximately 1.1 billion tons in 2011.

Coal is mined from coal fields throughout the United States, with the major production centers located in the western United States, the Appalachian region and the Illinois Basin.

Major regions in the West include the Powder River Basin and the Western Bituminous region. According to the EIA, coal produced in the western United States increased from 408 million tons in 1994 to an estimated 638 million tons in 2011, as competitive mining costs and regulations limiting sulfur- dioxide emissions have continued to increase demand for low-sulfur coal over this period. The Powder River Basin is located in northeastern Wyoming and southeastern Montana. Coal from this region is sub-bituminous coal with low sulfur content ranging from 0.2% to 0.9% and heating values ranging from 8,000 to 9,500 Btu. The

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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 and 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 Colorado, Utah and southern Wyoming. Coal from this region typically has low sulfur content ranging from 0.4% to 0.8% and heating values ranging from 10,000 to 12,200 Btu.

U.S. Coal Exports and Imports. U.S exports increased substantially in 2011 compared to 2010, supported by recovering global economies and continued growth in Chinese and Indian steel markets in particular. According to the EIA, exports of U.S. coal grew from 81 million tons in 2010 to 107 million tons in 2011. This is a trend we expect to continue as demand for U.S. coal grows in the seaborne market. Interest in access to the coal markets overseas has fueled considerable growth in developing new port capacity in the United States.

Historically, coal imported from abroad has represented a relatively small share of total U.S. coal consumption, and this remained the case in 2011. Imports did reach close to 36 million tons in 2007, but have fallen since then. According to the EIA, coal imports declined from 19 million tons in 2010 to 14 million in 2011. The decline is mostly attributed to more competitive pricing for domestic coal and stronger demand from non-U.S. markets for seaborne coal. 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 imports into the United States to continue to decrease in the near-term as more and more global coal will likely be directed to Asia.

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 below under “Our Mining Operations — General.” In 2011, approximately 87% of the coal that we produced came from surface mining operations.

Surface mining involves removing the topsoil then drilling and blasting the overburden (earth and rock covering the coal) with explosives. We then remove the overburden 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 plant life into the natural habitat and make other improvements that have local community and environmental benefits.

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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 “Our Mining Operations — General.” In 2011, approximately 13% 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 shearer to extract coal from long rectangular blocks of medium to thick 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.

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

Coal Preparation and Blending. We crush the coal mined from our Powder River Basin mining complexes and ship it directly from our mines to the customer. Typically, no additional preparation is required for a saleable product. Coal extracted from some of our underground mining operations contains impurities, such as rock, shale and clay, and occurs in a wide range of particle sizes. A few of our mines in the Western Bituminous region use a coal preparation plant located near the mine or connected to the mine by a conveyor. These coal preparation plants allow us to treat the coal we extract from those mines to ensure a consistent quality and to enhance its suitability for particular end-users.

The treatments we employ at our preparation plants depend on the size of the raw coal. For course material, the separation process relies on the difference in the density between coal and waste rock where, for the very fine fractions, the separation process relies on the difference in surface chemical properties between coal and the waste minerals. 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 a pre-determined specific gravity. Since coal is lighter than its impurities, it floats, and we can separate it from rock and shale. We treat intermediate sized particles with dense medium cyclones, in which a liquid is spun at high speeds to separate coal from rock. Fine coal is treated in spirals, in which the differences in density between coal and rock allow them, when suspended in water, to be separated. Ultra fine coal is recovered in column flotation cells utilizing the differences in surface chemistry between coal and rock. By injecting stable air bubbles through a suspension of ultra fine coal and rock, the coal particles adhere to the bubbles and rise to the surface of the column where they are removed. To minimize the moisture content in coal, we process most coal sizes through centrifuges. A centrifuge spins coal very quickly, causing water accompanying the coal to separate.

For more information about the preparation plants used at our mining operations, you should see the section entitled “Our Mining Operations” below.

OUR MINING OPERATIONS

General

At December 31, 2011, we operated seven 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. We incorporate by reference the information about the operating results of each of our segments for the years ended December 31, 2011, 2010 and 2009 contained in Note 15 — Segment Information to our consolidated financial statements beginning on page F-17.

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Our operations in the Powder River Basin are located in Wyoming and include two surface mining complexes (Black Thunder and Coal Creek). Our operations in the Western Bituminous region are located in southern Wyoming, Colorado and Utah and include four underground mining complexes (Dugout Canyon, Skyline, Sufco and West Elk) and one surface mining complex (Arch of Wyoming).

In general, we have developed our mining complexes and preparation plants at strategic locations in close proximity to rail facilities. Coal is transported from our mining complexes to customers by means of railroads, trucks, barge lines, and ocean-going vessels from terminal facilities. We currently own or lease under long-term arrangements a substantial portion of the equipment utilized in our mining operations. We employ sophisticated preventative maintenance and rebuild programs and upgrade our equipment to ensure that it is productive, well-maintained and cost-competitive. Our maintenance programs also employ procedures designed to enhance the efficiencies of our operations.

The following map shows the locations of our mining operations:

The following table provides a summary of information regarding our active mining complexes at December 31, 2011, the total sales associated with these complexes for the years ended December 31, 2009, 2010 and 2011 and the total reserves associated with these complexes at December 31, 2011. 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. The information included below in the following table describes in more detail our mining operations, the coal mining methods used, certain characteristics of our coal and the method by which we transport coal from our mining operations to our customers or other third parties.

							Total Cost
							of Property,
							Plant and
							Equipment
		Mining			Tons Sold		at December 31,		Assigned
Mining Complex	Mines	Equipment	Railroad	2009	2010	2011	2011		Reserves
					(Million tons)		($ in millions)		(Million tons)
Powder River Basin:
Black Thunder	S	D, S	UP/BN	81.2	116.2	104.9	$	1,147.4	1,298.0
Coal Creek	S	D, S	UP/BN	9.8	11.4	10.0	155.5		176.2
Western Bituminous:
Arch of Wyoming	S	L	UP	0.1	0.1	0.1	22.7		—
Dugout Canyon	U	LW, CM	UP	3.2	2.3	2.2	140.5		15.0
Skyline	U	LW, CM	UP	2.8	2.9	2.9	189.3		15.2
Sufco	U	LW, CM	UP	6.6	6.1	6.1	232.1		48.6
West Elk	U	LW, CM	UP	4.0	4.8	5.7	480.0		88.3
Totals				107.7	143.8	131.9	$	2,367.5	1,641.3

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

Powder River Basin

Black Thunder. Black Thunder is a surface mining complex located on approximately 34,500 acres in Campbell County, Wyoming. The Black Thunder complex extracts steam coal from the Upper Wyodak and Main Wyodak seams.

We control a significant portion of the coal reserves through federal and state leases. The Black Thunder mining complex had approximately 1.3 billion tons of proven and probable reserves at December 31, 2011. The air quality permit for the Black Thunder mine allows for the mining of coal at a rate of 190 million tons per year. Without the addition of more coal reserves, the current reserves could sustain current production levels until 2021 before annual output starts to significantly decline, although in practice production would drop in phases extending the ultimate mine life. Several large tracts of coal adjacent to the Black Thunder mining complex have been nominated for lease, and other potential large areas of unleased coal remain available for nomination by us or other mining operations. The U.S. Department of Interior Bureau of Land Management, which we refer to as the BLM, will determine if the tracts will be leased and, if so, the final boundaries of, and the coal tonnage for, these tracts.

The Black Thunder mining complex currently consists of seven active pit areas and three loadout facilities. 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 two hours.

Coal Creek. Coal Creek is a surface mining complex located on approximately 7,400 acres in Campbell County, Wyoming. The Coal Creek mining complex extracts steam coal from the Wyodak-R1 and Wyodak-R3 seams.

We control a significant portion of the coal reserves through federal and state leases. The Coal Creek mining complex had approximately 176.2 million tons of proven and probable reserves at December 31, 2011. The air quality permit for the Coal Creek mine allows for the mining of coal at a rate of 50 million tons per year. Without the addition of more coal reserves, the current reserves could sustain current production levels until 2025 before annual output starts to significantly decline. One tract of coal adjacent to the Coal Creek mining complex has been nominated for lease, and other potential areas of unleased coal remain available for nomination by us or other mining operations. The BLM will determine if these tracts will be leased and, if so, the final boundaries of, and the coal tonnage for, these tracts.

The Coal Creek 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

Arch of Wyoming. Arch of Wyoming is a surface mining complex located in Carbon County, Wyoming. The complex currently consists of one active surface mine and four inactive mines located on approximately 55,100 acres that are in the final process of reclamation and bond release. The Arch of Wyoming mining complex extracts coal from the Johnson seam.

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We control a significant portion of the coal reserves associated with this complex through federal, state and private leases. We currently do not have any tons assigned to the Arch of Wyoming mining operations. The air quality permit for the active Arch of Wyoming mining operation allows for the mining of coal at a rate of 2.5 million tons per year.

Dugout Canyon. Dugout Canyon mine is an underground mining complex located on approximately 18,600 acres in Carbon County, Utah. The Dugout Canyon mining complex has extracted steam coal from the Rock Canyon and Gilson seams.

We control a significant portion of the coal reserves through federal and state leases. The Dugout Canyon mining complex had approximately 15.0 million tons of proven and probable reserves at December 31, 2011. The coal seam currently being mined could sustain current production levels until approximately 2014, at which point we will need to transition to another coal seam to continue mining. We currently plan on idling longwall operations at the end of the current panel during the first quarter of 2012.

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 13,200 acres in Carbon and Emery Counties, Utah. The Skyline mining complex extracts steam coal from the Lower O’Conner A seam.

We control a significant portion of the coal reserves through federal leases and smaller portions through county and private leases. The Skyline mining complex had approximately 15.2 million tons of proven and probable reserves at December 31, 2011. The reserve area currently being mined could sustain current production levels through mid-2012, at which point we plan to transition to a new reserve area in order to continue mining.

The Skyline complex currently consists of a longwall, two continuous miner section and a loadout facility. We ship most of the coal raw to our customers via the Union Pacific railroad or by highway trucks. We process a portion of the coal mined at this complex at a nearby preparation plant. 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 25,700 acres in Sevier County, Utah. The Sufco mining complex extracts steam coal from the Upper Hiawatha seam.

We control a significant portion of the coal reserves through federal and state leases. The Sufco mining complex had approximately 48.6 million tons of proven and probable reserves at December 31, 2011. The coal seam currently being mined could sustain current production levels through 2020, at which point a new coal seam will have to be accessed in order to continue mining.

The Sufco 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. Processing at the mine site consists of crushing and sizing. The rail loadout facility is capable of loading an 11,000-ton train in less than three hours.

West Elk. West Elk is an underground mining complex located on approximately 17,800 acres in Gunnison County, Colorado. The West Elk mining complex extracts steam coal from the E seam.

We control a significant portion of the coal reserves through federal and state leases. The West Elk mining complex had approximately 88.3 million tons of proven and probable reserves at December 31, 2011. Without the addition of more coal reserves, the current reserves could sustain current production levels through 2021 before annual output starts to significantly decline.

The West Elk complex currently consists of a longwall, two continuous miner sections and a loadout facility. We ship most of the coal raw to our customers via the Union Pacific railroad. In 2010, we finished constructing a new coal preparation plant with supporting coal handling facilities at the West Elk mine site. The loadout facility can load an 11,000-ton train in less than three hours.

Sales and Marketing

Overview. Coal prices are influenced by a number of factors and vary materially 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

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other. The price of coal within a region is influenced by market conditions, coal quality, transportation costs involved in moving coal from the mine to the point of use and mine operating costs. For example, higher carbon and lower ash content generally result in higher prices, and higher sulfur and higher ash content generally result in lower prices within a given geographic region.

The cost of coal at the mine is also 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 primary 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 and at one Western Bituminous mine. 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.

We rely on Arch Coal’s sales and marketing force, which is principally based in St. Louis, Missouri and consists of sales personnel, transportation and distribution personnel, quality control personnel and contract administration personnel, and we pay Arch Coal for the use of their sales and marketing force under a marketing services agreement.

Customers. In 2011, we sold coal to domestic customers located in 31 different states. For the year ended December 31, 2011, we derived approximately 20% of our total coal revenues from sales to our three largest customers — Tennessee Valley Authority, Pacificorp and Ameren Corporation — and approximately 47% of our total coal revenues from sales to our 10 largest customers.

Long-Term Coal Supply Arrangements

As is customary in the coal industry, we enter into fixed price, fixed volume long-term supply contracts, the terms of which are more than one year, with many of our customers. Multiple year contracts usually have specific and possibly different volume and pricing arrangements for each year of the contract. Long-term contracts allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. In 2011, we sold approximately 77% of our coal under long-term supply arrangements. The majority of our supply contracts include a fixed price for the term of the agreement or a pre-determined escalation in price for each year. Some of our long-term supply agreements may include a variable pricing system. While most of our sales contracts are for terms of one to five years, some are as short as one month and other contracts have terms up to 7 years. At December 31, 2011, the average volume-weighted remaining term of our long-term contracts was approximately 2.5 years, with remaining terms ranging from one to six years. At December 31, 2011, remaining tons under long-term supply agreements, including those subject to price re-opener or extension provisions, were approximately 230 million tons.

We typically sell coal to customers under long-term arrangements through a “request-for-proposal” process. The terms of our coal sales agreements result from competitive bidding and negotiations with customers. Consequently, the terms of these contracts vary by customer, including base price adjustment features, price re-opener terms, coal quality requirements, quantity parameters, permitted sources of supply, future regulatory changes, extension options, force majeure, termination, damages and assignment provisions. Our long-term supply contracts typically contain provisions to adjust the base price due to new statutes, ordinances or regulations, such as the Mine Improvement and New Emergency Response Act of 2006, which we refer to as the MINER Act, that affect our costs related to performance of the agreement. Additionally, some of our contracts contain provisions that allow for the recovery of costs affected by modifications or changes in the interpretations or application of any applicable statute by local, state or federal government authorities. These provisions only apply to the base price of coal contained in these supply contracts. In some circumstances, a significant adjustment in base price can lead to termination of the contract.

Certain of our contracts contain index provisions that change the price based on changes in market based indices and or changes in economic indices. Certain of our contracts contain price re-opener provisions that may allow a party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on prevailing market price or, in some instances, require us to negotiate a new price, sometimes within a specified range of prices. In a limited number of agreements, if the parties do not agree on a new price, either party has an option to terminate the contract. Under some of our contracts, we have the right to match lower prices offered to our customers by other suppliers. In addition, certain of our contracts contain clauses that may allow customers to terminate the contract in the event of certain changes in environmental laws and regulations that impact their operations.

Coal quality and volumes are stipulated in coal sales agreements. In most cases, the annual pricing and volume obligations are fixed, although in some cases the volume specified may vary depending on the customer consumption requirements. Most of our coal sales agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash and moisture content as well as others. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts.

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Our coal sales agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers, during the duration of events beyond the control of the affected party, including events such as strikes, adverse mining conditions, mine closures or serious transportation problems that affect us or unanticipated plant outages that may affect the buyer. Our contracts also generally provide that in the event a force majeure circumstance exceeds a certain time period, the unaffected party may have the option to terminate the purchase or sale in whole or in part. Some contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer. Agreements between our customers and the railroads servicing our mines may also contain force majeure provisions. Generally, our coal sales agreements allow our customer to suspend performance in the event that the railroad fails to provide its services due to circumstances that would constitute a force majeure.

In most of our contracts, we have a right of substitution (unilateral or subject to counterparty approval), allowing us to provide coal from different mines, including third-party mines, as long as the replacement coal meets quality specifications and will be sold at the same equivalent delivered cost.

In some of our coal supply contracts, we agree to indemnify or reimburse our customers for damage to their or their rail carrier’s equipment while on our property, which result from our or our agents’ negligence, and for damage to our customer’s equipment due to non-coal materials being included with our coal while on our property.

Transportation. We ship our coal to domestic customers by means of railroad, barges or trucks, or a combination of these means of transportation. We generally sell coal used for domestic consumption free on board at the mine or nearest loading facility. Our domestic customers normally bear the costs of transporting coal by rail or barge.

We generally sell coal to international customers at the export terminal, and we are usually responsible for the cost of transporting coal to the export terminals. We transport our coal to Pacific coast terminals or terminals along the Gulf of Mexico for transportation to international customers. Our international customers are generally responsible for paying the cost of ocean freight.

Historically, most domestic electricity generators have arranged long-term shipping contracts with rail or barge companies to assure stable delivery costs. Transportation can be a large component of a purchaser’s total cost. Although the purchaser pays the freight, transportation costs still are important to coal mining companies because the purchaser may choose a supplier largely based on cost of transportation. Transportation costs borne by the customer vary greatly based on each customer’s proximity to the mine and our proximity to the loadout facilities. Trucks and overland conveyors haul coal over shorter distances, while barges, Great Lake carriers and ocean vessels move coal to export markets and domestic markets requiring shipment over the Great Lakes and several river systems.

Most coal mines are served by a single rail company, but much of the Powder River Basin is served by two rail carriers: the Burlington Northern-Santa Fe railroad and the Union Pacific railroad. In the Western Bituminous region our customers are largely served by the Union Pacific railroad or by truck delivery.

Competition

The coal industry is intensely competitive. The most important factors on which we compete are coal quality, delivered costs to the customer and reliability of supply. Our principal domestic competitors include Alpha Natural Resources, Inc., Cloud Peak Energy, CONSOL Energy Inc. and Peabody Energy Corp. 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 natural gas, nuclear energy, hydropower, wind, solar 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.

Suppliers

Principal supplies used in our business include petroleum-based fuels, explosives, tires, steel and other raw materials as well as spare parts and other consumables used in the mining process. We use third-party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services and construction. We use sole source suppliers for certain parts of our business such as explosives and fuel, and preferred suppliers for other parts at our business such as dragline and shovel parts and related services. We believe adequate substitute suppliers are available. For more information about our suppliers, you should see “Risk Factors — Increases in the costs of mining and other industrial supplies, including steel-based supplies, diesel fuel and rubber tires,

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or the inability to obtain a sufficient quantity of those supplies, could negatively affect our operating costs or disrupt or delay our production.”

Environmental and Other Regulatory Matters

Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety and the environment, including protection of air quality, water quality, wetlands, special status species of plants and animals, land uses, cultural and historic properties and other environmental resources identified during the permitting process. Reclamation is required during production and after mining has been completed. Materials used and generated by mining operations must also be managed according to applicable regulations and law. These laws have, and will continue to have, a significant effect on our production costs and our competitive position.

We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, due in part to the extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time. We cannot assure you that we have been or will be at all times in complete compliance with such laws and regulations. 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.

Future laws, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, may require substantial increases in equipment and operating costs and delays, interruptions or a termination of operations, the extent to which we cannot predict. Future laws, regulations or orders may also cause coal to become a less attractive fuel source, thereby reducing coal’s share of the market for fuels and other energy sources used to generate electricity. As a result, future laws, regulations or orders may adversely affect our mining operations, cost structure or our customers’ demand for coal.

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

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 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. For example, in order to obtain a federal coal lease, an environmental impact statement must be prepared to assist the BLM in determining the potential environmental impact of lease issuance, including any collateral effects from the mining, transportation and burning of coal. The authorization, permitting and implementation requirements imposed by federal, state and local authorities may be costly and time consuming and may delay commencement or continuation of mining operations. In the states where we operate, the applicable laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if officers, directors, shareholders with specified interests or certain other affiliated entities with specified interests in the applicant or permittee have, or are affiliated with another entity that has, outstanding permit violations. Thus, past or ongoing violations of applicable laws and regulations 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 federal and 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 or other authorized use. 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, even after a permit has been issued.

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.

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 regulatory primacy. A state agency may achieve primacy if the state regulatory agency develops a mining regulatory program that is no less

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stringent than the federal mining regulatory program under SMCRA. All states in which we conduct mining operations have achieved primacy and issue permits in lieu of OSM.

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. We begin the process of preparing a mining permit application 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 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 OSM’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 2011, we recorded $38.1 million of expense related to these reclamation fees.

Surety Bonds. Mine operators are often required by federal and/or state laws, including SMCRA, 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, 2011, we have self-bonded an aggregate of approximately $418 million and have posted an aggregate of approximately $34 million in surety bonds for reclamation purposes. In addition, we had approximately $34.5 million of surety bonds outstanding at December 31, 2011 to secure workers’ compensation, coal lease and other obligations.

Mine Safety and Health. 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 aimed at improving mine safety and health. Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive and pervasive systems for the protection of employee health and safety affecting any segment of U.S. industry. In reaction to recent mine accidents, 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 MINER Act. The MINER Act imposes additional obligations on coal operators including, among other things, the following:

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· 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.

In 2008, the U.S. House of Representatives approved additional federal legislation which would have required new regulations on a variety of mine safety issues such as underground refuges, mine ventilation and communication systems. Although the U.S. Senate failed to pass that legislation, it is possible that similar legislation may be proposed in the future. Various states, including West Virginia, have also enacted new laws to address many of the same subjects. The costs of implementing these new safety and health regulations at the federal and state level have been, and will continue to be, substantial. In addition to the cost of implementation, there are increased penalties for violations which may also be substantial. Expanded enforcement has resulted 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 2011, we recorded $73.9 million of expense related to this excise tax.

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 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 is likely, such as the Cross State Air Pollution Rule (CSAPR) and Mercury and Air Toxics Standard (MATS), finalized in 2011 and discussed in more detail below. Regulation of additional emissions, such as greenhouse gases, has been announced for early 2012 by the U.S. Environmental Protection Agency, which we refer to as EPA, and those regulations will apply to new coal-fueled power plants. Other greenhouse gas regulations may apply to industrial boilers (see discussion of Climate Change, below). This application 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, promulgated in 1990, imposed 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 been factored into the pricing of the coal market.

· Particulate Matter. The Clean Air Act requires 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 12 years from the date of designation to secure emissions reductions from sources contributing to the problem. In addition, EPA announced, in February of 2011, that it intends to propose a revision to the PM2.5 NAAQS; although, the revision has not yet been proposed. 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 new NAAQS for ozone. Nitrogen oxides, which are a byproduct of coal combustion, are classified as an ozone precursor. As a

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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, on March 27, 2008, EPA promulgated a new 75 parts per billion (ppb) ozone primary NAAQS. On September 16, 2009, EPA announced that it will reconsider the new standard, and on January 19, 2010, EPA proposed its reconsidered NAAQS (75 Fed Reg 2938), proposing to adopt a new, more stringent primary ambient air quality standard for ozone and to change the way in which the secondary standard is calculated. However, following an announcement by the President that the new ozone standard would undergo additional review, EPA Administrator Jackson announced on September 2, 2011, that the next ozone NAAQS review will occur in 2013. If a new ozone NAAQS is promulgated, 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 was 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, which could make 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 28 Eastern states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrous oxide pursuant to 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. 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. In July 2008, in State of North Carolina v. EPA and consolidated cases, the U.S. Court of Appeals for the District of Columbia Circuit disagreed with the EPA’s reading of the Clean Air Act and vacated CAIR in its entirety. In December 2008, the U.S. Court of Appeals for the District of Columbia Circuit revised its remedy and remanded the rule to the EPA. EPA proposed a revised transport rule on August 2, 2010, (75 Fed Reg 45209) and received thousands of comments on the proposal. The rule was finalized as the Cross State Air Pollution Rule (CSAPR) on July 6, 2011, with compliance required for SO2 reductions beginning January 1, 2012 and compliance with NOx reductions required by May 1, 2012. Numerous appeals of the rule were filed and, on December 30, 2011, the Federal Court of Appeals for the District of Columbia Circuit stayed the rule. The appeal is scheduled to be heard in April of 2012. If the CSAPR is upheld, the additional controls required under the CSAPR may affect the market for coal inasmuch as multiple existing coal fired units are expected to be retired rather than having required controls installed.

· Mercury. In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the EPA’s Clean Air Mercury Rule (CAMR) and remanded it to the EPA for reconsideration. In response to the vacatur, EPA announced an EGU Mercury and Air Toxics Standard (MATS) on December 16, 2011. The MATS is expected to be finalized in March or April of 2012. In addition, before the court decision vacating the CAMR, some states had either adopted the CAMR or adopted state-specific rules to regulate mercury emissions from power plants that are more stringent than the CAMR. The result of the EGU MATS and state mercury and air toxics controls is that these rules may adversely affect the demand for coal.

· 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. Under the Regional Haze Rule, affected states were required to submit regional haze SIP’s by December 17, 2007, that, among other things, was to identify facilities that would have to reduce emissions and comply with stricter emission limitations. The vast majority of states failed to submit their plans by December 17, 2007, and EPA issued a Finding of Failure to Submit plans on January 15, 2009 (74 Fed. Reg. 2392), which could trigger Federal implementation plans. EPA has taken no enforcement action against states to finalize implementation plans and is slowly dealing with the state Regional Haze SIPs that were submitted. Nonetheless, this program may result in additional emissions restrictions from new coal-fueled power plants whose operations 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.

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

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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 acceptance, the Kyoto Protocol became binding on all those countries that had ratified it in February 2005. The United States has refused to ratify the Kyoto Protocol. Although the Kyoto targets varied from country to country, the United States Kyoto Protocol target reductions of greenhouse gas emissions would be to 93% of 1990 levels. Following the Kyoto meeting, multiple Conferences of the Parties have been held. None to date, including the most recent Conference of the Parties in Cancun, Mexico, in late November and early December of 2010, have resulted in any mandatory reduction requirements for the United States, but any such future conference may do so.

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. The U.S. Congress has considered various proposals to reduce greenhouse gas emissions, but to date, none have become law. 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. On December 15, 2009, EPA published a formal determination that six greenhouse gases, including carbon dioxide and methane, endanger both the public health and welfare of current and future generations. In the same Federal Register rulemaking, EPA found that emission of greenhouse gases from new motor vehicles and their engines contribute to greenhouse gas pollution. Although Massachusetts v. EPA did not involve the EPA’s authority to regulate greenhouse gas emissions from stationary sources, such as coal-fueled power plants, the decision is likely to impact regulation of stationary sources.

For example, a challenge in the U.S. Court of Appeals for the District of Columbia with respect to the EPA’s decision not to regulate greenhouse gas emissions from power plants and other stationary sources under the Clean Air Act’s new source performance standards was remanded to the EPA for further consideration in light of Massachusetts v. EPA. Other pending cases regarding greenhouse gases may affect the market for coal. In AEP v. Connecticut (582 F. 3d, 309, 2d Cir, 2009) the Second Circuit Court of Appeals held that States and private plaintiffs may maintain actions under federal common law alleging that five electric utilities have created a “public nuisance” by contributing to global warming, and may seek injunctive relief capping the utilities’ CO2 emissions at judicially-determined levels. However, the Supreme Court granted certiorari (10-174, US) on December 6, 2010, and reversed and remanded the Second Circuit Court’s opinion on June 20, 2011.

On October 27, 2009, the EPA announced how it will establish thresholds for phasing-in and regulating greenhouse gas emissions under various provisions of the Clean Air Act. Three days later, on October 30, 2009, the EPA published a final rule in the Federal Register that requires the reporting of greenhouse gas emissions from all sectors of the American economy, and reporting of emissions from underground coal mines and coal suppliers was promulgated on July 12, 2010 (75 Fed Reg 39736). In addition, EPA has announced that it will establish permitting requirements for greenhouse gas emissions from electric utilities in early 2012. Those permitting rules may also decrease the demand for coal.

In the absence of federal legislation or regulation, many states and regions have adopted greenhouse gas initiatives. These state and regional 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 or at the federal level, will not affect the future market for coal in those regions. The permitting of new coal-fueled power plants has also recently been contested by state regulators and environmental organizations based on concerns relating to greenhouse gas emissions. Increased efforts to control greenhouse gas emissions could result in reduced demand for coal.

Clean Water Act. The federal Clean Water Act and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including dredged and fill materials, into waters of the United States. The Clean Water Act provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. Recent court decisions and regulatory actions have created uncertainty over Clean Water Act jurisdiction and permitting requirements that could variously increase or decrease the cost and time we expend on Clean Water Act compliance.

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 discharges into waters of the United States, especially on selenium, sulfate and specific conductance.

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Discharges that exceed the limits specified under NPDES permits can lead to the imposition of penalties, and persistent non-compliance could lead to significant penalties, compliance costs and delays in coal production. In addition, the imposition of future restrictions on the discharge of certain pollutants into waters of the United States could increase the difficulty of obtaining and complying with NPDES permits, which could impose additional time and cost burdens on our operations.

Discharges of pollutants into waters that states have designated as impaired (i.e., as not meeting present water quality standards) are subject to Total Maximum Daily Load, which we refer to as TMDL, regulations. The TMDL regulations establish a process for calculating the maximum amount of a pollutant that a water body can receive while maintaining state water quality standards. Pollutant loads are allocated among the various sources that discharge pollutants into that water body. Mine operations that discharge into water bodies designated as impaired will be required to meet new TMDL allocations. The adoption of more stringent TMDL-related allocations for our coal mines could require more costly water treatment and could adversely affect our coal production.

The Clean Water Act also requires states to develop anti-degradation policies to ensure that non-impaired water bodies continue to meet water quality standards. The issuance and renewal of permits for the discharge of pollutants to waters that have been designated as “high quality” are subject to anti-degradation review that may increase the costs, time and difficulty associated with obtaining and complying with NPDES permits.

Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, which we refer to as RCRA, may affect coal mining operations through its requirements for the 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. In addition, 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 its 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, and left the exemption in place. In May 2000, the EPA concluded that coal combustion products do not warrant regulation as hazardous waste under RCRA and again retained the hazardous waste exemption for these wastes. The EPA also 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. In March of 2007 the Office of Surface Mining and EPA proposed regulations regarding the management of coal combustion products. The EPA concluded that beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. As long as this exemption remains in effect, it is not anticipated that regulation of coal combustion waste will have any material effect on the amount of coal used by electricity generators. A final rule has not been promulgated. 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. In another development regarding coal combustion wastes, EPA conducted an assessment of impoundments and other units that manage residuals from coal combustion and that contain free liquids following a massive coal ash spill in Tennessee in 2008, EPA contractors conducted site assessments at many impoundments and is requiring appropriate remedial action at any facility that is found to have a unit posing a risk for potential failure. EPA is posting utility responses to the assessment on its web site as the responses are received. Future regulations resulting from the EPA coal combustion refuse assessments may impact the ability of the Company’s utility customers to continue to use coal in their power plants.

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.

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

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or other special status species or to their critical habitat, then we could experience increased operating costs or difficulty in obtaining future mining permits.

Use of Explosives. Our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to strict regulatory requirements established by four different federal regulatory agencies. For example, pursuant to a rule issued by the Department of Homeland Security in 2007, facilities in possession of chemicals of interest, including ammonium nitrate at certain threshold levels, must complete a screening review in order to help determine whether there is a high level of security risk such that a security vulnerability assessment and site security plan will be required.

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.

Employees

General. At March 15, 2012, we employed a total of approximately 2,900 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 February 28, 2012 and their positions and offices during the last five years:

Name	Age	Position

C. Henry Besten, Jr.	63	Mr. Besten has served as our Senior Vice President — Strategic Development since 2002.

John T. Drexler	42	Mr. Drexler has served as our Senior Vice President and Chief Financial Officer since April 2008. Mr. Drexler served as our Vice President — Finance and Accounting from March 2006 to April 2008. From March 2005 to March 2006, Mr. Drexler served as our Director of Planning and Forecasting. Prior to March 2005, Mr. Drexler held several other positions within our finance and accounting department.

John W. Eaves	54	Mr. Eaves has served as our President and Chief Operating Officer since April 2006. Mr. Eaves has also been a director since February 2006. From 2002 to April 2006, Mr. Eaves served as our Executive Vice President and Chief Operating Officer. Mr. Eaves also serves on the board of directors of ADA-ES, Inc. and CoaLogix.

Sheila B. Feldman	57	Ms. Feldman has served as our Vice President — Human Resources since 2003. From 1997 to 2003, Ms. Feldman was the Vice President — Human Resources and Public Affairs of Solutia Inc.

Robert G. Jones	55	Mr. Jones has served as our Senior Vice President — Law, General Counsel and Secretary since August 2008. Mr. Jones served as Vice President — Law, General Counsel and Secretary from 2000 to August 2008.

Paul A. Lang	51	Mr. Lang has served as our Executive Vice President — Operations since August 2011. Mr. Lang served as Senior Vice President — Operations from December 2006 through August 2011, 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 1998 through July 2005.

Steven F. Leer	59	Mr. Leer has served as our Chairman and Chief Executive Officer since April 2006. Mr. Leer served as our 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 Business Roundtable, the BRT, the University of the Pacific and Washington University and is past 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.

Deck S. Slone	48	Mr. Slone has served as our Vice President — Government, Investor and Public Affairs

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		since August 2008. Mr. Slone served as our Vice President — Investor Relations and Public Affairs from 2001 to August 2008.

Jeffrey W. Strobel	49	Mr. Strobel has served as our Vice President of Business Development and Strategy since October, 2011. Prior to joining Arch, Mr. Strobel held the following positions: Director of Energy Investment Banking for Wells Fargo Securities, LLC, from 2008 to 2011; Director of Energy Investment Banking for Wachovia Capital Markets, LLC, from 2007 to 2008; and Director, Vice President and Associate for A.G. Edwards Capital Markets from 2000 to 2007.

David N. Warnecke	56	Mr. Warnecke has served as our Senior Vice President — Marketing and Trading since March 2011. Mr. Warnecke served as Vice President — Marketing and Trading from August 2005 through March 2011, President of our Arch Coal Sales Company, Inc. subsidiary from June 2005 until March 2007, and as Executive Vice President of Arch Coal Sales Company, Inc. from April 2004 until June 2005. 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, proxy statements 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.

We also make the documents listed above available without charge through Arch Coal, Inc.’s website, archcoal.com, as soon as practicable after we file or furnish them with the SEC. You may also request copies of the documents, at no cost, by telephone at (314) 994-2700 or by mail at Arch Coal, Inc., One CityPlace Drive, Suite 300, St. Louis, Missouri, 63141 Attention: Vice President-Government, Investor and Public Affairs. The information on Arch Coal, Inc.’s website is not part of this Annual Report on Form 10-K.

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

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		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.

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

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

Coal prices are subject to change and a substantial or extended decline in prices could materially and adversely 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. The contract prices we may receive in the future for coal depend upon factors beyond our control, including the following:

· the domestic and foreign supply and demand for coal;

· the quantity and quality of coal available from competitors;

· competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;

· domestic air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards by installing scrubbers or other means;

· adverse weather, climatic or other natural conditions, including natural disasters;

· domestic and foreign economic conditions, including economic slowdowns;

· legislative, regulatory and judicial developments, environmental regulatory changes or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions or providing for increased funding and incentives for alternative energy sources;

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

· market price fluctuations for sulfur dioxide emission allowances.

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A substantial or extended decline in the prices we receive for our future coal sales contracts could materially and adversely affect us by decreasing our profitability and the value of our coal reserves.

Our coal mining operations are subject to operating risks that are beyond our control, which could result in materially increased operating expenses and decreased production levels and could materially and adversely affect our profitability.

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

· poor mining conditions resulting from geological, hydrologic or other conditions that may cause instability of highwalls or spoil piles or cause damage to nearby infrastructure or mine personnel;

· a major incident at the mine site that causes all or part of the operations of the mine to cease for some period of time;

· mining, processing and plant equipment failures and unexpected maintenance problems;

· adverse weather and natural disasters, such as heavy rains or snow, flooding and other natural events affecting operations, transportation or customers;

· unexpected or accidental surface subsidence from underground mining;

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

· competition and/or conflicts with other natural resource extraction activities and production within our operating areas, such as coalbed methane extraction or oil and gas development.

If any of these conditions or events occurs, particularly at our Black Thunder mining complex, which accounted for approximately 80% of the coal volume we sold in 2011, our coal mining operations may be disrupted, we could experience a delay or halt of production or shipments 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.

Competition within the coal industry could put downward pressure on coal prices and, as a result, materially and adversely affect our revenues and profitability.

We compete with numerous other coal producers in various regions of the United States for domestic sales. International demand for U.S. coal also affects competition within our industry. The demand for U.S. coal exports depends upon a number of factors outside our control, including the overall demand for electricity in foreign markets, currency exchange rates, ocean freight rates, port and shipping capacity, the demand for foreign-priced steel, both in foreign markets and in the U.S. market, general economic conditions in foreign countries, technological developments and environmental and other governmental regulations. Foreign demand for certain U.S. coal has increased in recent periods. If foreign demand for U.S. coal were to decline, this decline could cause competition among coal producers for the sale of coal in the United States to intensify, potentially resulting in significant downward pressure on domestic coal prices.

In addition, during the mid-1970s and early 1980s, increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in additional production capacity throughout the industry, all of which led to increased competition and lower coal prices. Increases in coal prices over the past several years have encouraged the development of expanded capacity by coal producers and may continue to do so. Any resulting overcapacity and increased production could materially reduce coal prices and therefore materially reduce our revenues and profitability.

Decreases in demand for electricity resulting from economic, weather changes or other conditions could adversely affect coal prices and materially and adversely affect our results of operations.

Our coal is primarily used as fuel for electricity generation. Overall economic activity and the associated demand for power by industrial users can have significant effects on overall electricity demand. An economic slowdown can significantly slow the growth of electrical demand and could result in contraction of demand for coal. Declines in international prices for coal generally will impact U.S. prices for coal. During the past several years, international demand for coal has been driven, in significant part, by fluctuations in demand due to economic growth in China and India as well as other developing countries. Significant declines in the rates of economic growth in these regions could materially affect international demand for U.S. coal, which may have an adverse effect on U.S. coal prices.

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Weather patterns can also greatly affect electricity demand. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increased generating requirements from all sources. Mild temperatures, on the other hand, result in lower electrical demand, which allows generators to choose the sources of power generation when deciding which generation sources to dispatch. Any downward pressure on coal prices, due to decreases in overall demand or otherwise, including changes in weather patterns, would materially and adversely affect our results of operations.

The use of alternative energy sources for power generation could reduce coal consumption by U.S. electric power generators, which could result in lower prices for our coal. Declines in the prices at which we sell our coal could reduce our revenues and materially and adversely affect our business and results of operations.

In 2011, approximately 95.5% of the tons we sold were to domestic electric power generators. The amount of coal consumed for U.S. electric power generation is affected by, among other things:

· the location, availability, quality and price of alternative energy sources for power generation, such as natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power; and

· technological developments, including those related to alternative energy sources.

Gas-fueled generation has the potential to displace coal-fueled generation, particularly from older, less efficient coal-powered generators. We expect that many of the new power plants needed to meet increasing demand for electricity generation will be fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain as natural gas is seen as having a lower environmental impact than coal-fueled generators. In addition, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by domestic electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

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

Our profitability depends substantially on our ability to mine and process, in a cost-effective manner, coal reserves that possess the quality characteristics desired by our customers. As we mine, our coal reserves decline. As a result, our future success depends upon our ability to acquire additional coal that is economically recoverable. If we fail to acquire or develop additional coal reserves, our existing reserves will eventually be depleted. 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 the availability of cash we generate from our operations or available financing, restrictions under our existing or future financing arrangements, and competition from other coal producers, the lack of suitable acquisition or lease-by-application, or LBA, opportunities or the inability to acquire coal properties or LBAs on commercially reasonable terms. If we are unable to acquire replacement reserves, our future production may decrease significantly and our operating results may be negatively affected. In addition, we may not be able to mine future reserves as profitably as we do at our current operations.

Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. We base our estimates of reserves on engineering, economic and geological data assembled, analyzed and reviewed by internal and third-party engineers and consultants. We update our estimates of the quantity and quality of proven and probable coal reserves annually to reflect the production of coal from the reserves, updated geological models and mining recovery data, the tonnage contained in new lease areas acquired and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including the following:

· quality of the coal;

· geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;

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· the percentage of coal ultimately recoverable;

· the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;

· assumptions concerning the timing for the development of the reserves; and

· assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.

As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary materially due to changes in the above factors and assumptions. Actual production recovered from identified reserve areas and properties, and revenues and expenditures associated with our mining operations, may vary materially from estimates. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues and/or higher than expected costs.

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, explosives, rubber tires and other mining and industrial supplies. The cost 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. 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 ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

We have contracts to supply coal to energy trading and brokering companies under which they purchase the coal for their own account or resell the coal to end users. Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer’s coal sales contract. If this occurs, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contracted price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could materially and adversely affect our financial position. In addition, our customer base may change with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear for customer payment default. These new power plant owners may have credit ratings that are below investment grade, or may become below investment grade after we enter into contracts with them. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk of payment default.

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 barge, 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

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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.

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 the section entitled “Long-Term Coal Supply Arrangements.”

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

For the year ended December 31, 2011, we derived approximately 20% of our total coal revenues from sales to our three largest customers and approximately 47% of our total coal revenues from sales to our ten largest customers. 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.

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 may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, or failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third

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party surety bond issuers of their right to refuse to renew the surety and restrictions on availability on collateral for current and future third party surety bond issuers under the terms of our financing arrangements.

Risks Related to Environmental, Other Regulations and Legislation

Extensive environmental regulations, including existing and potential future regulatory requirements relating to air emissions, affect our customers and could reduce the demand for coal as a fuel source and cause coal prices and sales of our coal to materially decline.

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. The operations of our customers are subject to extensive environmental regulation particularly with respect to air emissions. For example, the federal Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. A series of more stringent requirements relating to particulate matter, ozone, haze, mercury, sulfur dioxide, nitrogen oxide and other air pollutants are expected to be proposed or become effective in coming years. In addition, concerted conservation efforts that result in reduced electricity consumption could cause coal prices and sales of our coal to materially decline.

Considerable uncertainty is associated with these air emissions initiatives. The content of regulatory requirements in the U.S. is in the process of being developed, and many new regulatory initiatives remain subject to review by federal or state agencies or the courts. Stringent air emissions limitations are either in place or are likely to be imposed in the short to medium term, and these limitations will likely require significant emissions control expenditures for many coal-fueled power plants. As a result, these power plants may switch to other fuels that generate fewer of these emissions or may install more effective pollution control equipment that reduces the need for low sulfur coal, possibly reducing future demand for coal and a reduced need to construct new coal-fueled power plants. The EIA’s expectations for the coal industry assume there will be a significant number of as yet unplanned coal-fired plants built in the future which may not occur. Any switching of fuel sources away from coal, closure of existing coal-fired plants, or reduced construction of new plants could have a material adverse effect on demand for and prices received for our coal. Alternatively, less stringent air emissions limitations, particularly related to sulfur, to the extent enacted could make low sulfur coal less attractive, which could also have a material adverse effect on the demand for and prices received for our coal.

You should see “Environmental and Other Regulatory Matters” 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 impose strict regulations on various environmental and operational matters in connection with coal mining. These include permits issued by various federal, state and local agencies and regulatory bodies. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by the regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing operations or the development of future mining operations. The public, including non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and submit objections to requested permits and environmental impact statements prepared in connection with applicable regulatory processes, and otherwise engage in the permitting process, including bringing citizens’ lawsuits to challenge the issuance of permits, the validity of environmental impact statements or performance of mining activities. Accordingly, required permits may not be issued or renewed in a timely fashion or at all, or permits issued or renewed may be conditioned in a manner that may restrict our ability to efficiently and economically conduct our mining activities, any of which would materially reduce our production, cash flow and profitability.

Federal or state regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances, which could materially and adversely affect our ability to meet our customers’ demands.

Federal or state regulatory agencies have the authority under certain circumstances following significant health and safety incidents, such as fatalities, to order a mine to be temporarily or permanently closed. If this occurred, we may be required to incur capital expenditures to re-open the mine. In the event that these agencies order the closing of our mines, our coal sales contracts generally permit us to issue force majeure notices which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of force majeure notices. If these challenges are successful, we may have to purchase coal from third-party sources, if it is available, to fulfill these obligations, incur capital expenditures to re-open the mines and/or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of

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time for delivery or terminate customers’ contracts. Any of these actions could have a material adverse effect on our business and results of operations.

Extensive environmental regulations impose significant costs on our mining operations, and future regulations could materially increase those costs or limit our ability to produce and sell coal.

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

· limitations on land use;

· mine permitting and licensing requirements;

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

· management of materials generated by mining operations;

· the storage, treatment and disposal of wastes;

· remediation of contaminated soil and groundwater;

· air quality standards;

· water pollution;

· protection of human health, plant-life and wildlife, including endangered or threatened species;

· protection of wetlands;

· the discharge of materials into the environment;

· the effects of mining on surface water and groundwater quality and availability; and

· the management of electrical equipment containing polychlorinated biphenyls.

The costs, liabilities and requirements associated with the laws and regulations related to these and other environmental matters may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. We cannot assure you that we have been or will be at all times in compliance with the applicable laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. We may incur material costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we are pursued for sanctions, costs and liabilities in respect of these matters, our mining operations and, as a result, our profitability could be materially and adversely affected.

New legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us to change operations significantly or incur increased costs. Such changes could have a material adverse effect on our financial condition and results of operations. You should see the section entitled “Environmental and Other Regulatory Matters” for more information about the various governmental regulations affecting us.

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

SMCRA and counterpart state laws and regulations establish 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, engineering studies 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 our original assumptions or if governmental regulations change significantly. We are required to record new obligations as liabilities at fair value under generally accepted accounting principles. 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. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf. The resulting estimated reclamation and mine closure obligations could change significantly if actual amounts change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial condition.

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

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

We maintain extensive coal refuse areas and slurry impoundments at a number of our mining complexes. Such areas and impoundments are subject to extensive regulation. Slurry impoundments have been known to fail, releasing large volumes of coal slurry into the surrounding environment. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.

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

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

Changes in the legal and regulatory environment, particularly in light of developments in 2010, could complicate or limit our business activities, increase our operating costs or result in litigation.

The conduct of our businesses is subject to various laws and regulations administered by federal, state and local governmental agencies in the United States. These laws and regulations may change, sometimes dramatically, as a result of political, economic or social events or in response to significant events. Certain recent developments particularly may cause changes in the legal and regulatory environment in which we operate and may impact our results or increase our costs or liabilities. Such legal and regulatory environment changes may include changes in: the processes for obtaining or renewing permits; costs associated with providing healthcare benefits to employees; health and safety standards; accounting standards; taxation requirements; and competition laws.

In response to the April 2010 explosion at Massey Energy Company’s Upper Big Branch Mine and the ensuing tragedy, we expect that safety matters pertaining to underground coal mining operations will be the topic of new legislation and regulation, as well as the subject of heightened enforcement efforts. For example, federal and West Virginia state authorities have announced special inspections of coal mines to evaluate several safety concerns, including the accumulation of coal dust and the proper ventilation of gases such as methane. In addition, both federal and West Virginia state authorities have announced that they are considering changes to mine safety rules and regulations which could potentially result in additional or enhanced required safety equipment, more frequent mine inspections, stricter and more thorough enforcement practices and enhanced reporting requirements. Any new environmental, health and safety requirements may increase the costs associated with obtaining or maintain permits necessary to perform our mining operations or otherwise may prevent, delay or reduce our planned production, any of which could adversely affect our financial condition, results of operations and cash flows.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2. PROPERTIES.

Our Properties

General

At December 31, 2011, we owned or controlled primarily through long-term leases approximately 105,667 acres of coal land in Wyoming, 62,822 acres of coal land in Utah, 21,802 acres of coal land in New Mexico, and 18,443 acres of coal land in Colorado.

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We lease a significant portion of our coal land from Arch Coal. Arch Coal leases a portion of that property from the federal government and from various state governments. 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 Coal Reserves

We estimate that we owned or controlled approximately 2.2 billion tons of proven and probable recoverable reserves at December 31, 2011. Approximately 70% of our reserves are controlled under a lease with Arch Coal. Our coal reserve estimates at December 31, 2011 were prepared by our engineers and geologists and reviewed by Weir International, Inc., a mining and geological consultant. Our coal reserve estimates are based on data obtained from our drilling activities and other available geologic data. Our coal reserve estimates are periodically updated to reflect past coal production and other geologic and mining data. Acquisitions or sales of coal properties will also change these estimates. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam.

Our coal reserve estimates include reserves that can 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 use various assumptions in preparing our estimates of our coal reserves. You should see “Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs” contained under the heading “Risk Factors.”

The following tables present our estimated assigned and unassigned recoverable coal reserves at December 31, 2011:

Total Assigned Reserves

(Tons in millions)


	Total
	Assigned			Sulfur Content						Mining Method		Past Reserve
	Recoverable			(lbs. per million Btus)			As Received	Reserve Control			Under-	Estimates
	Reserves	Proven	Probable	<1.2	1.2-2.5	>2.5	Btus per lb.(1)	Leased	Owned	Surface	ground	2009	2010
Wyoming	1,474	1,454	20	1,396	78	—	8,837	1,474	—	1,474	—	1,733	1,605
Utah	79	50	29	71	7	1	11,405	78	1	—	79	105	84
Colorado	88	76	12	88	—	—	11,374	88	—	—	88	75	64
Total	1,641	1,580	61	1,555	85	1	9,097	1,640	1	1,474	167	1,913	1,753

(1)

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

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Total Unassigned Reserves

(Tons in millions)

	Total
	Unassigned			Sulfur Content			As Received
	Recoverable			(lbs. per million Btus)			Btus per	Reserve Control		Mining Method
	Reserves	Proven	Probable	<1.2	1.2-2.5	>2.5	lb.(1)	Leased	Owned	Surface	Underground
Wyoming	494	410	84	442	52	—	9,637	384	110	319	175
Utah	38	20	18	34	4	—	11,024	37	1	—	38
Colorado	23	18	5	23	—	—	11,347	23	—	—	23
Total	555	448	107	499	56	–	9,803	444	111	319	236

(1)

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

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 93.6% consist of compliance coal, or coal which emits 1.2 pounds or less of sulfur dioxide per million Btus upon combustion, while an additional 3.2% could be sold as low-sulfur coal.

The carrying cost of our coal reserves at December 31, 2011 was $341.7 million.

Reserve Acquisition Process

A significant portion of the coal we control in the western United States was acquired by Arch Coal through the LBA process. Under this process, before a mining company can obtain new coal reserves, the coal tract must be nominated for lease, and the company must win the lease through a competitive bidding process. The LBA process can last anywhere from two to five years from the time the coal tract is nominated to the time a final bid is accepted by the BLM. After the LBA is awarded, the company then conducts the necessary testing to determine what amount can be classified as reserves.

To initiate the LBA process, companies wanting to acquire additional coal must file an application with the BLM’s state office indicating interest in a specific coal tract. The BLM reviews the initial application to determine whether the application conforms to existing land-use plans for that particular tract of land and that the application would provide for maximum coal recovery. The application is further reviewed by a regional coal team at a public meeting. Based on a review of the available information and public comment, the regional coal team will make a recommendation to the BLM whether to continue, modify or reject the application.

If the BLM determines to continue the application, the company that submitted the application will pay for a BLM-directed environmental analysis or an environmental impact statement to be completed. This analysis or impact statement is subject to publication and public comment. The BLM may consult with other governmental agencies during this process, including state and federal agencies, surface management agencies, Native American tribes or bands, the U.S. Department of Justice or others as needed. The public comment period for an analysis or impact statement typically occurs over a 60-day period.

After the environmental analysis or environmental impact statement has been issued and a recommendation has been published that supports the lease sale of the LBA tract, the BLM schedules a public competitive lease sale. The BLM prepares an internal estimate of the fair market value of the coal that is based on its economic analysis and comparable sales analysis. Prior to the lease sale, companies interested in acquiring the lease must send sealed bids to the BLM. The bid amounts for the lease are payable in five annual installments, with the first 20% installment due when the mining operator submits its initial bid for an LBA. Before the lease is approved by the BLM, the company must first furnish to the BLM an initial rental payment for the first year of rent along with either a bond for the next 20% annual installment payment for the bid amount, or an application for history of timely payment, in which case the BLM may waive the bond requirement if the company successfully meets all the qualifications of a timely payor. The bids are opened at the lease sale. If the BLM decides to grant a lease, the lease is awarded to the company that submitted the highest total bid meeting or exceeding the BLM’s fair market value estimate, which is not published. The BLM, however, is not required to grant a lease even if it determines that a bid meeting or exceeding the fair market value of the coal has been submitted. The winning bidder must also submit a report setting forth the nature and extent of its coal holdings to the

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U.S. Department of Justice for a 30-day antitrust review of the lease. If the successful bidder was not the initial applicant, the BLM will refund the initial applicant certain fees it paid in connection with the application process, for example the fees associated with the environmental analysis or environmental impact statement, and the winning bidder will bear those costs. Coal won through the LBA process and subject to federal leases are administered by the U.S. Department of Interior under the Federal Coal Leasing Amendment Act of 1976. In addition, we occasionally add small coal tracts adjacent to our existing LBAs through an agreed upon lease modification with the BLM. Once the BLM has issued a lease, the company must also complete the permitting process before it can mine the coal. You should see the section entitled “Environmental and Other Regulatory Matters.”

Most of the federal coal leases governing the property we control have an initial term of 20 years and are renewable for subsequent 10-year periods and for so long thereafter as coal is produced in commercial quantities. These leases require diligent development within the first ten years of the lease award with a required coal extraction of 1.0% of the total coal under the lease by the end of that 10-year period. At the end of the 10-year development period, the lessee is required to maintain continuous operations, as defined in the applicable leasing regulations. In certain cases a lessee may combine contiguous leases into a logical mining unit, which we refer to as an LMU. This allows the production of coal from any of the leases within the LMU to be used to meet the continuous operation requirements for the entire LMU. Some of our mines are also subject to coal leases with applicable state regulatory agencies and have different terms and conditions that we must adhere to in a similar way to our federal leases. Under these federal and state leases, if the leased coal is not diligently developed during the initial 10-year development period or if certain other terms of the leases are not complied with, including the requirement to produce a minimum quantity of coal or pay a minimum production royalty, if applicable, the BLM or the applicable state regulatory agency can terminate the lease prior to the expiration of its term.

Title to Coal Property

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. You should see “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” contained under the heading “Risk Factors” for more information.

At December 31, 2011, approximately 5.1% 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.

From time to time, lessors or sublessors of land leased by our subsidiaries have sought to terminate such leases on the basis that such subsidiaries have failed to comply with the financial terms of the leases or that the mining and related operations conducted by such subsidiaries are not authorized by the leases. Some of these allegations relate to leases upon which we conduct operations material to our consolidated financial position, results of operations and liquidity, but we do not believe any pending claims by such lessors or sublessors have merit or will result in the termination of any material lease or sublease.

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. MINE SAFETY DISCLOSURES.

The statement concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

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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
	2011		2010 (1)			2009 (2)		2008			2007
	(Amounts in thousands, except per ton data)
Statement of Operations Data:
Revenues	$	2,261,728	$	2,048,287		$	1,651,389	$	1,758,008		$	1,541,066
Income from operations	242,512		134,349			39,310		180,392			197,271
Net income	255,321		118,403			18,276		188,705			221,661
Balance Sheet Data:
Cash and cash equivalents	$	75,093	$	79,817		$	6,819	$	2,851		$	248
Receivable from Arch Coal, Inc.	1,708,721		1,493,181			1,541,243		1,528,068			1,427,833
Total assets	3,508,833		3,246,630			3,307,913		3,105,084			2,852,187
Total debt, including note payable to Arch Coal	675,971		733,522			1,004,234		1,021,819			1,032,473
Redeemable membership interests	11,534		10,444			8,962		8,765			8,000
Non-redeemable membership interests	2,075,227		1,836,070			1,706,710		1,495,613			1,330,202
Cash Flow Data:
Cash provided by operating activities	$	465,245	$	438,376		$	178,119	$	396,582		$	324,764
Depreciation, depletion and amortization	158,961		167,260			159,755		155,400			136,927
Amortization of acquired sales contracts, net	19,458		35,606			19,623		(705		)	(1,633		)
Capital expenditures	174,580		102,612			125,454		286,607			147,423
Payments to retire debt	—		(505,627		)	—		—			—
Operating Data:
Tons sold	131,997		143,953			107,649		120,361			115,743
Tons produced	132,499		144,101			108,213		119,494			115,841
Average sales price per ton	$	17.13	$	14.23		$	15.34	$	14.61		$	13.31

(1) On September 8, 2010, we redeemed $500.0 million aggregate principal amount of the outstanding 6.75% senior notes due in 2013 at a redemption price of 101.125%. We funded this redemption with cash transferred from Arch Coal in the form of a loan of $225.0 million and a repayment of a portion of the balance receivable from Arch Coal. We recognized a loss on the redemption of $6.8 million, including the payment of $5.6 million redemption premium, the write-off of $3.3 million of unamortized debt financing costs, partially offset by the write-off of $2.1 million of the original issue premium on the senior notes.

(2) On October 1, 2009, Arch Coal acquired the Jacobs Ranch mining operations for a purchase price of $768.8 million. The acquisition included approximately 345 million tons of coal reserves located adjacent to our Black Thunder mining complex. Arch Coal contributed the acquired employees, inventories and supply parts, equipment and other personal property to us, which we immediately merged with our Black Thunder mining operations. We lease the related 345 million tons of coal reserves from a subsidiary of Arch Coal.

ITEM 7.

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

Overview

Coal markets weakened in the fourth quarter of 2011, as abnormally mild weather and muted economic growth caused U.S. power generation to decline slightly for the full year. Domestic coal consumption declined 5 percent in 2011, resulting from the decrease in power generation as well as fuel switching by power producers given decade-low prices for natural gas and abnormally high hydroelectric availability. As a result, coal stockpiles at U.S. generators rose to an estimated 180 million tons by year end, a seasonal build that is above historical norms. Mild weather has reduced power demand and the current oversupply in natural gas markets could induce more coal displacement in 2012.

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On November 3, 2011, we announced that we would be scaling back production at our Dugout Canyon mine in Utah in response to weakness in domestic thermal coal markets. We plan to suspend longwall operations at the end of the current panel in the first half of 2012. The next potential longwall panel at Dugout Canyon has been developed and future decisions about production will be based on market conditions.

Offsetting weak domestic coal trends is continued projected growth in global energy demand. In 2011, global cross-border hard coal trade exceeded 1.2 billion tons, and that growth is expected to continue in 2012. Roughly 470 gigawatts of new coal-fueled capacity is planned to start up by 2015, resulting in an estimated 1.6 billion tons of additional coal demand during the next three years. Since 2010, approximately 350 new coal plants have begun operating around the world. Domestic coal exports reached 108 million tons in 2011 in response to the demand.

In response to the global demand for steam coal, we expanded our seaborne sales during 2011. Both of our operating segments are participating in the expansion of seaborne shipments, from ports on the West Coast as well through the Gulf of Mexico. Arch Coal has entered into throughput agreements and made investments to increase our port access along the West and Gulf Coasts.

Results of Operations

Year Ended December 31, 2011 Compared to Year ended December 31, 2010

Summary. Our improved results during 2011 when compared to 2010 were due primarily to higher average sales realizations as a result of better market conditions.

Revenues. The following table summarizes information about coal sales for the year ended December 31, 2011 and compares it with the information for the year ended December 31, 2010:

	Year ended December 31				Increase (Decrease)
	2011		2010		Amount			%
	(Amounts in thousands, except per ton data and percentages)
Revenues	$	2,261,728	$	2,048,287	$	213,441		10.4	%
Tons Sold	131,997		143,953		(11,956		)	(8.3	)%
Coal sales realization per ton sold	$	17.13	$	14.23	$	2.90		20.4	%

Coal sales increased in 2011 from 2010, due to higher pricing in both regions, partially offset by lower sales volumes in the Powder River Basin. 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”.

Costs, expenses and other. The following table summarizes costs, expenses and other components of operating income for the year ended December 31, 2011 and compares them with the information for the year ended December 31, 2010:

	Year ended December 31						Increase (Decrease) in Net Income
	2011			2010			Amount			%
	(Amounts in thousands, except percentages)
Cost of sales	$	1,812,458		$	1,679,872		$	(132,586	)	(7.9	)%
Depreciation, depletion and amortization	158,961			167,260			8,299			5.0
Sales contract amortization	19,458			35,606			16,148			45.4
Selling, general and administrative	34,313			35,989			1,676			4.7
Other operating income, net	(5,974		)	(4,789		)	1,185			24.7
	$	2,019,216		$	1,913,938		$	(105,278	)	(5.5	)%

Cost of coal sales. Our cost of coal sales increased in 2011 from 2010 primarily due to an increase in sales-sensitive costs and an increase in transportation costs, as a result of an increase in export shipments. We have provided more information about our operating segments’ performance and profitability under the heading “Operating segment results”.

Depreciation, depletion and amortization. When compared with 2010, lower depreciation, depletion and amortization costs in 2011 resulted primarily from the impact of lower production and sales volumes on assets amortized or depleted on the basis of tons produced.

Amortization of acquired sales contracts, net. Arch Coal acquired both above- and below-market sales contracts with the Jacobs Ranch mining operation. The sales contracts were not contributed to us; however, the amortization of these acquired sales contracts is reflected in our results. The fair values of acquired sales contracts are amortized over the tons of coal shipped during

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the term of the contracts. The remaining amortizable amount of these sales contracts is a liability of $13.4 million at December 31, 2011.

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.

Operating segment results. The following table shows results by operating segment for the year ended December 31, 2011 and compares it with information for the year ended December 31, 2010:

	Year ended December 31				Increase (Decrease)
	2011		2010		Amount			%
Powder River Basin
Tons sold (in thousands)	114,956		127,645		(12,689		)	(9.9	)%
Coal sales realization per ton sold (1)	$	13.46	$	11.76	$	1.70		14.4	%
Operating margin per ton sold (2)	$	1.28	$	0.83	$	0.45		54.2	%

Western Bituminous
Tons sold (in thousands)	17,041		16,308		733			4.5	%
Coal sales realization per ton sold (1)	$	35.72	$	32.77	$	2.95		9.0	%
Operating margin per ton sold (2)	$	7.04	$	3.36	$	3.68		109.5	%

(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, 2011, transportation costs per ton were $0.36 for the Powder River Basin and $3.76 for the Western Bituminous region. For the year ended December 31, 2010, transportation costs per ton were $0.08 for the Powder River Basin and $0.19 for the Western Bituminous region.

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

Powder River Basin — Lower sales volumes in the Powder River Basin in 2011 when compared with 2010 were the result of flooding in the Midwest and a market-driven approach to sales commitments earlier in the year. The operating margin per ton sold in the Powder River Basin was higher in 2011 than in 2010 due to higher average sales prices, reflecting the improved coal markets in 2011. Partially offsetting the impact of higher selling prices were higher per-ton production costs. Higher production costs reflected an increase in labor, maintenance and diesel costs and an increase in sales-sensitive costs, due to the increased realizations. Per-ton costs were also higher due to the lower production levels.

Western Bituminous — Improved per-ton operating margin reflects higher sales volumes and improved pricing resulting from increased export shipments for coal from our Colorado operations. Effective cost control in the region and slightly higher production levels reduced our per-ton operating costs, which also contributed to the improved results during 2011, when compared with 2010, when two outages affected production at the Dugout Canyon mine.

Interest expense. Interest expense consists primarily of interest on our 6.75% senior notes, the discount on trade accounts receivable sold to Arch Coal under Arch Coal’s accounts receivable securitization program, interest on commercial paper, and interest on the $225.0 million loan from Arch Coal. The decrease in 2011, when compared with 2010, is the result of the retirement of $500.0 million aggregate principal amount of the outstanding 6.75% senior notes in September 2010. The redemption was funded by a loan from Arch Coal of $225 million and a repayment of a portion of the balance receivable from Arch Coal.

Interest income. Interest income primarily reflects the interest on the receivable balance from Arch Coal, which earns interest at the prime interest rate.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Summary. Our improved results for the year ended December 31, 2010 when compared to the year ended December 31, 2009 were generated from increased sales volumes and lower production costs.

Revenues. The following table summarizes information about coal sales during the year ended December 31, 2010 and compares it with the information for the year ended December 31, 2009:

	Year Ended December 31				Increase (Decrease)
	2010		2009		Amount			%
	(Amounts in thousands, except per ton data and percentages)
Coal sales	$	2,048,287	$	1,651,389	$	396,898		24.0	%
Tons sold	143,953		107,649		36,304			33.7	%
Coal sales realization per ton sold	$	14.23	$	15.34	$	(1.11	)	(7.2	)%

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Coal sales increased in 2010 from 2009, primarily due to an increase in tons sold in the Powder River Basin region, resulting from the acquisition of the Jacobs Ranch mining complex at the beginning of the fourth quarter of 2009. Our average coal sales realization per ton was lower in 2010, due to the impact of changes in regional mix on our average selling price and lower pricing in the Powder River Basin. 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”.

Costs, expenses and other. The following table summarizes costs, expenses and other components of operating income for the year ended December 31, 2010 and compares it with the information for the year ended December 31, 2009:

	Year Ended December 31						Increase (Decrease) in Net Income
	2010			2009			$			%
	(Amounts in thousands, except percentages)
Cost of coal sales	$	1,679,872		$	1,398,663		$	(281,209	)	(20.1	)%
Depreciation, depletion and amortization	167,260			159,755			(7,505		)	(4.7	)
Amortization of acquired sales contracts, net	35,606			19,623			(15,983		)	(81.5	)
Selling, general and administrative expenses	35,989			44,513			8,524			19.1
Other operating income, net	(4,789		)	(10,475		)	(5,686		)	(54.3	)
Total	$	1,913,938		$	1,612,079		$	(301,859	)	(18.7	)%

Cost of coal sales. Our cost of coal sales increased in 2010 from 2009 primarily due to the higher sales volumes discussed above, partially offset by the impact of a lower average cost per-ton sold, due to the impact of the changes in regional mix as well as lower per-ton production costs in both regions. We have provided more information about our operating segments under the heading “Operating segment results”.

Depreciation, depletion and amortization. When compared with 2009, higher depreciation and amortization costs in 2010 resulted primarily from the impact of the acquisition of the Jacobs Ranch mining complex in the fourth quarter of 2009.

Amortization of acquired sales contracts, net. Arch Coal acquired both above- and below-market sales contracts with a net fair value of $58.4 million with the Jacobs Ranch mining operation. The sales contracts were not contributed to us, however, the amortization of these acquired sales contracts is reflected in our results. The fair values of acquired sales contracts are amortized over the tons of coal shipped during the term of the contracts.

Other operating income, net. The net decrease is primarily the result of a decrease in income from contract settlements.

Operating segment results. The following table shows results by operating segment for the year ended December 31, 2010 and compares it with the information for the year ended December 31, 2009:

	Year Ended December 31				Increase (Decrease)
	2010		2009		Amount			%
Powder River Basin
Tons sold (in thousands)	127,645		90,956		36,689			40.3	%
Coal sales realization per ton sold (1)	$	11.76	$	12.11	$	(0.35	)	(2.9	)%
Operating margin per ton sold (2)	$	0.83	$	0.47	$	0.36		76.6	%

Western Bituminous
Tons sold (in thousands)	16,308		16,693		(385		)	(2.3	)%
Coal sales realization per ton sold (1)	$	32.77	$	29.11	$	3.66		12.6	%
Operating margin per ton sold (2)	$	3.36	$	1.66	$	1.70		102.4	%

(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, 2010, transportation costs per ton were $0.08 for the Powder River Basin and $0.19 for the Western Bituminous region. For the year ended December 31, 2009, transportation costs per ton were $0.12 for the Powder River Basin and $3.18 for the Western Bituminous region.

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(2)

Operating margin per ton is calculated as coal sales revenues less cost of coal sales and depreciation, depletion and amortization, including amortization of acquired sales contracts, divided by tons sold.

Powder River Basin — The increase in sales volumes in the Powder River Basin in 2010 when compared with 2009 resulted primarily from the acquisition of the Jacobs Ranch mining operations on October 1, 2009, although improving demand for Powder River Basin coal in the second half of 2010 also had a positive impact on sales volumes. Sales prices during 2010 were slightly lower when compared with 2009, primarily reflecting the roll-off of contracts committed when market conditions were more favorable. On a per-ton basis, operating margins in 2010 increased, as a decrease in per-ton costs offset the effect of lower average sales price. The decrease in per-ton costs resulted from efficiencies achieved from combining the acquired Jacobs Ranch mining operations with our existing Black Thunder operations, as well as a decrease in hedged diesel fuel costs.

Western Bituminous — In the Western Bituminous region, despite a soft steam coal market in the region and the two outages at the Dugout Canyon mine in 2010, sales volumes decreased only slightly compared to 2009. Sales volumes in 2009 were also affected by weaker market conditions that had an impact on our ability to market coal with a high ash content, which resulted from geologic conditions at our West Elk mine, and the decision to reduce production accordingly. A preparation plant at the West Elk mine was placed into service in the fourth quarter of 2010 to address any future quality issues arising from sandstone intrusions similar to those we encountered previously. Despite the detrimental impact in 2009 on our per-ton realizations of selling coal with a higher ash content, our realizations increased only slightly in 2010, due to the soft steam coal market and an unfavorable mix of customer contracts. Effective cost control in the region resulted in the higher per-ton operating margins in 2010, partially offset by the impact of the two outages at the Dugout Canyon mine in 2010.

Net interest expense. Interest expense consists primarily of interest on our 6.75% senior notes, the discount on trade accounts receivable sold to Arch Coal under Arch Coal’s accounts receivable securitization program, interest on our commercial paper, and interest on a loan from Arch Coal. On September 8, 2010, we redeemed $500.0 million aggregate principal amount of the outstanding 6.75% senior notes at a redemption price of 101.125%. We funded this redemption with cash transferred from Arch Coal in the form of a loan of $225.0 million and a repayment of a portion of the balance receivable from Arch Coal. See further discussion under the heading “Liquidity and Capital Resources”. The decrease in net interest expense in 2010 compared to 2009 is primarily due to the net decrease in our total debt balances as a result of the redemption.

Our cash transactions are managed by Arch Coal. Cash paid to or from us that is not considered a distribution, a contribution, or a loan is recorded through a note receivable from Arch Coal. The balance earns at the prime interest rate. The increase in interest income during 2010 when compared to 2009 resulted primarily from higher average receivable balance during the majority of 2010.

Other non-operating expense. Amounts reported as non-operating consist of income or expense resulting from our financing activities, other than interest costs. The loss on early extinguishment of debt relates to the redemption of $500 million in principal amount of the 6.75% senior notes. The loss includes the payment of $5.6 million of redemption premium and the write-off of $3.2 million of unamortized debt financing costs, partially offset by the write-off of $2.1 million of the original issue premium.

Liquidity and Capital Resources

Our primary sources of cash are coal sales to customers and debt related to significant transactions. Excluding any significant business acquisitions, we generally satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations, and if necessary, from Arch Coal. Arch Coal manages our cash transactions. Cash paid to or from us that is not considered a distribution or a contribution is recorded through a note receivable from Arch Coal, with exception of the borrowings under the intercompany credit agreement. The receivable balance earns interest at the prime interest rate. We are also party to Arch Coal’s accounts receivable securitization program. Under the program, we sell our receivables to a subsidiary of Arch Coal without recourse at a discount based on the prime rate and days sales outstanding.

We manage our exposure to changing commodity prices for our long-term coal contract portfolio through the use of long-term coal supply agreements. We enter into fixed price, fixed volume supply contracts with terms generally greater than one year with customers with whom we have historically had limited collection issues.

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.

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On September 8, 2010 we redeemed $500.0 million aggregate principal amount of our subsidiary Arch Western Finance LLC’s outstanding 6.75% senior notes due in 2013 at a redemption price of 101.125%. We funded this redemption with cash transferred from Arch Coal in the form of a loan of $225.0 million and a repayment of a portion of the balance receivable from Arch Coal.

Arch Coal made the loan pursuant to an intercompany credit agreement. Under the intercompany credit agreement, we may borrow up to $675.0 million through July 1, 2013, or such later date as designated by Arch Coal. Interest on loans outstanding under the agreement is calculated at a per annum rate equal to the three month LIBOR rate plus 200 or 250 basis points, depending on a leverage ratio, as defined in the agreement, at the date the rate is determined. Interest is due on any outstanding loans on the first day of each calendar quarter. We may repay the balance of the loan, in whole or in part, at any time, without penalty.

Under Arch Coal’s accounts receivable securitization program, we sold $1.7 billion of trade accounts receivable to Arch Coal during 2011, at a total discount of $3.7 million. During 2010, we sold $1.7 billion of trade accounts receivable to Arch Coal, at a total discount of $4.0 million. During 2009, we sold $1.4 billion of trade accounts receivable to Arch Coal, at a total discount of $3.5 million.

We have outstanding an aggregate principal amount of $450.0 million of 6.75% senior notes due on July 1, 2013, subsequent to the redemption discussed previously. Interest is payable on the notes on January 1 and July 1 of each year. The senior notes are secured by an intercompany note from Arch Coal to Arch Western. The indenture under which the senior notes were issued contains certain restrictive covenants that limit Arch Western’s ability to, among other things, incur additional debt, sell or transfer assets and make certain investments. The redemption price of the notes, reflected as a percentage of the principal amount, is: 101.125% for notes redeemed prior to July 1, 2011 and 100% for notes redeemed on or after July 1, 2011.

On June 14, 2011, we terminated our commercial paper placement program and the supporting credit facility.

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

	Year ended December 31
	2011			2010			2009
	(in thousands)
Cash provided by (used in):
Operating activities	$	465,245		$	438,376		$	178,119
Investing activities	(413,049		)	(92,704		)	(157,729		)
Financing activities	(59,920		)	(272,674		)	(16,422		)

Cash provided by operating activities increased in 2011 compared to 2010 due to our higher income levels in 2011, partially offset by an increased investment in coal inventories and higher spending on mine reclamation in 2011. Cash provided by operating activities increased $260.3 million in 2010 compared to 2009, primarily as a result of an increase in our profitability in 2010 when compared with 2009, driven largely by higher sales volumes, as well as a benefit in 2010 from the timing of payments on accounts and production taxes payable.

Our investing activities consist primarily of capital spending and activity under the intercompany note receivable from Arch Coal. We used more cash in investing activities in 2011 when compared to 2010, primarily due to increased capital spending and due to amounts repaid on the intercompany note by Arch Coal in 2010 related to the redemption of our 6.75% Notes. Cash used in investing activities was $65.0 million less in 2010 compared to the amount used in 2009, primarily due to a $22.8 million reduction in capital expenditures and net cash received from Arch Coal of $12.8 million in 2010, compared with net cash loaned to Arch Coal of $32.8 million in 2009, primarily related to the redemption of the 6.75% notes.

We used $59.9 million of cash in financing activities during 2011, $272.7 million during 2010 and $16.4 million during 2009. In 2010, Arch Coal made a loan to us in the amount of $225.0 million, which proceeds, along with the repayment of the intercompany note mentioned above, were used to fund the redemption on September 8, 2010 of $500.0 million aggregate principal amount of our outstanding 6.75% senior notes due in 2013 at a redemption price of 101.125%.

The following is a summary of our significant contractual obligations as of December 31, 2011:

	Payments Due by Period
	2012		2013-2014		2015-2016		After 2016		Total
	(Dollars in thousands)
Long-term debt, including related interest	$	30,375	$	465,188	$	—	$	—	$	495,563
Note payable to Arch Coal, including related interest	6,458		228,229		—		—		234,687
Operating leases	23,506		43,377		22,958		9,164		99,005
Coal lease rights	1,203		2,188		1,696		7,092		12,179
Unconditional purchase obligations	94,505		16,827		17,852		39,031		168,215
Total contractual obligations	$	156,047	$	755,809	$	42,506	$	55,287	$	1,009,649

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The related interest on long-term debt and the note payable to Arch Coal was calculated using rates in effect at December 31, 2011 for the remaining term of outstanding borrowings.

Coal lease rights represent non-cancelable royalty lease agreements.

Unconditional purchase obligations include open purchase orders and other purchase commitments, which have not been recognized as a liability. The commitments in the table above relate to contractual 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 $318.7 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. Asset retirement obligations are recorded at fair value when incurred and accretion expense is recognized through the expected date of settlement. Determining the fair value of asset retirement obligations involves a number of estimates, as discussed in the section entitled “Critical Accounting Policies”, including the timing of payments to satisfy the 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 table above also excludes certain other obligations reflected in our consolidated balance sheet, including our allocation of obligations 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 directly to Arch Coal’s pension and postretirement plans, but we are charged through the intercompany receivable for an allocated portion of Arch Coal’s contributions. The timing of Arch Coal’s contributions to their pension plans varies based on a number of factors, including changes in the fair value of plan assets and actuarial assumptions. You should see the section entitled “Critical Accounting Policies” for more information about these assumptions. You should see the notes to our consolidated financial statements for more information about the amounts we have recorded for the pension and postretirement benefit obligations.

Arch Coal is a party to a number of transportation capacity throughput agreements, to secure port and rail capacity for our export shipments out of the West and Gulf coasts. Because we are not a party to these agreements, they are not included in the table above. If the contracted quantities are not fulfilled, we would expect to be allocated charges from Arch Coal through the intercompany note. The maximum liquidated damages under these contracts are approximately $45 million in 2012, $46 million in 2013, $47 million in 2014 and $39 million in 2015.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications, financial instruments with off-balance sheet risk, such as surety bonds. Liabilities related to these arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

We use a combination of surety bonds and corporate guarantees (e.g., self bonds) to secure our financial obligations for reclamation, workers’ compensation, coal lease obligations and other obligations as follows as of December 31, 2011:

	Reclamation Obligations		Lease Obligations		Other		Total
	(Dollars in thousands)
Self-bonding	$	417,716	$	—	$	—	$	417,716
Surety bonds	34,006		30,856		3,641		68,503

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

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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, reclamation costs and assumptions regarding equipment 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 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.

Accretion expense is recognized on the obligation through the expected settlement date. 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 recorded amount of the liability and the actual cost of reclamation will be recognized 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, 2011, our balance sheet reflected asset retirement obligation liabilities of $318.7 million, including amounts classified as a current liability. As of December 31, 2011, we estimate the aggregate undiscounted cost of final mine closures to be approximately $630.2 million.

See the rollforward of the asset retirement obligation liability in “Financial Statements and Supplementary Data, Note 10 to the consolidated financial statements.”

Employee Benefit Plans

We participate in Arch Coal’s non-contributory defined benefit pension plans covering essentially all 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 to us 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.” Changes in these assumptions can result in different pension expense and liability amounts, and actual experience can differ from the assumptions. 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. 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. 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 assumed expected long-term rate of return on pension plan assets 0.5% in 2011 would have been an increase in our expense of approximately $0.6 million. The impact of lowering the assumed discount rate 0.5% in 2011 would have been an increase in our net periodic pension and postretirement costs of approximately $1.8 million.

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

We manage our commodity price risk for our 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 expect to use approximately 45 to 50 million gallons of diesel in our operations in 2012. 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 realized gains or losses resulting from the settlement of these swaps and options are allocated to us through the Arch Coal intercompany account.

We are exposed to market risk associated with fluctuating interest rates on the notes payable to Arch Coal. A one percentage point increase in the interest rates related to these borrowings would result in an annualized increase in interest expense of $2.3 million, based on borrowing levels at December 31, 2011.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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

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

None.

ITEM 9A. CONTROLS AND PROCEDURES.

We performed an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2011. 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 our internal control over financial reporting during our fiscal quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

We incorporate by reference the report of independent registered public accounting firm and management’s report on internal control over financial reporting included on pages F-2 and F-3, respectively, of this Annual Report on Form 10-K.

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, Inc. 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 20.

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 20, their ages on February 28, 2012 and biographical information:

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Name	Age	Director of Arch Coal Since	Occupation and Other Information
James R. Boyd	65	1990	Mr. Boyd served as chairman of the board of directors from 1998 to April 2006, when he was appointed lead director of Arch Coal. 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.

Governor David Freudenthal	61	2011	Governor Freudenthal served as the Governor of Wyoming from 2003 until January 2011. Prior to his service as governor, he served as U.S. Attorney for the District of Wyoming. Governor Freudenthal current serves as an Adjunct Professor at the University of Wyoming.

Patricia F. Godley	63	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	59	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	51	2006	Since February 2009, Mr. Jennings has been President and Chief Executive Officer of Rise Energy Partners, L.P. From February 2007 to June 2008, Mr. Jennings 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 intrastate and interstate natural gas pipelines. From 2004 to December 2006, Mr. Jennings served as Senior Vice President-Corporate Finance and Development and Chief Financial Officer of Devon Energy Corporation.

J. Thomas Jones	62	2010	Mr. Jones has been Chief Executive Officer of West Virginia United Health System located in Fairmont, West Virginia since 2002. From 2000 to 2002, Mr. Jones served as Chief Executive Officer of Genesis Hospital System in Huntington, West Virginia. Mr. Jones is also a director of Premier, Inc. and Health Partners Network.

George C. Morris III	56	2012	Since March 2009, Mr. Morris has served as President of Morris Energy Advisors, Inc. From December 2006 until his retirement in March 2009, Mr. Morris served as a managing director at Merrill Lynch & Co. Prior to 2006, Mr. Morris served as a managing director of investment banking at Petrie Parkman & Co. until its acquisition by Merrill Lynch & Co. in 2006, and also previously served as a managing director of investment banking at Simmons & Company International and as a director of investment banking at The First Boston Corporation. Mr. Morris also serves on the board of directors of Calumet GP, LLC, the general partner of Calumet Specialty Products Partners, L.P.

A. Michael Perry	75	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	72	2001	Mr. Potter was Chairman and Chief Executive Officer of Solutia, Inc. from 1997 until his retirement in 1999. He is also an investor in several private companies and has served as a

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Name	Age	Director of Arch Coal Since	Occupation and Other Information
			member of the board of directors for six other companies.

Theodore D. Sands	66	1999	Since 1999, Mr. Sands has served as President of HAAS Capital, LLC, a private consulting and investment company. Mr. Sands served as Managing Director, Investment Banking for the Global Metals/Mining Group of Merrill Lynch & Co. from 1982 until February 1999. Mr. Sands has also served as a member of the board of directors for several other companies.

Wesley M. Taylor	69	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 FirstEnergy Corporation.

Peter I. Wold	64	2010	Mr. Wold is President and co-owner of Wold Oil Properties, Inc., an oil and gas exploration and production company. He is also Vice President of American Talc Company, a corporation that mines and processes talc in Western Texas. He presently chairs the Wyoming Enhanced Oil Recovery Commission and is a director of the Oppenheimer Funds, Inc., New York Board. Mr. Wold has also served in the Wyoming House of Representatives and as a director of the Denver Branch of the Kansas City Federal Reserve Bank.

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. Reference is made to Item 10. Directors, Executive Officers and Corporate Governance of Arch Coal’s Annual Report on Form 10-K for its fiscal year ended December 31, 2011, which is incorporated by reference in this Item 10.

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. Reference is made to Item 11. Executive Compensation of Arch Coal’s Annual Report on Form 10-K for its fiscal year ended December 31, 2011, which is incorporated by reference in this Item 11.

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 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. Reference is made to Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters of Arch Coal’s Annual Report on Form 10-K for its fiscal year ended December 31, 2011, which is incorporated by reference in this Item 12.

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 arm’s 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

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recorded in the account. The receivable from Arch Coal was $1.7 billion at December 31, 2011 and $1.5 billion at December 31, 2010. This amount earns interest from Arch Coal at the prime interest rate. Interest earned was $54.3 million in 2011, $52.2 million in 2010, and $46.5 million in 2009. 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.

On September 8, 2010, we received a loan of $225.0 million and a repayment of a portion of the balance receivable from Arch Coal to redeem $500.0 million aggregate principal amount of the outstanding 6.75% senior notes at a redemption price of 101.125%. Interest incurred on the loan was $6.3 million for the year ended December 31, 2011.

On February 10, 2006, Arch Coal established an accounts receivable securitization program. Under the program, we sell our receivables to Arch Coal without recourse at a discount based on the prime rate and days sales outstanding. During 2011, we sold $1.7 billion of trade accounts receivable to Arch Coal, at a discount of $3.7 million. During 2010, we sold $1.7 billion of trade accounts receivable to Arch Coal, at a discount of $4.0 million.

We mine on tracts that are owned or leased by Arch Coal and subleased to us. 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 these sublease agreements. We incurred production royalties of $102.8 million in 2011, $92.4 million in 2010, and $47.8 million in 2009 to Arch Coal under sublease agreements.

Amounts charged to the intercompany account for our allocated portion of pension and postretirement contributions totaled $22.4 million in 2011, $10.9 million in 2010, and $11.1 million in 2009.

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 $34.3 million in 2011, $36.0 million in 2010, and $44.5 million in 2009. 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. Reference is made to Item 13. Certain Relationships and Related Transactions, and Director Independence of Arch Coal’s Annual Report on Form 10-K for its fiscal year ended December 31, 2011, which is incorporated by reference in this Item 13.

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. Reference is made to Item 14. Principal Accounting Fees and Services of Arch Coal’s Annual Report on Form 10-K for its fiscal year ended December 31, 2011, which is incorporated by reference in this Item 14.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

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

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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, 2011, 2010 and 2009	F-4
Consolidated Balance Sheets at December 31, 2011 and 2010	F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009	F-6
Consolidated Statements of Non-Redeemable Membership Interest for the Years Ended December 31, 2011, 2010 and 2009	F-7
Notes to Consolidated Financial Statements	F-8
Financial Statement Schedule	F-27

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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, 2011 and 2010, 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, 2011. 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 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, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, 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.



St. Louis, Missouri
March 30, 2012

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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, 2011.

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.

/s/ Paul A. Lang		/s/ John T. Drexler
Paul A. Lang		John T. Drexler
President and Principal		Senior Vice President and Chief
Executive Officer		Financial Officer

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ARCH WESTERN RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31
	2011			2010			2009
	(In thousands)

Revenues	$	2,261,728		$	2,048,287		$	1,651,389

Costs, expenses and other
Cost of sales	1,812,458			1,679,872			1,398,663
Depreciation, depletion and amortization	158,961			167,260			159,755
Amortization of acquired sales contracts, net	19,458			35,606			19,623
Selling, general and administrative expenses	34,313			35,989			44,513
Other operating income, net	(5,974		)	(4,789		)	(10,475		)
	2,019,216			1,913,938			1,612,079

Income from operations	242,512			134,349			39,310

Interest income (expense), net
Interest expense	(41,503		)	(61,614		)	(67,605		)
Interest income, primarily from Arch Coal, Inc.	54,312			52,444			46,571
	12,809			(9,170		)	(21,034		)
Other non-operating expense
Net loss resulting from early retirement of debt	—			(6,776		)	—
	—			(6,776		)	—

Net income	$	255,321		$	118,403		$	18,276
Net income attributable to redeemable membership interest	$	1,157		$	537		$	10
Net income attributable to non-redeemable membership interest	$	254,164		$	117,866		$	18,266

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

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ARCH WESTERN RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31
	2011			2010
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	75,093		$	79,817
Receivables	4,964			2,015
Receivable from Arch Coal, Inc.	473,803			582,384
Inventories	170,439			150,419
Other	22,162			21,435
Total current assets	746,461			836,070
Property, plant and equipment
Coal lands and mineral rights	763,059			763,059
Plant and equipment	1,798,404			1,665,285
Deferred mine development	577,332			548,776
	3,138,795			2,977,120
Less accumulated depreciation, depletion and amortization	(1,624,296		)	(1,488,277		)
Property, plant and equipment, net	1,514,499			1,488,843
Other assets
Receivable from Arch Coal, Inc.	1,234,918			910,797
Other	12,955			10,920
Total other assets	1,247,873			921,717
Total assets	$	3,508,833		$	3,246,630
LIABILITIES AND MEMBERSHIP INTERESTS
Current liabilities
Accounts payable	183,151			$	121,670
Accrued expenses and other current liabilities	166,762			153,141
Commercial paper	—			56,904
Total current liabilities	349,913			331,715
Long-term debt	450,971			451,618
Note payable to Arch Coal, Inc.	225,000			225,000
Asset retirement obligations	305,046			301,355
Accrued postretirement benefits other than pension	22,195			23,509
Accrued pension benefits	24,843			23,904
Other noncurrent liabilities	44,104			43,015
Total liabilities	1,422,072			1,400,116

Redeemable membership interest	11,534			10,444

Non-redeemable membership interest	2,075,227			1,836,070
Total liabilities and membership interests	$	3,508,833		$	3,246,630

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

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ARCH WESTERN RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31
	2011			2010			2009
	(In thousands)
Operating Activities
Net income	$	255,321		$	118,403		$	18,276
Adjustments to reconcile net income to cash provided by operating activities
Depreciation, depletion and amortization	158,961			167,260			159,755
Amortization of acquired sales contracts, net	19,458			35,606			19,623
Net loss resulting from early retirement of debt	—			6,776			—
Amortization relating to financing activities	483			941			964
Changes in operating assets and liabilities
Receivables	(2,950		)	6,364			(5,115		)
Inventories	(20,020		)	15,230			(11,233		)
Accounts payable and accrued expenses	68,392			54,378			(32,439		)
Asset retirement obligations	96			22,610			18,328
Other	(14,496		)	10,808			9,960
Cash provided by operating activities	465,245			438,376			178,119

Investing Activities
Capital expenditures	(174,580		)	(102,612		)	(125,454		)
Change in receivable from Arch Coal, Inc.	(234,651		)	12,803			(32,784		)
Proceeds from dispositions of property, plant and equipment	156			79			91
Additions to prepaid royalties	(3,974		)	(2,974		)	(2,791		)
Reimbursement of deposits on equipment	—			—			3,209
Cash used in investing activities	(413,049		)	(92,704		)	(157,729		)

Financing Activities
Payments to retire debt	—			(505,627		)	—
Loan from Arch Coal, Inc.	—			225,000			—
Net proceeds from (repayments on) commercial paper	(56,904		)	7,452			(16,219		)
Debt financing costs	(16		)	(390		)	(203		)
Contribution from redeemable membership interest	—			891			—
Cash used in financing activities	(56,920		)	(272,674		)	(16,422		)
Increase (decrease) in cash and cash equivalents	(4,724		)	72,998			3,968
Cash and cash equivalents, beginning of year	79,817			6,819			2,851
Cash and cash equivalents, end of year	$	75,093		$	79,817		$	6,819

Supplemental cash flow information:
Cash paid during the year for interest, net of amounts capitalized	$	37,738		$	71,600		$	65,626

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

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ARCH WESTERN RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF NON-REDEEMABLE MEMBERSHIP INTEREST

Three years ended December 31, 2011

	Non-redeemable
	Membership
	Interest
	(In thousands)

Balance at January 1, 2009	$	1,495,613
Comprehensive income
Net income	18,266
Pension, postretirement and other post-employment benefits adjustment	14,998
Net pension, postretirement and other post-employment benefits adjustments reclassified to income	(161		)
Total comprehensive income	33,103
Reclassification of prior contribution	(121		)
Contribution of former Jacob’s Ranch mining complex net assets from Arch Coal	178,210
Dividends on preferred membership interest	(95		)

Balance at December 31, 2009	1,706,710
Comprehensive income
Net income	117,866
Pension, postretirement and other post-employment benefits adjustment	13,282
Net pension, postretirement and other post-employment benefits adjustments reclassified to income	(1,693		)
Total comprehensive income	129,455
Dividends on preferred membership interest	(95		)

Balance at December 31, 2010	1,836,070
Comprehensive income
Net income	254,164
Pension, postretirement and other post-employment benefits adjustment	(13,241		)
Net pension, postretirement and other post-employment benefits adjustments reclassified to income	(1,671		)
Total comprehensive income	239,252
Dividends on preferred membership interest	(95		)

Balance at December 31, 2011	$	2,075,227

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

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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 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.

On October 1, 2009, Arch Coal contributed to the Company the employees, inventories and supply parts, equipment and other personal property of the former Jacobs Ranch mining complex, which was adjacent to the Company’s Black Thunder mining operations. The contributed assets and related liabilities were immediately merged with the Black Thunder mining operations. The Company is leasing the related coal reserves of approximately 345 million tons from a subsidiary of Arch Coal.

2. Accounting Policies

Basis of Presentation

The consolidated financial statements include the accounts of the Company and its subsidiaries and controlled entities. Intercompany transactions and accounts have been eliminated in consolidation. The Company produces coal from surface and underground mines for sale to domestic and international customers as steam coal to power plants and industrial facilities. The Company’s mines are located in Wyoming, Colorado and Utah. The Company’s results of operations reflect all costs of doing business, including expenses incurred on the Company’s behalf by Arch Coal. Certain assets, such as coal reserves and acquired sales contracts, may be owned by and reflected in the financial statements of Arch Coal, but the cost representing the usage of those assets is reflected in the results of operations of the Company. In addition, there is goodwill of $115.8 million on the consolidated balance sheet of Arch Coal that is associated with the Company’s Powder River Basin segment for Arch Coal’s impairment testing purposes.

Accounting Pronouncements

There were no accounting pronouncements whose adoption had, or is expected to have, a material impact on the Company’s consolidated financial statements.

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

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three months or less when purchased.

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. The costs of removing overburden, called stripping costs, incurred during the production phase of the mine are considered variable production costs and are included in the cost of the coal extracted during the period the stripping costs are incurred.

Acquired Sales Contracts

Coal supply agreements (sales contracts) acquired in a business combination are capitalized at their fair value and amortized over the tons of coal shipped during the term of the contract. The fair value of a sales contract is determined by discounting the cash flows attributable to the difference between the contract price and the prevailing forward prices for the tons under contract at the date of acquisition. Sales contracts associated with the acquisition of the Jacob’s Ranch mining complex were not contributed to the Company, however, the amortization of these acquired sales contracts is reflected in the accompanying consolidated statements of income. Based upon expected shipments under these contracts in the next five years, the Company anticipates annual amortization expense (income) of acquired sales contracts in the next five years of: $0.7 million, $(4.7) million, $(4.7) million, $(4.8) million and $0.4 million.

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. 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.

Preparation plants and loadouts are depreciated using the units-of-production method over the estimated recoverable reserves, subject to a minimum level of depreciation. Other plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets, limited by the remaining life of the mine. The useful lives of mining equipment, including longwalls, draglines and shovels, range from 5 to 32 years. The useful lives of buildings and leasehold improvements generally range from 10 to 30 years.

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 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

A significant portion of the Company’s coal reserves are controlled through leasing arrangements, primarily with Arch Coal. The net book value of the Company’s leased coal interests was $332.3 million and $339.9 million at December 31, 2011 and 2010, respectively. Any amounts paid to acquire coal reserves are capitalized and depleted over the life of proven and probable reserves. 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 providing certain requirements are met.

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Impairment

If facts and circumstances suggest that the carrying value of a long-lived asset or asset group may not be recoverable, the asset or asset group is reviewed for potential impairment. If this review indicates that the carrying amount of the asset will not be recoverable through projected undiscounted cash flows generated by the asset and its related asset group over its remaining life, then an impairment loss is recognized by reducing the carrying value of the asset to its fair value. The Company may, under certain circumstances, idle mining operations in response to market conditions or other factors. Because an idling is not a permanent closure, it is not considered an automatic indicator of impairment.

Revenue Recognition

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

Other Operating Income, Net

Other operating income in the accompanying consolidated statements of income reflects income and expense from sources other than coal sales.

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. Accretion expense is recognized through the expected settlement date of the obligation. 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 a discounted cash flow technique and is based upon permit requirements and various estimates and assumptions that would be used by market participants, including estimates of disturbed acreage, reclamation costs and assumptions regarding productivity. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying value of the related long-lived asset.

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. Any difference between the recorded obligation and the actual cost of reclamation is recorded in profit or loss in the period the obligation is settled. See additional discussion in Note 10, “Asset Retirement Obligations.”

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.

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 11, “Related Party Transactions” for discussion of various

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transactions with Arch Coal.

Benefit Plans

Essentially all of the Company’s employees are covered by Arch Coal’s non-contributory 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 Company reflects its actuarially-determined allocation of benefit cost, benefit obligation and other comprehensive income related to these plans in its consolidated financial statements. See further discussion in Note 9, “Employee Benefit Plans.”

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.

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, 2009	$	6,366		$	2,399	$	8,765
Net income attributable to BP p.l.c. common membership interest	10			—		10
Other comprehensive income attributable to BP p.l.c. common membership interest	67			—		67
Reclassification of prior contribution	121			—		121
Dividends on preferred membership interest	(1		)	—		(1		)

Balance at December 31, 2009	6,563			2,399		8,962
Net income attributable to BP p.l.c. common membership interest	537			—		537
Other comprehensive income attributable to BP p.l.c. common membership interest	55			—		55
BP p.l.c’s contribution related to Jacobs Ranch	891			—		891
Dividends on preferred membership interest	(1		)	—		(1		)

Balance at December 31, 2010	8,045			2,399		10,444
Net income attributable to BP p.l.c. common membership interest	1,157			—		1,157
Other comprehensive income attributable to BP p.l.c. common membership interest	(66		)	—		(66		)
Dividends on preferred membership interest	(1		)	—		(1		)

Balance at December 31, 2011	$	9,135		$	2,399	$	11,534

4. Accumulated Other Comprehensive Income (Loss)

Other comprehensive income (loss) items are transactions recorded in membership interests during the year, excluding net income and transactions with members. Following are the items included in accumulated other comprehensive income (loss):

	Accumulated Other
	Comprehensive
	Income (Loss)
	(In thousands)
Balance at January 1, 2009	$	(24,678	)
Pension, postretirement and other post-employment benefits	14,903
Balance at December 31, 2009	(9,775		)
Pension, postretirement and other post-employment benefits	11,645
Balance at December 31, 2010	1,870
Pension, postretirement and other post-employment benefits	(14,978		)
Balance at December 31, 2011	$	(13,108	)

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The net losses that is expected to be reclassified from accumulated other comprehensive income into net income in 2012 is $2.2 million.

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5. Inventories

Inventories consist of the following:

	December 31
	2011		2010
	(In thousands)
Coal	$	65,790	$	46,464
Repair parts and supplies, net of allowance	104,649		103,955
	$	170,439	$	150,419

The repair parts and supplies are stated net of an allowance for slow-moving and obsolete inventories of $12.1 million and $11.7 million at December 31, 2011 and 2010, respectively.

6. Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consists of the following:

	December 31
	2011		2010
	(In thousands)
Payroll and employee benefits	$	22,606	$	24,971
Taxes	110,578		98,914
Interest	16,804		17,189
Other	16,774		12,067
	$	166,762	$	153,141

7. Debt and Financing Arrangements

Commercial paper

On June 14, 2011, the Company terminated its commercial paper placement program and the supporting credit facility.

2013 Senior Notes

The 6.75% senior notes, due July 1, 2013, (“2013 Notes”) were issued by the Company’s subsidiary, Arch Western Finance LLC (“Arch Western Finance”), under an indenture dated June 25, 2003. The senior notes are guaranteed by Arch Western and certain of its subsidiaries and are secured by an intercompany note from Arch Coal. The Company redeemed $500.0 million aggregate principal amount of the 2013 Notes on September 8, 2010. The Company recognized a loss on the redemption of $6.8 million, including the payment of the $5.6 million redemption premium and the write-off of $3.3 million of unamortized debt financing costs, partially offset by the write-off of $2.1 million of the original issue premium. The Company funded this redemption with cash transferred from Arch Coal in the form of a loan of $225.0 million and a repayment of a portion of the note receivable from Arch Coal. The terms of the 2013 Notes contain restrictive covenants that limit Arch Western’s ability to, among other things, incur additional debt, sell or transfer assets, pay dividends and make certain investments. Of the aggregate principal outstanding at December 31, 2011 and 2010, $118.4 million of the 2013 Notes were issued at a premium of 104.75% of par. The premium is being amortized over the term of the notes. Interest is payable on the notes on January 1 and July 1 of each year. The notes are redeemable at any time at their face value.

The $225.0 million loan was made pursuant to an intercompany credit agreement with Arch Coal. Under the intercompany credit agreement, the Company may borrow up to $675.0 million through July 1, 2013, or such later date as designated by Arch Coal. Interest on loans outstanding under the agreement is calculated at a per annum rate equal to the three month LIBOR rate plus 200 or 250 basis points, depending on the Company’s leverage ratio, as defined in the agreement, at the date the rate is determined. As of December 31, 2011and 2010, the interest rate on the loan was 2.87% and 2.79%, respectively. Interest is due on any outstanding loans on the first day of each calendar quarter. The Company may repay the balance of the loan at any time, in whole or in part, without penalty. It is currently management’s intention not to prepay the balance of the loan within the next year. Therefore, the loan is classified on the accompanying consolidated balance sheets as noncurrent.

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8. 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, 2011 and 2010, the carrying amounts of cash and cash equivalents approximate fair value.

Debt: The fair value of the Company’s debt, excluding intercompany debt, was $451.7 million and $512.5 million at December 31, 2011 and 2010, respectively. Fair values are based upon observed prices in an active market when available or from valuation models using market information.

9. 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 receivable. See Note 11, “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 receivable as benefits are paid.

The Company’s allocated expense related to these plans was $8.4 million, $9.6 million and $12.6 million for the years ended December 31, 2011, 2010 and 2009, respectively. The Company’s balance sheet reflects its allocated portion of Arch Coal’s liabilities related to its benefit plans, including amounts recorded through other comprehensive income. The Company’s recorded balance sheet amounts are as follows:

	December 31
	2011			2010
	(In thousands)
Accrued benefit liabilities (current)	$	2,115		$	1,230
Accrued benefit liabilities (noncurrent)	47,038			47,413
Accumulated other comprehensive loss	(14,540		)	(21		)

Other Plans

Arch Coal sponsors savings plans that have been established to assist eligible employees in providing for their future retirement needs. The Company’s expense related to the plans were $12.1 million in 2011, $11.4 million in 2010 and $9.5 million in 2009.

10. 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 following table describes the changes to the Company’s asset retirement obligation liability:

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	Year Ended December 31
	2011			2010
	(In thousands)
Balance at January 1 (including current portion)	$	308,395		$	277,088
Accretion expense	26,541			23,952
Adjustments to the liability from changes in estimates	9,682			8,831
Liabilities settled	(25,932		)	(1,476		)
Balance at December 31	318,686			308,395
Current portion included in accrued expenses	(13,640		)	(7,040		)
Noncurrent liability	$	305,046		$	301,355

Liabilities settled of $25.9 million in 2011 mostly related to reclamation activities at the Black Thunder mining complex on a pit acquired with the Jacobs Ranch operations in 2009.

As of December 31, 2011, the Company had $34.0 million in surety bonds outstanding and $417.7 million in self-bonding to secure reclamation obligations.

11. 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, exclusive of borrowings under the intercompany credit agreement discussed in Note 7, “Debt and Financing Arrangements”, are recorded in the account. The receivable from Arch Coal was approximately $1.7 billion and $1.5 billion, at December 31, 2011 and 2010, respectively. This amount earns interest from Arch Coal at the prime interest rate. Interest earned for the years ended December 31, 2011, 2010 and 2009 was $54.3 million, $52.2 million and $46.5 million, respectively. The current portion of the receivable balance at December 31, 2011 represents the amount needed to fund working capital and contractual purchase, service and lease obligations due within the next twelve months.

As mentioned in Note 7, “Debt and Financing Arrangements”, during September of 2010, the Company received a loan of $225.0 million and a repayment of a portion of the balance receivable from Arch Coal to redeem $500.0 million aggregate principal amount of the outstanding 2013 Notes at a redemption price of 101.125%. Interest incurred on the loan was $6.3 million and $1.9 million for the years ended December 31, 2011 and 2010, respectively.

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 2011, 2010 and 2009, the Company sold $1.7 billion, $1.7 billion and $1.4 billion of trade accounts receivable to Arch Coal, respectively, at a discount of $3.7 million, $4.0 million and $3.5 million, respectively.

The Company mines on tracts that are owned or leased by Arch Coal and subleased to the Company. Approximately 70% of the Company’s reserves are controlled under a lease with Arch Coal. 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, plus all rents and royalties (excluding bonus bid obligations) due under Arch Coal’s subsidiary’s state and federal lease agreements. No advance royalties are required under the agreements. For the years ended December 31, 2011, 2010 and 2009, the Company incurred production royalties of $102.8 million, $92.4 million and $47.8 million, respectively, under sublease agreements with Arch Coal.

Amounts charged to the intercompany account for the Company’s allocated portion of contributions to the Arch Coal, Inc. Retirement Account Plan and to the Arch Coal, Inc. Postretirement Benefit Plan totaled $22.4 million, $10.9 million and $11.1 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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 $34.3 million, $36.0 million and $44.5 million for the years ended December 31, 2011, 2010 and 2009, respectively. Costs allocated in 2009 included costs related to the Jacobs Ranch acquisition. Such amounts are reported as selling, general and administrative expenses in the accompanying consolidated statements of income.

12. Concentration of Credit Risk and Major Customers

The Company markets its steam coal principally to electric utilities in the United States. Revenues from export sales were $167,097 in 2011, $40,949 in 2010 and $50,150 in 2009. Arch Coal has a formal written credit policy that establishes procedures to

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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 132.0 million tons of coal in 2011. Approximately 77% of this tonnage (representing approximately 77% of the Company’s revenue) was sold under long-term contracts (contracts having a term of greater than one year). Long-term contracts range in remaining life from one to six 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
	2011		2010		2009
	(In thousands)
Ameren	$	119,212	$	220,937	$	189,768

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 and result in decreased shipments. In the past, disruptions in rail service have resulted in missed shipments and production interruptions.

13. 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. In addition, the Company enters into various non-cancelable royalty lease agreements under which future minimum payments are due.

Minimum payments due in future years under these agreements in effect at December 31, 2011 are as follows:

	Operating Leases		Royalties
	(In thousands)
2012	$	23,506	$	1,203
2013	22,698		1,117
2014	20,679		1,071
2015	14,701		938
2016	8,257		758
Thereafter	9,164		7,092
	$	99,005	$	12,179

Rental expense related to these operating leases amounted to $31.2 million in 2011, $32.3 million in 2010 and $33.5 million in 2009. Royalty expense was $345.5 million, $322.3 million and $227.6 million for the years ended December 31, 2011, 2010 and 2009, respectively, including $102.8 million, $92.4 million and $47.8 million, respectively, that were incurred under sublease agreements with Arch Coal. See Note 11, “Related Party Transactions” for further discussion of these agreements.

As of December 31, 2011, certain of the Company’s lease obligations were secured by outstanding surety bonds totaling $30.9 million.

14. Commitments and Contingencies

Arch Coal is a party to a number of transportation capacity throughput agreements, to secure port and rail capacity for its export shipments out of the West and Gulf coasts. While the Company is not a party to these agreements if the contracted quantities are not fulfilled, Arch Coal would allocate any charges incurred to the Company. The maximum liquidated damages under these contracts are approximately $45 million in 2012, $46 million in 2013, $47 million in 2014 and $39 million in 2015.

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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.

15. 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, 2011, 2010 and 2009 are presented below. Results for the operating segments include all direct costs of mining. Corporate, Other and Eliminations includes primarily corporate overhead and other support functions.

The amounts in the Corporate, Other and Eliminations represent primarily intercompany receivables.

	PRB		WBIT		Corporate, Other and Eliminations			Consolidated
	(In thousands)
December 31, 2011
Revenues	$	1,588,962	$	672,766	$	—		$	2,261,728
Income from operations	150,618		121,065		(29,171		)	242,512
Total assets	1,108,651		655,169		1,745,013			3,508,833
Depreciation, depletion and amortization	80,852		78,109		—			158,961
Amortization of acquired sales contracts, net	19,458		—		—			19,458
Capital expenditures	108,223		66,357		—			174,580
December 31, 2010
Revenues	$	1,510,825	$	537,462	$	—		$	2,048,287
Income from operations	108,710		58,740		(33,101		)	134,349
Total assets	1,064,879		649,843

ARCH WESTERN RESOURCES LLC 10-K