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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

Commission File Number: 001-34547

Cloud Peak Energy Inc.
(Exact name of registrant as specified in its charter)

(307) 687-6000
(Registrant's telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)

Securities Registered Pursuant to Section 12(b) of the Act:

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 ý

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

         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 ý    No o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o

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

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

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

         As of June 30, 2009, the last business day of the registrant's most recently completed second fiscal quarter, the registrant's common stock was not listed on any exchange or over-the-counter market. The registrant's common stock began trading on the New York Stock Exchange on November 20, 2009.

         Number of shares outstanding of each of the registrant's classes of common stock, as of March 9, 2010: common stock, par value $0.01 per share 31,484,445 shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the registrant's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the registrant's 2010 annual meeting of stockholders (the "Proxy Statement") are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.

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CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

        This report contains forward-looking statements that involve substantial risks and uncertainties. You can identify these statements by forward-looking words such as "anticipate," "believe," "could," "estimate," "expect," "intend," "may," "plan," "potential," "should," "will," "would" or similar words. You should read statements that contain these words carefully because they discuss our plans, strategies, prospects and expectations concerning our business, operating results, financial condition and other similar matters. There may be events in the future, however, that we are not able to predict accurately or control. The factors listed under "Risk Factors," as well as any cautionary language in this report, provide examples of risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements. Additional factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

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future economic conditions, including the duration and severity of the global economic downturn and additional disruptions in global financial markets;



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the contract prices we receive for coal and our customers' ability to honor contract terms;



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market demand for domestic and foreign coal, electricity and steel;



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safety and environmental laws and regulations, including those directly affecting our coal mining and production, and those affecting our customers' coal usage, gaseous emissions or ash handling as well as related costs and liabilities;



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future legislation and changes in regulations or governmental policies or changes in interpretations thereof, including with respect to carbon emissions and safety standards;



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our ability to produce coal at existing and planned volumes and costs;



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the availability and cost of coal reserve acquisitions and surface rights and our ability to successfully acquire new coal reserves at attractive prices;



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the impact of our recent initial public offering and related transactions, including resulting tax implications and changes to our valuation allowance on our deferred tax assets;



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our assumptions regarding payments arising under the Tax Receivable Agreement and other agreements related to our initial public offering;



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our plans and objectives for future operations and the development of additional coal reserves or acquisition opportunities;



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our relationships with, and other conditions affecting, our customers, including economic conditions and the credit performance and credit risks associated with our customers;



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timing of reductions or increases in customer coal inventories;



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risks inherent to surface coal mining;



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weather conditions or catastrophic weather-related damage;



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changes in energy policy;



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competition;



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the availability and cost of competing energy resources, including changes in the price of crude oil and natural gas generally, as well as subsidies to encourage use of alternative energy sources;

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•

railroad and other transportation performance and costs;



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disruptions in delivery or changes in pricing from third-party vendors of raw materials and other consumables which are necessary for our operations, such as explosives, petroleum-based fuel, tires, steel and rubber;



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our assumptions concerning coal reserve estimates;



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the terms of Cloud Peak Energy Resources LLC's indebtedness;



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changes in costs that we incur as a stand-alone public company as compared to our expectations;



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inaccurately estimating the costs or timing of our reclamation and mine closure obligations;



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liquidity constraints, including those resulting from the cost or unavailability of financing due to credit market conditions;



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our liquidity, results of operations and financial condition, including amounts of working capital that are available; and



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other factors, including those discussed in "Risk Factors."

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GLOSSARY FOR SELECTED MINING TERMS

        Anthracite.    Anthracite is the highest rank coal. It is hard, shiny (or lustrous), has a high heat content and little moisture. Anthracite is used in residential and commercial heating as well as a mix of industrial applications. Some waste products from anthracite piles are used in energy generation.

        Appalachian region.    Coal producing area in Alabama, eastern Kentucky, Maryland, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia. The Appalachian region is divided into the northern, central and southern Appalachian regions.

        Ash.    Inorganic material consisting of iron, alumina, sodium and other incombustible matter that are contained in coal. The composition of the ash can affect the burning characteristics of coal.

        Assigned reserves.    Reserves that are committed to our surface mine operations with operating mining equipment and plant facilities. All our reported reserves are considered to be assigned reserves.

        Bituminous coal.    The most common type of coal that is between sub-bituminous and anthracite in rank. Bituminous coals produced from the central and eastern U.S. coal fields typically have moisture content less than 20% by weight and heating value of 10,500 to 14,000 Btus.

        BLM.    Department of the Interior, Bureau of Land Management.

        BNSF.    Burlington Northern Santa Fe Railroad.

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

        CAIR.    Clean Air Interstate Rule.

        Carbon dioxide, or CO₂.    A gaseous chemical compound that is generated as a by-product of the combustion of fossil fuels, including coal, or the burning of vegetable matter, among other process.

        Coal seam.    Coal deposits occur in layers typically separated by layers of rock. Each layer is called a "seam." A coal seam can vary in thickness from inches to a hundred feet or more.

        Coalbed methane.    Also referred to as CBM or coalbed natural gas (CBNG). Coalbed methane is methane gas formed during the coalification process and stored within the coal seam.

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

        Compliance coal.    Coal that when combusted emits no greater than 1.2 pounds of sulfur dioxide per million Btus and requires no blending or sulfur-reduction technology to comply with current sulfur dioxide emissions under the Clean Air Act.

        Dragline.    A large excavating machine used in the surface mining process to remove overburden. A dragline has a large bucket suspended from the end of a boom, which may be 275 feet long or larger. The bucket is suspended by cables and capable of scooping up significant amounts of overburden as it is pulled across the excavation area. The dragline, which can "walk" on large pontoon-like "feet," is one of the largest land-based machines in the world.

        EIA.    Energy Information Administration.

        EIS.    Environmental impact statement.

        Force majeure.    An event not anticipated as of the date of the applicable contract, which is not within the reasonable control of the party affected by such event, which partially or entirely prevents

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such party's ability to perform its contractual obligations. During the duration of such force majeure but for no longer period, the obligations of the party affected by the event may be excused to the extent required.

        Fossil fuel.    A hydrocarbon such as coal, petroleum or natural gas that may be used as a fuel.

        GW.    Gigawatts.

        Highwalls.    The unexcavated face of exposed overburden and coal in a surface mine.

        Incident rate or IR.    The rate of injury occurrence, as determined by the Mine Safety and Health Administration, or MSHA, based on 200,000 hours of employee exposure and calculated as follows:

IR = (number of cases × 200,000) / hours of employee exposure.

        LBA.    Lease by Application. Before a mining company can obtain new coal leases on federal land, the company must nominate lands for lease. The Bureau of Land Management, or BLM, then reviews the proposed tract to ensure maximum coal recovery. It also requires completion of a detailed environmental assessment or an environmental impact statement, and then schedules a competitive lease sale. Lease sales must meet fair market value. The process is known as Lease by Application. After a lease is awarded, the BLM also has the responsibility to assure development of the resource is conducted in a fashion that achieves maximum economic recovery.

        LBM.    Lease by Modification. A process of acquiring federal coal through a non-competitive leasing process. An LBM is used in circumstances where a lessee is seeking to modify an existing federal coal lease by adding less than 960 acres in a configuration that is deemed non-competitive to other coal operators.

        Lbs SO₂/mmBtu.    Pounds of sulfur dioxide emitted per million Btu of heat generated.

        Lignite.    The lowest rank of coal. It is brownish-black with a high moisture content commonly above 35% by weight and heating value commonly less than 8,000 Btu.

        LMU.    Logical Mining Unit. A combination of contiguous federal coal leases that allows the production of coal from any of the individual leases within the LMU to be used to meet the continuous operation requirements for the entire LMU.

        Metallurgical coal.    The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as "met" coal, it possesses four important qualities: volatility, which affects coke yield; the level of impurities, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Metallurgical coal has a particularly high Btu, but low ash content.

        MSHA.    Mine Safety and Health Administration.

        NAAQ.    National Ambient Air Quality.

        NO_x.    Nitrogen oxides. NO_x represents both nitrogen dioxide (NO₂) and nitrogen trioxide (NO₃) , which are gases formed in high temperature environments, such as coal combustion. It is a harmful pollutant that contributes to acid rain and is a precursor of ozone.

        Non-reserve coal deposits.    Non-reserve coal deposits are coal bearing bodies that have been sufficiently sampled and analyzed in trenches, outcrops, drilling and underground workings to assume continuity between sample points, and therefore warrant further exploration work. However, this coal does not qualify as commercially viable coal reserves as prescribed by the Securities and Exchange Commission, or SEC, standards until a final comprehensive evaluation based on unit cost per ton,

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recoverability and other material factors concludes legal and economic feasibility. Non-reserve coal deposits may be classified as such by either limited property control or geologic limitation, or both.

        QSO.    Qualified Surface Owner. A status attributed by the BLM to a certain class of surface owners of split estate lands which allows the QSO to prohibit leasing of federal coal without their explicit consent.

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

        PRB.    Powder River Basin. Coal producing area in northeastern Wyoming and southeastern Montana.

        Preparation plant.    Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process separates higher ash coal and may also remove some of the coal's sulfur content.

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

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

        Reclamation.    The process of restoring land to its prior condition, productive use or other permitted condition following mining activities. The process commonly includes "recontouring" or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and shrubs. Reclamation operations are typically conducted concurrently with mining operations. Reclamation is closely regulated by both state and federal laws.

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

        Riparian habitat.    Areas adjacent to rivers and streams with a differing density, diversity and productivity of plant and animal species relative to nearby uplands.

        Riverine habitat.    A habitat occurring along a river.

        Scrubber.    Any of several forms of chemical physical devices which operate to control sulfur compounds formed during coal combustion. An example of a scrubber is a flue gas desulfurization unit.

        SMCRA.    Surface Mining Control and Reclamation Act of 1977.

        Spoil-piles.    Pile used for any dumping of waste material or overburden material, particularly used during the dragline method of mining.

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

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        Sub-bituminous coal.    Black coal that ranks between lignite and bituminous coal. Sub-bituminous coal produced from the PRB has a moisture content between 20% to over 30% by weight, and its heat content ranges from 8,000 to 9,500 Btus.

        Sulfur.    One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide (SO₂) is produced as a gaseous by-product of coal combustion.

        Sulfur dioxide emission allowance.    A tradable authorization to emit sulfur dioxide. Under Title IV of the Clean Air Act, one allowance permits the emission of one ton of sulfur dioxide.

        Surface mine.    A mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil overburden. Surface mines are also known as open-pit mines.

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

        Truck-and-shovel mining and truck and front-end loader mining.    Similar forms of mining where large shovels or front-end loaders are used to remove overburden, which is used to backfill pits after the coal is removed. Smaller shovels load coal in haul trucks for transportation to the preparation plant or rail loading facilities.

        Union Pacific or UP.    Union Pacific Railroad.

Note: In this document, unless the context otherwise requires, references to:

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"Cloud Peak Energy," "we," "us," "our" or the "Company" refer collectively to Cloud Peak Energy Inc., a Delaware corporation, which was incorporated on July 31, 2008 in preparation for an initial public offering, and its consolidated subsidiary, CPE Resources, together with the businesses that CPE Resources operates;



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"CPE Resources" refers to Cloud Peak Energy Resources LLC, a Delaware limited liability company, formerly known as Rio Tinto Sage LLC, which is the operating company for our business, and of which Cloud Peak Energy Inc. is the managing member;



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"IPO Structuring Agreements" refers to the following agreements entered into in connection with our initial public offering: The master separation agreement, the acquisition agreement, the assignment agreement, the agency contract, the promissory note, the employee matters agreement, the escrow agreement, the CPE Resources limited liability company agreement, the management services agreement, registration rights agreement, the Rio Tinto Energy America coal supply agreement, the software license agreement, the tax receivable agreement, the trademark assignment agreement, the trademark license agreement, and the transition services agreement. For a description of our agreements with Rio Tinto and its affiliates, refer to the information included under the caption Certain Relationships and Related Transactions in our Proxy Statement to be distributed to our stockholders in connection with our 2010 annual meeting. We refer generally to the transactions we entered into in connection with these IPO Structuring Agreements as IPO structuring transactions or structuring transactions. See "Initial Public Offering and Related IPO Structuring Transactions" in Note 2 of Notes to Consolidated Financial Statements in Item 8; and



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"Rio Tinto" refers to Rio Tinto plc and Rio Tinto Limited and their direct and indirect subsidiaries, including Rio Tinto Energy America Inc. ("RTEA"), our predecessor for accounting purposes; Kennecott Management Services Company ("KMS"); and Rio Tinto America Inc. ("RTA"), which is the owner of RTEA and KMS.

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PART I

Item 1.    Business.

Overview

        Cloud Peak Energy Inc. is the third largest producer of coal in the U.S. and in the Powder River Basin, or PRB, based on our 2009 coal production of 93.3 million tons. We had revenues from our continuing operations of $1.40 billion in 2009. We operate some of the safest mines in the industry. According to Mine Safety and Health Administration, or MSHA, data, in 2009 we had the lowest employee all injury incident rate among the four largest U.S. coal producing companies. We operate solely in the PRB, the lowest cost coal producing region of the major coal producing regions in the U.S., and operate two of the four largest coal mines in the region and in the U.S. Our operations include three wholly-owned surface coal mines, two of which are in Wyoming and one of which is in Montana. We also own a 50% interest in a fourth surface coal mine in Montana. We produce sub-bituminous steam coal with low sulfur content and sell our coal primarily to domestic electric utilities, supplying approximately 70 customers with over 100 domestic plants. We do not produce any metallurgical coal. Steam coal is primarily consumed by electric utilities and industrial consumers as fuel for electricity generation. In 2009, the coal we produced generated approximately 4% of the electricity produced in the U.S. As of December 31, 2009, we controlled approximately 1.0 billion tons of proven and probable reserves.

        Cloud Peak Energy Inc., a Delaware corporation organized on July 31, 2008, is a holding company that manages its consolidated subsidiary CPE Resources, but has no business operations or material assets other than its ownership interest as of December 31, 2009 of approximately 51.7% of the common membership units in CPE Resources as discussed more fully in "History" below. Rio Tinto America indirectly holds the remaining 48.3% of CPE Resources' common membership units as of December 31, 2009. Our only source of cash flow from operations will be distributions from CPE Resources pursuant to the CPE Resources limited liability company agreement. We also receive management fees pursuant to a management services agreement between us and CPE Resources as reimbursement of certain administrative expenses.

History

        Our business operations are conducted by CPE Resources, formerly known as Rio Tinto Sage LLC, a Delaware limited liability company formed as a wholly-owned subsidiary of RTEA on August 19, 2008. RTEA is our predecessor for accounting purposes. RTEA, a Delaware corporation, formerly known as Kennecott Coal Company, was formed as a wholly-owned subsidiary of Rio Tinto America on March 1, 1993. Between 1993 and 1998, RTEA acquired the Antelope, Colowyo, Jacobs Ranch and Spring Creek coal mines and the Cordero and Caballo Rojo coal mines, which are operated together as the Cordero Rojo coal mine, and a 50% interest in the Decker coal mine, which is operated by a third-party mine operator. In December 2008, RTEA contributed Rio Tinto America's western U.S. coal business to CPE Resources (other than the Colowyo mine, which is now owned indirectly by Rio Tinto America). On October 1, 2009, CPE Resources sold the Jacobs Ranch mine to Arch Coal, Inc. and distributed the proceeds to Rio Tinto. On November 19, 2009, Cloud Peak Energy Inc. acquired from RTEA approximately 51.0% of the common membership units in CPE Resources in exchange for a promissory note and the SEC declared effective Cloud Peak Energy Inc.'s Registration Statement on Form S-1 (File No. 333-161293) for its initial public offering, or IPO. As a result of these transactions, Cloud Peak Energy Inc. became the sole managing member of CPE Resources with a controlling interest in CPE Resources and its subsidiaries. Cloud Peak Energy Inc. used the proceeds from the IPO to repay the promissory note upon the completion of our IPO on November 25, 2009.

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        The following condensed diagram depicts our organizational structure after our IPO:

Coal Characteristics

        In general, coal of all geological compositions is characterized by end use. Heat value and sulfur content are the most important variables in the profitable marketing and transportation of steam coal. We mine, process and market low sulfur content, sub-bituminous steam coal, the characteristics of which are described below. Because we operate only in the PRB, which does not have metallurgical coal, we produce only steam coal.

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Heat Value

        The heat value of coal is commonly measured in British thermal units, or "Btus." Sub-bituminous coal from the PRB has a typical heat value that ranges from 8,000 to 9,500 Btus. Sub-bituminous coal from the PRB is used primarily by electric utilities and by some industrial customers for steam generation. Coal found in other regions in the U.S., including the eastern and midwestern regions, tends to have a higher heat value than coal found in the PRB.

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-fired power plants can comply with sulfur dioxide emissions 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-reduction technology. PRB coal typically has a lower sulfur content than eastern U.S. coal and generally emits no greater than 0.8 pounds of sulfur dioxide per million Btus. All of our reserves are compliance coal under the Clean Air Act.

        Higher sulfur noncompliance coal can be burned in plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by up to 90%, and in facilities that blend compliance and noncompliance coal. In 2009, out of utilities with a coal generating capacity of approximately 315 GW, utilities accounting for a capacity of over 150 GW had been retrofitted with scrubbers. Furthermore, all new coal-fired generation plants built in the U.S. are expected to use some type of sulfur-reduction technology. The demand or price for lower sulfur coal may decrease with widespread implementation of sulfur-reduction technology.

Other

        Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, 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 ash content of PRB coals is generally low, representing approximately 5% to 10% by weight. The composition of the ash, including the proportion of sodium oxide, as well as the ash and fusion temperatures are important characteristics of coal and help determine the suitability of the coal to end users. In limited cases, customer requirements at the Spring Creek mine have required, and may continue to require, the addition of earthen materials to dilute the sodium oxide and ash of the coal.

        Moisture content of coal varies by the type of coal and the region where it is mined. In general, high moisture content is associated with lower heat values and generally makes the coal 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. PRB coals have typical moisture content of 25% to 35%.

        Trace elements within coal that are of primary concern are mercury, for health and environmental reasons, and chlorine, for utility plant performance. Trace elements of mercury and chlorine in PRB coal are relatively low compared to other coal regions. However, the low chlorine content of PRB coal is associated with the emission of elemental mercury, which is difficult to remove with conventional pollution control devices.

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Coal Mining Methods

Surface Mining

        All of our mines are surface mining operations utilizing both dragline and truck-and-shovel mining methods. Surface mining is used when coal is found relatively close to the surface. Surface mining typically involves the removal of topsoil, and drilling and blasting the overburden (earth and rock covering the coal) with explosives. The overburden is then removed with draglines. Trucks, shovels and dozers then remove the coal. The final step involves replacing the overburden and topsoil after the coal has been excavated, reestablishing vegetation and plant life into the natural habitat and making other changes designed to provide local community benefits. We typically recover 90% or more of the economic coal seam through in the mines we operate.

Coal Preparation and Blending

        Depending on coal quality and customer requirements, in almost all cases the coal from our mines is crushed and shipped directly from our mines to the customer. Typically, no other preparation is needed for a saleable product. However, depending on the specific quality characteristics of the coal and the needs of the customer, blending different types of coals may be required at the customer's plant. Coals of various sulfur and ash contents can be mixed or "blended" to meet the specific combustion and environmental needs of customers. All of our coal can be blended with coal from other coal producers. Spring Creek's location and the high Btu content of its coal make its coal better suited than our other products for export and transportation to the northeastern U.S. coal markets for blending by the customer with coal sourced from other markets to achieve a suitable overall product.

Mining Operations

        We operate solely in the PRB. Two of the mines we operate are located in Wyoming and one is located in Montana. We also own a 50% non-operating interest in the Decker mine, which is located in Montana and operated by a third-party mine operator. We currently own substantially all of the equipment utilized in our mining operations, excluding the Decker mine. We employ preventative maintenance and rebuild programs and upgrade our equipment as part of our efforts to ensure that it is productive, well-maintained and cost-competitive. Our maintenance programs also utilize procedures designed to enhance the efficiencies of our operations. The following table provides summary information regarding our mines as of December 31, 2009.

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        All of our operations utilize dragline and truck-and-shovel mining methods. Our Antelope and Cordero Rojo mines are served by the BNSF and UP railroads. Our Spring Creek mine and the Decker mine are served solely by the BNSF railroad.

        The following map shows the locations of our mining operations:

Antelope Mine

        The Antelope mine is located in the southern end of the PRB approximately 60 miles south of Gillette, Wyoming. The mine extracts steam coal from the Anderson and Canyon Seams, with up to 44 and 36 feet, respectively, in thickness. We have nominated as a Lease by Application, or LBA, a large coal tract adjacent to our existing operation. The Bureau of Land Management, or BLM, will determine if the tract will be leased, and if so, the final boundaries of, and the coal tonnage for, this tract. Acquisition of this tract would facilitate access to approximately 80 million tons of non-reserve coal deposits that we control. We currently expect the BLM will schedule this LBA for bid sometime in 2011. Other potential large areas of unleased coal north and west of the mine are available for nomination by us or other mining operations or persons.

Cordero Rojo Mine

        The Cordero Rojo mine is located approximately 25 miles south of Gillette, Wyoming. The mine extracts steam coal from the Wyodak Seam, which ranges from approximately 55 to 70 feet in thickness. We have nominated as an LBA a large coal tract adjacent to our existing operation, which

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we believe the BLM will schedule for lease sometime between 2011 and 2013 although we have recently requested that the BLM delay the sale of this lease until 2013. The BLM will determine if the tract will be leased, and if so, the final boundaries of, and the coal tonnage for, this tract. Significant areas of unleased coal are potentially available for nomination by us or other mining operations or persons adjacent to our current operations.

Spring Creek Mine

        The Spring Creek mine is located in Montana approximately 35 miles north of Sheridan, Wyoming. The mine extracts steam coal from the Anderson-Dietz Seam, which averages approximately 80 feet in thickness. The location of the mine relative to the Great Lakes is attractive to our customers in the northeast because of lower transportation costs. The location of the Spring Creek mine also provides access to the Westshore terminal near Vancouver, Canada, which is the main export terminal from the western U.S., providing an advantage relative to other PRB mines. As a result, interest from foreign buyers in coal from our Spring Creek mine continues, and, in 2009, we shipped over 1.6 million tons of Spring Creek coal through the Westshore terminal. We have nominated a Lease by Modification area adjacent to our existing operation containing additional non-reserve coal deposits. The BLM is currently reviewing the proposal.

Decker Mine

        The Decker mine is located immediately to the southeast of Spring Creek in Big Horn County, Montana. We own a non-operating 50% interest in the mine. The Decker mine is a unionized operation; however, we do not employ any of the Decker employees. A third-party operates the Decker mine for us and our joint venture partner and markets the steam coal out of the Decker mine. There are two principal seams at West Decker, Dietz 1 and Dietz 2, with typical thicknesses of 51 and 16 feet, respectively, and three seams at East Decker, Dietz 1 Upper, Dietz 1 Lower and Dietz 2, with typical thicknesses of 27, 17 and 16 feet, respectively.

Customers and Coal Contracts

        We focus on building long-term relationships with creditworthy customers through our reliable performance and commitment to customer service. We supply coal to over 50 electric utilities and over 80% of our sales were to customers with an investment grade credit rating as of December 31, 2009. Moreover, over 75% of our 2009 sales were to customers with whom we have had relationships for more than 10 years.

Sales and Marketing

        We have a team of experienced sales, marketing and customer service individuals. To help develop and maintain the relationships we have with our customers, we have divided the department into three teams:

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Sales and Marketing, which focuses on traditional requests for proposals, constituting the majority of our sales;



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Marketing and Pricing, which provides industry insight, recommends pricing strategies and participates in the spot market; and



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Customer Service, which provides contract and after-sales support to our customers.

As of December 31, 2009, we had 16 employees in our sales and marketing department.

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Customers

        Our primary customers are domestic utility companies with over 100 plants primarily located in the mid-west and south central U.S. Our coal supplies fueled approximately 4% of the electricity generated in the U.S. in 2009. During 2009, approximately 47% of our revenues were derived from our top ten customers. In 2009, NRG Texas Power LLC accounted for 10% of our revenues. No other customer accounted for 10% or more of our revenues in 2009. The following map shows the percentage of our shipped tons of coal by state of destination during 2009 from coal produced at the three mines we own and operate. We also exported approximately 3% of the tons produced at these mines in 2009.

Long-term Coal Sales Agreements

        As is customary in the coal industry, we generally enter into fixed price, fixed volume supply contracts of one- to five-year terms with many of our customers. Multiple year contracts usually have specific and possibly different volume and pricing arrangements for each year of the contract. As of December 31, 2009, approximately 6% of our committed tons were associated with contracts that had three years or more remaining on their term. Most 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 agreements that extend for a four- or five-year term or longer may include a variable pricing system. These contracts allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales price. For the year ended December 31, 2009, approximately 97% of our revenues were derived from long-term supply contracts with a term of one year or greater. While most of our sales contracts are for terms of one to five years, some are as short as one to six months, and other contracts have terms longer than ten years.

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        On January 6, 2010, we announced the buyout by the Decker mine of a coal contract. This contract accounted for approximately 30% of production at the Decker mine for 2010 and the majority of the production for 2011 and 2012. The Decker mine currently holds no firm sales contracts beyond 2011 and the most recent life of mine plans reviewed by the Decker management committee do not contain any coal sales beyond 2011 although the life of mine plan has historically changed from time to time at the Decker mine.

        Our coal is primarily sold on a mine-specific basis to utility customers through a request-for-proposal process. The terms of our coal sales agreements result from competitive bidding and extensive 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, impact of future regulatory changes, extension options, force majeure, termination, assignment and other provisions.

        Our supply contracts typically contain provisions to adjust the base price due to new statutes, ordinances or regulations 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.

        Price re-opener and index provisions, which can be either renegotiated or based on a fixed formula, are present in contracts covering approximately 40% of our total future tonnage commitments. These provisions may allow either 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 between a specified range of prices. In some 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, some of our contracts contain clauses which may allow customers to terminate the contract in the event of certain changes in environmental laws and regulations.

        Quality and volumes for the coal 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 quality of the coal. Some customers are allowed to vary the amount of coal taken under the contract. 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 ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Many of our contracts contain clauses which require us and our customers to maintain a certain level of creditworthiness or provide appropriate credit enhancement upon request. The failure to do so can result in a suspension of shipments under the contract.

        Our coal sales agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers during the duration of specified events beyond the control of the affected party, 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 generally provide that in the event a force majeure circumstance exceeds a certain time period (e.g., 60-90 days), the unaffected party may have the option to terminate the 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.

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        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 some of our contracts, we have a right of substitution, 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 delivered cost.

        Generally, under the terms of our coal sales agreements, we agree to indemnify or reimburse our customers for damage to their or their rail carrier's equipment while on our property, other than from their own negligence, and for damage to our customer's equipment due to non-coal materials being included with our coal before leaving our property.

Broker Sales and Third-Party Sources

        From time to time, we purchase coal through brokers to cover any shortfalls under our supply agreements and sell to brokers any excess produced coal.

        Our subsidiary, Spring Creek Coal LLC, is a party to a broker sales contract under which it had agreed to sell purchased coal to a wholesale power generation company. In 1978, our Spring Creek subsidiary entered into a long-term coal sales contract to underpin the establishment of the Spring Creek mine. When we acquired the Spring Creek mine in 1993, the contract had been amended to allow the mine to meet its delivery requirements from long-term purchase contracts entered into with two separate mines (one of which was the Jacobs Ranch mine which we subsequently acquired in 1998 and sold in 2009). Due to the nature of the broker sales contract and the market conditions at the time the respective agreements were all executed, our selling price for the coal is higher than our purchasing price. Under this contract, we sold approximately 6.8 million tons per year. Delivery commitments under this contract are substantially complete. This broker sales contract contributed $140.4 million of revenues in 2009. The expiration of this contract will negatively impact our future revenues and operating income. See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview."

        For delivery during the year ended December 31, 2009, we purchased 10.1 million tons through brokers and third-party sources.

Transportation

        Transportation can be one of the largest components of a purchaser's total cost. Coal used for domestic consumption is generally sold free on board (fob) at the mine or nearest loading facility, and the purchaser of the coal normally bears the transportation costs and risk of loss in the event of a problem. Most electric generators arrange long-term shipping contracts with rail or barge companies to assure stable delivery costs. Our mines are served by the BNSF and UP railways. In limited circumstances, we sell coal on a delivered basis where we arrange and pay for the freight and charge our customers on a cost plus basis for this service.

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 dragline shovel parts and services and tires. We believe adequate substitute suppliers are available. For further discussion of our suppliers, see Item 1A "Risk Factors—Risks Related to Our Business and Industry—

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Increases in the cost of raw materials and other industrial supplies, or the inability to obtain a sufficient quantity of those supplies, could increase our operating expenses, disrupt or delay our production and materially and adversely affect our profitability."

        We historically relied on various Rio Tinto supply contracts to obtain some of our key raw materials and consumables. Since our November 2009 IPO, we are not a party to any Rio Tinto supply contracts. While some of our heavy mobile equipment supplies and equipment are still being delivered under purchase orders entered into prior to our IPO, in particular certain heavy mobile equipment and tires, we have since entered into new supply contracts to replace the Rio Tinto supply contracts.

Competition

        The coal industry is highly competitive. We compete directly with all coal producers and indirectly with other energy producers throughout the U.S. The most important factors on which we compete with other coal producers are coal price, coal quality and characteristics, costs incurred by our customers to transport the coal, customer service and the reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry and international consumers. These coal consumption patterns are influenced by factors beyond our control, including the supply and demand for domestic and foreign electricity, domestic and foreign governmental regulations and taxes, environmental and other regulatory changes, technological developments, the price and availability of other fuels, such as natural gas and crude oil, and the availability, and subsidies designed to encourage greater use of, alternative energy sources, including hydroelectric, nuclear, wind and solar power, all of which can decrease demand for coal.

        Because most of the coal in the vicinity of our mines is owned by the U.S. federal government, we compete with other coal producers operating in the PRB for additional coal through the LBA process. This process is competitive and we expect the competition for LBAs to remain strong.

Employees

        As of December 31, 2009, we had 1,529 employees. None of our employees are currently parties to collective bargaining agreements. We hold a 50% interest in the Decker mine in Montana, which is a union-based operation operated by a third-party mine operator. However, we do not employ any of the Decker mine employees. We believe that we have good relations with our employees. As of December 31, 2009, we had 292 external contractors, on a full-time equivalent basis.

Executive Officers of the Company

        Set forth below is information concerning our current executive officers.

        Colin Marshall has served as our President, Chief Executive Officer and a director since July 2008. Previously, he served as the President and Chief Executive Officer of RTEA from June 2006 until November 2009. From March 2004 to May 2006, Mr. Marshall served as General Manager of Rio

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Tinto's Pilbara Iron's west Pilbara iron ore operations in Tom Price, West Australia, as General Manager of RTEA's Cordero Rojo mine in Wyoming from June 2001 to March 2004 and as Operations Manager of RTEA's Cordero Rojo mine from August 2000 to June 2001. Mr. Marshall worked for Rio Tinto plc in London as an analyst in the Business Evaluation Department from 1992 to 1996. From 1996 to 2000, he was Finance Director of Rio Tinto Pacific Coal business unit based in Brisbane Australia. Mr. Marshall received his bachelor's degree and his master's degree in mechanical engineering from Brunel University and his MBA from the London Business School.

        Michael Barrett has served as our Executive Vice President and Chief Financial Officer since September 2008. Previously, he served as Chief Financial Officer of RTEA from April 2007 until November 2009, and as Acting Chief Financial Officer of RTEA from January 2007 to March 2007. From November 2004 to April 2007, Mr. Barrett served as Director, Finance & Commercial Analysis of RTEA, and as Principal Business Analyst of Rio Tinto Iron Ore's new business development group from December 2001 to November 2004. From May 1997 to May 2000, Mr. Barrett worked as a Senior Business Analyst for WMC Resources Ltd, a mining company, and was Chief Financial Officer and Finance Director of Medtech Ltd. and Auxcis Ltd., two technology companies listed on the Australian stock exchange, from May 2000 to December 2001. From August 1991 to May 1997, he held positions with PricewaterhouseCoopers in England and Australia. Mr. Barrett received his bachelor's degree with joint honors in economics and accounting from Southampton University and is a Chartered Accountant.

        Gary Rivenes has served as our Executive Vice President and Chief Operating Officer since October 2009. Previously, he served as Vice President, Operations, of RTEA from December 2008 until November 2009, and as Acting Vice President, Operations, of RTEA from January 2008 to November 2008. From September 2007 to December 2007, Mr. Rivenes was General Manager for RTEA's Jacobs Ranch mine and RTEA's Antelope mine from October 2006 to September 2007 and served as Manager, Mine Operations for RTEA's Antelope mine from November 2003 to September 2006. Prior to that, he worked for RTEA in a variety of operational and technical positions for RTEA's Antelope, Colowyo and Jacobs Ranch mines for 17 years. Mr. Rivenes holds a bachelor of science in mining engineering from Montana College of Mineral, Science & Technology.

        Cary W. Martin has served as our Senior Vice President of Human Resources since October 2009. Previously, he served as Vice President / Corporate Officer of Human Resources for OGE Energy Corp., an electric utility and natural gas processing holding company from September 2006 until March 2008, and as a Segment Vice President for several different divisions of SPX Corporation, an international multi-industry manufacturing and services company from December 1999 until May 2006. From 1982 until 1999, Mr. Martin served in various management and officer positions for industries ranging from medical facilities to cable manufacturers. Mr. Martin received his bachelor's degree in Business Administration from the University of Missouri and his master's degree in Management Sciences from St. Louis University.

        James Orchard has served as our Senior Vice President, Marketing and Government Affairs since October 2009. Previously, he served as Vice President, Marketing and Sustainable Development for RTEA from March 2008 until November 2009. From January 2005 to March 2008, Mr. Orchard was director of customer service for RTEA. Prior to that he worked for Rio Tinto's Aluminum division in Australia and New Zealand for over 17 years, where he held a number of technical, operating, process improvement and marketing positions, including as manager of metal products from January 2001 to January 2005. Mr. Orchard graduated from the University of New South Wales with a BSc and a PhD in industrial chemistry.

        Bryan Pechersky has served as our Senior Vice President and General Counsel since January 2010. Previously, Mr. Pechersky was Senior Vice President, General Counsel and Secretary for Harte-Hanks, Inc., a worldwide, direct and targeted marketing company from March 2007 until January 2010.

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Prior to that, he also served as Senior Vice President, Secretary and Senior Corporate Counsel for Blockbuster Inc., a global movie and game entertainment retailer from October 2005 until March 2007, and from March 2004 until October 2005 was Deputy General Counsel and Secretary for Unocal Corporation, an international energy company acquired by Chevron Corporation in 2005. Mr. Pechersky was in private practice for approximately seven years with the international law firm Vinson & Elkins LLP before joining Unocal Corporation. Mr. Pechersky also served as a Law Clerk to the Hon. Loretta A. Preska, Chief Judge of the U.S. District Court for the Southern District of New York in 1995 and 1996. Mr. Pechersky earned his bachelor's degree and Juris Doctorate from the University of Texas, Austin, Texas.

        A. Nick Taylor has served as our Senior Vice President, Technical Services since October 2009. Previously, he served as RTEA's Vice President of Technical Services & Business Improvement Process from October 2005 until November 2009. Prior to that, Mr. Taylor worked for Rio Tinto Technical Services in Sydney providing advice to Rio Tinto mining operations worldwide from 1992 to 2005, at its Bougainville Copper operations in New Guinea from 1980 to 1981, and at its Rossing Uranium operations in Namibia from 1976 to 1980. Additionally, he worked for Nchanga Consolidated Copper Mines in Zambia from 1973 to 1976, and as a mining consultant in Australia between 1981 and 1992. Mr. Taylor graduated from the University of Wales with a bachelor of science degree in Mineral Exploitation.

        Terri Eggert has served as our Vice President of Finance since September 2009 and our Chief Accounting Officer since March 2010. Previously, she served as Assistant Controller from January 2007 until July 2009 for Ball Corporation, a supplier of high-quality metal and plastic packaging for beverage, food and household products customers, and of aerospace and other technologies and services. Prior to that, Ms. Eggert worked for Molson Coors Brewing Company as its Director of Accounting Processes from June 2001 until January 2007 and as its Director of Corporate Accounting from June 1997 through June 2001 and Manager of Technical Accounting from December 1996 until June 1997. Ms. Eggert worked for the accounting firms Deloitte & Touche and KPMG prior to joining Molson Coors Brewing Company. Ms. Eggert received her bachelor's degree in Accounting from the University of Wyoming and is a certified public accountant.

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, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment and the effects of mining on surface and groundwater quality and availability. These laws and regulations have had, and will continue to have, a significant effect on our production costs and our competitive position. 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 of which we cannot predict. Future laws, regulations or orders, including those dealing with climate change, 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.

        We are committed to conducting our mining operations in compliance with all applicable federal, state and local laws and regulations. Our industry is highly regulated and the laws and regulations which apply to our operations are extensive. We have procedures in place which are designed to allow us to comply in this extremely regulated environment, and we believe that we are substantially in compliance with applicable laws and regulations. We cannot, however, assure that we have been or will be at all times in complete compliance.

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Mining Permits and Approvals

        Numerous governmental permits or approvals are required for mining operations. When we apply for these permits and approvals, we may be required to prepare and present data to federal, state or local authorities 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, or EIS, must be prepared to assist the BLM in determining the potential environmental impact of lease issuance, including any direct and indirect effects from the mining, transportation and burning of coal. Recently, particular attention has been focused on the effects of coal on climate change, which has resulted in extensive comments from environmental groups on the EIS prepared in connection with one of our federal mining lease applications. This may result in further delays or an inability to obtain this lease, and future lease applications may also be subject to these delays or difficulties in obtaining other leases. 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.

        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, productive use or other permitted condition. Typically, we submit the necessary permit applications several months or even years before we plan to begin mining a new area.

        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, or SMCRA, establishes mining, environmental protection, reclamation and closure standards for all aspects of surface coal mining. Mining operators must obtain SMCRA permits and permit renewals from the Office of Surface Mining, or the 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 stringent than the federal mining regulatory program under SMCRA. Both Wyoming and Montana, where our mines are located, have achieved primacy to administer the SMCRA program.

        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, surface runoff and drainage control, establishment of suitable post mining land uses and re-vegetation. 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 typically 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 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

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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 SMCRA 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 two years to prepare and review, depending on the size and complexity of the mine, and another 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, imposes 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. In 2009, we recorded $28.7 million of expense related to these reclamation fees.

Surety Bonds

        State laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. The costs of surety bonds have fluctuated in recent years, and the market terms of these 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. We and some other mine operators have therefore used letters of credit to secure the performance of a portion of our reclamation obligations. Prior to our IPO, Rio Tinto served as guarantor of our surety bonds, and our letters of credit were issued under Rio Tinto's pre-existing credit facilities. We have obtained new surety bonds, letters of credit or other credit arrangements and have obtained the full release of Rio Tinto and its affiliates with respect to any existing surety bonds, letters of credit and other guarantees or credit arrangements.

        As of December 31, 2009, there were approximately $549.2 million in surety bonds and letters of credit outstanding to secure the performance of our reclamation obligations (including our obligations with respect to the Decker mine).

Mine Safety and Health

        Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977, or the Mine Act, significantly expanded the enforcement of safety and health standards and imposed 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 state programs for mine safety and health regulation and

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enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive and pervasive systems for protection of employee health and safety affecting any segment of U.S. industry. The Mine Act is a strict liability statute that requires mandatory inspections of surface and underground coal mines and requires the issuance of enforcement action when it is believed that a standard has been violated. A penalty is required to be imposed for each cited violation. Negligence and gravity assessments result in a cumulative enforcement scheme that may result in the issuance of withdrawal orders. The Mine Act contains criminal liability provisions. For example, it imposes criminal liability for corporate operators who knowingly or willfully authorize, order or carry out violations. The Mine Act also provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly authorize, order or carry out violations. In addition, criminal liability may be imposed against any person for knowingly falsifying records required to be kept under the Mine Act and standards. In reaction to recent underground mine accidents, state and federal legislatures and regulatory authorities have increased scrutiny of mine safety matters and passed more stringent laws governing mining. For example, in 2006, Congress enacted the Mine Improvement and New Emergency Response Act, or MINER Act, which imposed additional burdens on coal operators, including, among other matters, (i) obligations related to (a) the 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; (b) establishing additional requirements for mine rescue teams; and (c) promptly notifying federal authorities of incidents that pose a reasonable risk of death and (ii) increased penalties for violations of the applicable federal laws and regulations. The penalty regulations promulgated in 2007 as a result of this legislation included new heightened penalty categories for certain types of violations and have resulted in imposition of penalty assessment amounts that doubled between fiscal year 2007 and 2008 in the coal industry and are expected to continue to increase. In the wake of the 2006 legislation, enforcement scrutiny also increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions. Various states also have enacted their own new laws and regulations addressing many of these same subjects.

        We have implemented various internal standards to promote employee health and safety. In addition to these internal standards, we are also Occupational Health and Safety Assessment Series 18001 certified and have voluntarily implemented policies and standards in addition to those required by state or federal regulations that we consider important to the health and safety of our employees. According to MSHA, in 2009 we had the lowest employee all injury incident rate among the five largest U.S. coal producing companies.

        Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must pay federal black lung benefits to claimants who are current and former employees and also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to January 1, 1970. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the U.S. In 2009, we recorded $41.8 million of expense related to this excise tax.

Clean Air Act

        The federal Clean Air Act and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emission control requirements relating to particulate matter, which may include controlling fugitive dust. The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired power plants. In recent years, Congress has

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considered legislation that would require increased reductions in emissions of sulfur dioxide, nitrogen oxide and mercury. In addition to greenhouse gas issues discussed below, the air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the following:

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Acid Rain.  Title IV of the Clean Air Act requires reductions of sulfur dioxide emissions by electric utilities. Affected power plants have sought to reduce sulfur dioxide emissions by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading sulfur dioxide emission allowances. We cannot accurately predict the future effect of these Clean Air Act provisions on our operations.



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Particulate Matter.  The Clean Air Act requires the U.S. Environmental Protection Agency, or EPA, to set standards, referred to as National Ambient Air Quality Standards, or NAAQS, for certain pollutants. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. For example, NAAQS have been issued for coarse particulate matter with an aerodynamic diameter less than or equal to 10 microns, or PM₁₀, and for fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns, or PM_2.5. In 2004, 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 PM_2.5 NAAQS. Individual states were required to identify the sources of emissions and submit emission reduction plans by 2008. These plans could be state-specific or regional in scope. Under the Clean Air Act, individual states have until 2010 with possible extensions to 2015 to secure emissions reductions from sources contributing to the problem and achieve attainment of the standards. None of our operations are currently located in non-attainment areas for PM_2.5 that were designated in 2004. New, more stringent NAAQS for PM_2.5 and PM₁₀ were promulgated in 2006. In February 2009, the U.S. Court of Appeals for the District of Columbia Circuit upheld the 2006 PM₁₀ NAAQS, but remanded the 2006 PM_2.5 NAAQS to the EPA. The 2006 PM_2.5 NAAQS remain in effect pending either the promulgation of a new NAAQS or an adequate justification of the 2006 PM_2.5 NAAQS by the EPA. Any new PM_2.5 NAAQS may be more stringent than the 2006 version. In November 2009, the EPA designated non-attainment areas for the revised PM_2.5 NAAQS adopted in 2006. State emission reduction plans for achieving the revised standards are due in 2012 and attainment must be achieved between 2014 and 2019. Meeting the 2006 PM_2.5 NAAQS or any new version may require reductions of nitrogen oxide and sulfur dioxide emissions that are separate and distinct from the reductions that may, in addition to requiring reductions of PM_2.5 emissions, be required under any other program. Although our operations are not currently located in non-attainment areas, enforcement of the 2006 PM_2.5 NAAQS or the promulgation of any new standard will affect many power plants, especially coal-fired plants in non-attainment areas; however, we are unable to predict the magnitude of the impact on the demand for, or price of, lower sulfur coals from the PRB. In addition, it is possible that the 2006 PM_2.5 NAAQS or any new standard will directly impact our mining operations by, for example, requiring additional controls of emissions from our mining equipment and vehicles. Moreover, if the areas in which our mines and coal preparation plants are located suffer from extreme weather events such as droughts, or are designated as non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development. In addition, in October 2009 the EPA revised emission limits for coal preparation plants. These revised limits include more stringent and additional particulate matter emissions limits for certain plants constructed, reconstructed or modified after April 28, 2008, and new emission limits for sulfur dioxide, nitrogen dioxide and carbon monoxide from certain equipment constructed, reconstructed or modified after May 27, 2009. We do not know whether or to what extent the revised limits might have a negative impact on our customers or adversely affect the demand for coal.

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Ozone.  The EPA issued revised ozone NAAQS imposing more stringent limits that took effect in May 2008. Nitrogen oxides, which are a by-product of coal combustion, are classified as an ozone precursor. Under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants. Attainment dates for the new standards range between 2013 and 2030, depending on the severity of the non-attainment. In July 2009, the U.S. Court of Appeals for the District of Columbia vacated part of a rule implementing the ozone NAAQs and remanded certain other aspects of the rule to the EPA for further consideration. Notwithstanding the decision, we expect that additional emissions control requirements may be imposed on new and expanded coal-fired power plants and industrial boilers in the years ahead. The combination of these actions may impact demand for coal nationally, but we are unable to predict the magnitude of the impact. In January 2010, the EPA proposed to adopt even more stringent primary NAAQS for ozone, between the range of 60-70 parts per billion (compared with the 75 parts per billion standard adopted in 2008). Stringent secondary standards to protect plant life also were proposed. The EPA intends to finalize new standards by August 2010; non-attainment designations will be made by August 2011; state plans to implement the standards will be due by the end of 2013; and attainment of the standards must be achieved between 2014 and 2031, depending on the severity of the problem.



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NAAQS for Other Pollutants.  In December 2009, the EPA proposed to adopt a more stringent revised NAAQS for sulfur dioxide. For the first time, a 1-hour standard has been proposed at a level between 50 and 100 parts per billion. The EPA proposes to repeal the existing 24-hour standard and annual NAAQS for sulfur dioxide. The EPA intends to finalize the rule in June 2010. Non-attainment designations would be finalized by June 2012; state implementation plans would be due in the winter of 2014; and the deadline to achieve attainment would be the summer of 2017. We do not know whether or to what extent these developments might affect our operations.



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In January 2010, the EPA announced adoption of a revised NAAQS for nitrogen dioxide. For the first time, the EPA has adopted a 1-hour standard, as well as the existing annual standard. Initial designations of non-attainment areas will be made by January 2012, with additional designations in 2016-2017 based on further monitoring of ambient levels of nitrogen dioxide. EPA estimates the target date for attainment of the new standard will be between 2021-2022. We do not know whether or to what extent these developments might affect our operations.



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NO_x SIP Call.  The NO_x SIP Call program was established by the EPA in October 1998 to reduce the transport of nitrogen oxide and ozone on prevailing winds from the Midwest and South to states in the Northeast, which alleged that they could not meet federal air quality standards because of migrating pollution. The program is designed to reduce nitrogen oxide emissions by one million tons per year in 22 eastern states and the District of Columbia. 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-fired power plants, potentially making coal a less attractive fuel.



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Clean Air Interstate Rule.  The EPA's Clean Air Interstate Rule, or CAIR, calls for power plants in 28 eastern states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system now in effect for acid rain. In July 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR in its entirety and directed the EPA to commence new rule-making. After a petition for rehearing, the court ruled in December 2008 that to completely vacate CAIR would sacrifice public health and environmental benefits and that CAIR should remain in effect while the EPA modifies the rule. It is uncertain how the EPA will proceed to modify CAIR, although the EPA has indicated that it intends to propose a replacement rule in early 2010 and to issue a final rule

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by early 2011. Under CAIR and any replacement rule with similarly stringent caps, some coal-fired power plants might be required to install additional pollution control equipment, such as scrubbers, which could lead scrubbed plants to become less sensitive to the sulfur content of coal and more sensitive to delivered price, thereby potentially decreasing the demand for low-sulfur coal at these plants and reducing market prices for low-sulfur coal.

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Mercury.  In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the EPA's Clean Air Mercury Rule, or CAMR, which had established a cap-and-trade program to reduce mercury emissions from power plants. At present, there are no federal regulations that require monitoring and reduction of mercury emissions at existing power plants, and regulations that were promulgated under the CAMR framework in several states have been invalidated. As a result of the decision to vacate the CAMR, the EPA is gathering information from coal-fired power plants regarding emissions of mercury and other hazardous air pollutants for the purpose of developing Maximum Achievable Control Technology standards, or MACT, for hazardous air pollutants from coal-fired power plants. The MACT limits for mercury are likely to be stricter than the vacated CAMR. The EPA is under a court deadline to issue a final rule requiring MACT for power plants by November 2011. In the meantime, case-by-case MACT determinations for mercury and possibly other hazardous air pollutants may be required for new and reconstructed coal-fired power plants. We are unable to predict the impact of any future MACT standard for mercury or other hazardous air pollutants on the demand for, or the price of, our low-sulfur coal. Apart from CAMR, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed. The Obama Administration has also indicated a desire to begin negotiations on an international treaty to reduce mercury pollution. Regulation of mercury emissions by the EPA, states, Congress or pursuant to an international treaty may decrease the future demand for coal, but we are currently unable to predict the magnitude of any such effect.



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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. This program may result in additional emissions restrictions from new coal-fired power plants whose operations may impair visibility at and around federally protected areas. This program may also require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could negatively affect the future market for coal.



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New Source Review.  A number of pending regulatory changes, court actions and administrative actions may affect the scope and application of the EPA's new source review program, which under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install the more stringent air emissions control equipment required of new plants. The changes to the new source review program may negatively 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.

Climate Change

        One by-product of burning coal is carbon dioxide, which is considered a greenhouse gas and is a major source of public concern with respect to climate change and global warming. In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for greenhouse gases, became binding on all those countries that had ratified it. To date, the U.S. has refused to ratify the Kyoto Protocol, which expires in 2012. Emission targets under the Kyoto Protocol vary from country to country. If the U.S. were to ratify the Kyoto Protocol, the U.S. would be required to reduce greenhouse gas emissions to 93% of 1990 levels from

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2008 to 2012. International discussions are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012, with an initial goal of reaching a consensus on a replacement treaty at a milestone meeting in Copenhagen, Denmark in December 2009. The Copenhagen meeting did not result in a new treaty, but did result in an "agreement in principle," which would entail the U.S. reducing CO₂ emissions on a voluntary basis by at least 17% by 2020, and greater percentages in succeeding years. Any replacement treaty or other international arrangement requiring additional reductions in greenhouse gas emissions could have a negative global impact on the demand for coal.

        Future regulation of greenhouse gases in the U.S. could occur pursuant to future U.S. treaty commitments, new domestic legislation that may impose a carbon emissions tax or establish a cap-and-trade program or regulation by the EPA. The Obama Administration has indicated its support for a mandatory cap-and-trade program to reduce greenhouse gas emissions and the U.S. Congress is actively considering various proposals to reduce greenhouse gas emissions, mandate electricity suppliers to use renewable energy sources to generate a certain percentage of power, and require energy efficiency measures. In June 2009, the U.S. House of Representatives passed a comprehensive climate change and energy bill, the American Clean Energy and Security Act, and the U.S. Senate is now considering similar legislation that would, among other things, impose a nationwide cap on greenhouse gas emissions and require major sources, including coal-fired power plants, to obtain "allowances" to meet that cap. Passage of such comprehensive climate change and energy legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American 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.

        Even in the absence of new federal legislation, greenhouse gas emissions may be regulated in the future by the EPA pursuant to the Clean Air Act. In response to the 2007 U.S. Supreme Court ruling Massachusetts v. EPA that the EPA has authority to regulate carbon dioxide emissions under the Clean Air Act, the EPA has taken several steps towards implementing regulations regarding the emission of greenhouse gases. In April 2009, the EPA issued a proposed finding that carbon dioxide and certain other greenhouse gases emitted by motor vehicles endanger public health and the environment. EPA finalized that "Endangerment Finding" in December 2009. In October 2009, the EPA also published a proposed rule that makes it clear that the EPA anticipates regulating the emission of greenhouse gases from certain stationary sources with an initial focus on facilities that release more than 25,000 tons of greenhouse gases a year, and which would require best available control technology for greenhouse gas emissions whenever such facilities are built or significantly modified. If the EPA were to set emission limits for carbon dioxide from electric utilities, the amount of coal our customers purchase from us could decrease. Moreover, in September 2009, the EPA promulgated a rule requiring certain emitters of greenhouse gases, including coal-fired power plants, to monitor and report their greenhouse gas emissions to the EPA. Taken together, the various EPA regulatory actions based on the Endangerment Finding have the potential to ripple through federal and state air quality laws and regulations, imposing additional costs and regulatory obstacles on the mining, transport and use of coal.

        Many states and regions have adopted greenhouse gas initiatives and certain governmental bodies, including the State of California, have or are considering the imposition of fees or taxes based on the emission of greenhouse gases by certain facilities. In December 2005, seven northeastern states (Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York, and Vermont) signed the Regional Greenhouse Gas Initiative agreement, or RGGI, calling for implementation of a cap-and-trade program by 2009 aimed at reducing carbon dioxide emissions from power plants in the participating states. The RGGI program calls for signatory states to stabilize carbon dioxide emissions to current levels from 2009 to 2015, followed by a 2.5% reduction each year from 2015 through 2018. Since its inception, several additional northeastern states and Canadian provinces have joined as participants or observers. RGGI has begun holding quarterly carbon dioxide allowance auctions for its

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initial three-year compliance period from January 1, 2009 to December 31, 2011 to allow utilities to buy allowances to cover their carbon dioxide emissions.

        Climate change initiatives are also being considered or enacted in some western states. In September 2006, California enacted the Global Warming Solutions Act of 2006, which establishes a statewide greenhouse gas emissions cap of 1990 levels by 2020 and sets a framework for further reductions after 2020. In September 2006, California also adopted greenhouse gas legislation that prohibits long-term baseload generators from having a greenhouse gas emissions rate greater than that of combined cycle natural gas generator. In February 2007, the governors of Arizona, California, New Mexico, Oregon and Washington launched the Western Climate Initiative in an effort to develop a regional strategy for addressing climate change. The goal of the Western Climate Initiative is to identify, evaluate and implement collective and cooperative methods of reducing greenhouse gases in the region to 15% below 2005 levels by 2020. Since its initial launching, a number of additional western states and provinces have joined the initiative, or have agreed to participate as observers, including Montana, which has joined the initiative and Wyoming, which has signed on as an observer. The proposed scope of the cap-and-trade program pursuant to the Western Climate Initiative include fossil fuels (such as coal) production and processing. Thus, our coal mines could incur direct costs if new laws are passed in Montana and Wyoming in accordance with the Western Climate Initiative.

        Midwestern states have also adopted initiatives to reduce and monitor greenhouse gas emissions. In November 2007, the governors of Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Ohio, South Dakota and Wisconsin and the premier of Manitoba signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions. The draft recommendations, released in June 2009, call for a 20% reduction below 2005 emissions levels by 2020 and additional reductions to 80% below 2005 emissions levels by 2080.

        Additionally, two U.S. federal appeals courts have reinstated lawsuits permitting individuals, state attorneys general and others to pursue claims against major utility, coal, oil and chemical companies on the basis that those companies have created a public or private nuisance due to their emissions of carbon dioxide, including such damages as the effects of Hurricane Katrina.

        These and other current or future climate change rules have required, and rules, court orders or other legally enforceable mechanisms may in the future require, additional controls on coal-fired 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, or future court orders or other legally enforceable mechanisms, will not adversely affect the future market for coal in those regions. The permitting of new coal-fired power plants has also recently been contested by some state regulators and environmental organizations based on concerns relating to greenhouse gas emissions. Recently, the EPA has required that states and companies considering coal-fired plants evaluate the use of natural gas instead. Increased efforts to control greenhouse gas emissions could result in reduced demand for coal. If mandatory restrictions on carbon dioxide emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of carbon capture and storage technology have been proposed or enacted. For example, the U.S. Department of Energy announced in May 2009 that it would provide $2.4 billion of federal stimulus funds under the American Recovery and Reinvestment Act of 2009, or ARRA, to expand and accelerate the commercial deployment of large-scaled carbon capture and storage technology. However, there can be no assurances that cost-effective carbon capture and storage technology will become commercially feasible in the near future or at all.

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        Even in the absence of comprehensive federal or state legislation on greenhouse gas emissions, climate change has increasingly become an issue that must be addressed in connection with the preparation of EISs necessary to obtain additional federal coal leases. We have recently received extensive comments from several environmental groups pertaining to the extent of climate change discussion that should be included within the EIS document for the federal coal lease application pending for one of our mines. We worked in cooperation with the BLM's consultant to adequately address these concerns for the final EIS document, which was published in December 2008, and we continue to work with the BLM to make sure subsequent comments that were received upon publication of the final EIS are addressed in the pending record of decision. It is possible that in the future we may be unable to obtain future coal leases on a timely basis, which could have an adverse impact on our business.

Clean Water Act

        The federal Clean Water Act, or CWA, and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the U.S. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. Legislation that seeks to clarify the scope of CWA jurisdiction is under consideration by Congress. Recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease the cost and time we expend on CWA compliance.

        CWA requirements that may directly or indirectly affect our operations include the following:

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Wastewater Discharge.  Section 402 of the CWA 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, or NPDES, and corresponding programs implemented by state regulatory agencies. 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 U.S. 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. Furthermore, the imposition of future restrictions on the discharge of certain pollutants into waters of the U.S. 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, or 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 and costs of operations.

The CWA 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 cost, time and difficulty associated with obtaining and complying with NPDES permits.

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Dredge and Fill Permits.  Many mining activities, including the development of settling ponds and other impoundments, may result in impacts to waters of the U.S., including wetlands, streams and certain man-made conveyances with hydrologic connections to such streams or wetlands. Under the CWA, coal companies are required to obtain a Section 404 permit from the Army Corps of Engineers, or the Corps, prior to conducting such mining activities. In Coeur Alaska Inc. v. Southeast Alaska Conservation Council, the U.S. Supreme Court held that the Section 402 and Section 404 permitting programs are mutually exclusive, such that if fill material is discharged into waters of the U.S. under a Section 404 permit, a Section 402 permit for the same discharge is not required. The Corps is authorized to issue general "nationwide" permits for specific categories of activities that are similar in nature and that are determined to have minimal adverse effects on the environment. Permits issued pursuant to Nationwide Permit 21, or NWP 21, generally authorize the disposal of dredged or fill material from surface coal mining activities into waters of the U.S., subject to certain restrictions. Since March 2007, permits under NWP 21 were reissued for a five-year period with new provisions intended to strengthen environmental protections. There must be appropriate mitigation in accordance with nationwide general permit conditions rather than less restrictive state-required mitigation requirements, and permit-holders must receive explicit authorization from the Corps before proceeding with proposed mining activities. We currently utilize NWP 21 authorizations for our operations in Wyoming and Montana.

The Corps, the EPA and the Department of the Interior have announced an interagency action plan designed to reduce the harmful environmental consequences of mountaintop mining in the Appalachian region. As part of this interagency action plan, in July 2009 the Corps proposed to suspend and modify NWP 21 in six Appalachian region states to prohibit its use to authorize discharges of fill material into waters of the U.S. for mountaintop mining. In addition non-governmental organizations have filed lawsuits challenging the Corps' use of NWP 21 to authorize mountaintop mining, although a Kentucky state court decision stayed at least one such challenge due to the proposed suspension of NWP 21 described above. We do not practice mountaintop mining; we have no operations in the jurisdictions where these lawsuits were filed; and we have no operations in the states that may be affected by the proposed suspension and modification of NWP 21. However, decisions that restrict the issuance of permits pursuant to NWP 21, similar lawsuits that may be filed in jurisdictions where we operate, or suspensions or modifications of NWP 21 in the states where we operate could restrict our ability to utilize NWP 21 authorizations in the future. Additionally, while it is unknown precisely what other future changes will be implemented as a result of the interagency action plan, any future changes could further restrict our ability to obtain other new permits or to maintain existing permits.

The geographic extent of the Corps' regulatory jurisdiction over waters of the U.S. is likewise subject to legal uncertainty that may affect NWP 21 permitting as applied to our operations. On June 5, 2007, in response to the U.S. Supreme Court's divided decision in Rapanos v. United States, the Corps and the EPA issued joint regulatory guidance interpreting the extent of jurisdiction under Section 404 of the CWA and issued revised guidance on December 2, 2008. Specifically, the guidance differentiates between waters where the agencies will categorically assert jurisdiction, and waters where the agencies will assert jurisdiction on a case-by-case basis after a fact-specific "significant nexus analysis." Waters that are subject to the significant nexus analysis include non-navigable tributaries that do not have relatively permanent flow, wetlands adjacent to non-navigable tributaries that are not relatively permanent, and wetlands adjacent to but that do not directly abut a relatively permanent non-navigable tributary. We have applied for revised jurisdictional wetland determinations for certain of our mines in Wyoming and Montana. A Preliminary Jurisdictional Determination was completed on April 22, 2009 for our Antelope coal mine, finding that there may be waters of the U.S. on the subject project site. We accepted the Preliminary Jurisdictional Determination by letter dated July 8, 2009. The Corps' decisions

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on our other applications are currently pending. Until all jurisdictional determinations are resolved, our affected mines continue to operate under their old NWP 21 permits. We believe that the pending jurisdictional wetland determinations are likely to reduce the waters that are currently subject to NWP 21 permitting requirements, with concomitant decreases in the cost and time burdens associated with NWP 21 permit compliance.

Resource Conservation and Recovery Act

        The EPA determined that coal combustion wastes do not warrant regulation as hazardous wastes under the Resource Conservation and Recovery Act, or RCRA, in May 2000. Most state hazardous waste laws also regulate coal combustion wastes as non-hazardous wastes. The EPA also concluded that beneficial uses of coal combustion wastes, other than for mine-filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as mine-fill. There have been several legislative proposals that would require the EPA to further regulate the storage of coal combustion waste. In response, the EPA has stated that proposed regulations for management of coal combustion wastes by electric utilities will be issued in the future. Any significant changes in the management of coal combustion waste could increase our customers' operating costs and potentially reduce their ability to purchase coal. In addition, the EPA announced in 2009 that it will consider whether to reclassify by-products of coal combustion as hazardous waste. If coal combustion wastes were re-classified as hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers' operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of coal combustion waste, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

Comprehensive Environmental Response, Compensation and Liability Act

        The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances into the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on hazardous substance generators, site owners, transporters, lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA currently 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 CERCLA or similar state laws. Thus, we may be subject to liability under CERCLA and similar state laws for coal mines that we currently own, lease or operate or that we or our predecessors have previously owned, leased or operated, and sites to which we or our predecessors sent hazardous substances. We may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination and natural resource damages at sites where we control surface rights.

Endangered Species Act

        The federal Endangered Species Act, or ESA, and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service, or USFWS, works closely with the Office of Surface Mining, or OSM, and state regulatory agencies to ensure that species subject to the ESA are protected from mining-related impacts. A number of species indigenous to the areas in which we operate are protected under the ESA, and compliance with ESA requirements could have the

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effect of prohibiting or delaying us from obtaining mining permits. These requirements may also include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. For example, our Spring Creek coal mine applied for lease modification under the BLM leasing regulations, and the area we were proposing to include was declared critical greater sage-grouse habitat by the Montana Fish, Wildlife and Parks Department. This requires a certain degree of mitigation of the impacts on the habitat in order for us to obtain approval of this lease modification. Should more stringent protective measures be applied, or if the USFWS lists the sage grouse as threatened or endangered, this could result in increased operating costs, heightened difficulty in obtaining future mining permits, or the need to implement additional mitigation measures. The USFWS published the result of its 12-month status review on March 5, 2010, determining that a listing is warranted but precluded by higher priority listing actions. We have not determined its impact on our operations, if any.

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 regulatory requirements. 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) are required to 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 a site security plan will be required. It is possible that our use of explosives in connection with blasting operations may subject us to the Department of Homeland Security's new chemical facility security regulatory program.

Other Environmental Laws

        We are required to comply with numerous other federal, state and local environmental laws and regulations 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.

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, or SEC. You may access and read our filings without charge through the SEC's website at www.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 our website, www.cloudpeakenergy.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 (303) 713-5000 or by mail at Cloud Peak Energy Inc., 8051 East Maplewood Avenue, Greenwood Village, Colorado 80111, Attention: Vice President, Investor Relations. The information on our website is not part of this Annual Report on Form 10-K.

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Item 1A.    Risk Factors.

        You should carefully consider the risk factors described below and other information contained in this report. If any of the following risk factors, as well as other risks and uncertainties that are not currently known to us or that we currently believe are not material, actually occur, our business, financial condition and results of operations could be materially and adversely affected.

Risks Related to Our Business and Industry

The recent global economic downturn and disruptions in the financial and credit markets may have a material adverse effect on our business, financial condition and results of operations.

        The recent global economic downturn, particularly with respect to the U.S. economy, coupled with the global financial and credit market disruptions, have had an adverse impact on the coal industry generally and may continue to do so until economic conditions improve. The demand for electricity in our target markets has decreased during 2009. Decreases in the demand for electricity typically lead to a decline in the demand for and prices of coal. The economic downturn has also negatively impacted the demand for U.S. exports of coal. If these trends continue, we may not be able to sell all of the coal we are capable of producing or sell our coal at prices comparable to more favorable years. In addition, prices for coal in the spot market, including for PRB coal, have decreased from their historic highs reached during the first half of 2008. Although we have historically sold most of our coal under long-term coal sales agreements with fixed prices, the prices in the spot market influence the price for the forward sales agreements that we are entering into now and may enter into in the future, and the prices we receive for our coal may not be as favorable as they have been in the past. Although economic conditions have generally deteriorated since mid-2008, we began to feel the effects of the changes in the market during the beginning of the second quarter of 2009. In addition, stockpiles of coal by our customers increased as a result of the downturn, reaching their highest level in recent years, and our customers began curtailing future orders. Recent low prices for natural gas, which is a substitute for coal generated power, may also lead to continued decreased coal consumption by electricity-generating utilities. Recent market conditions, including tightening of the credit markets, may also impact our customers' ability to finance their operations, which may result in decreased demand for our coal, cancellation of orders or changes to the coal sales agreements with those customers. For example, during 2009 we experienced a greater than normal number of customers seeking to reduce the amount of tons taken under existing contracts through contractual remedies, such as force majeure provisions, and additional customers may seek to similarly reduce tons taken in future periods under their agreements with us. Decreased sales volumes could impact our revenues, cost structure and opportunities for growth in the future. We are unable to predict the long-term impact of the recent global economic and financial crisis, and any actions we may take in response to these conditions or any which may arise in the future may be insufficient. A protracted continuation or worsening of the global economic downturn or disruptions in the financial markets could have a material adverse effect on our business, financial condition and results of operations. Furthermore, because we typically seek to enter into long-term arrangements for the sale of a substantial portion of our coal, it is likely that the average sales price we receive for our coal will lag behind any general economic recovery in the United States.

Coal prices are subject to change and a substantial or extended decline in prices could materially and adversely affect our revenues and results of operations, as well as the value of our coal reserves.

        Our revenues, results of operations and the value of our coal reserves are dependent in large measure upon the prices we receive for our coal. Because coal is a commodity, the prices we receive are set by the marketplace. Prices for coal generally tend to be cyclical, and over the last several years

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have become more volatile. The contract prices we may receive in the future for coal depend upon numerous factors, including:

•

the domestic and foreign supply and demand for coal, including demand for U.S. coal exports from eastern U.S. markets;



•

domestic demand for electricity;



•

domestic and foreign economic conditions, including economic downturns and the strength of the global and U.S. economies;



•

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, such as natural gas and crude oil, and alternative energy sources, such as nuclear, hydroelectric, wind and solar power, and the effects of technological developments related to these non-coal and alternative energy sources;



•

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



•

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



•

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 that limits carbon dioxide emissions or provides for increased funding and incentives for, or mandates the use of, alternative energy sources;



•

domestic and foreign governmental regulations and taxes;



•

the quantity, quality and pricing of coal available in the resale market;



•

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



•

market price fluctuations for sulfur dioxide emission allowances; and



•

subsidies designed to encourage the use of alternative energy sources.

A substantial or extended decline in the prices we receive for our future coal sales contracts due to these or other factors could materially and adversely affect us by decreasing our revenues, thereby materially and adversely affecting our results of operations.

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

        We mine coal at surface mining operations located in Wyoming and Montana. Our coal mining operations are subject to a number of operating risks. Because we maintain very little produced coal inventory, certain conditions or events could disrupt operations, adversely affect production and shipments and increase the cost of mining at particular mines for varying lengths of time, which could have a material adverse effect on our results of operations. These conditions and events include, among others:

•

poor mining conditions resulting from geological, hydrologic or other conditions, which may cause instability of highwalls or spoil-piles or cause damage to nearby infrastructure;



•

mining and plant equipment failures and unexpected maintenance problems;



•

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

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•

the unavailability of raw materials, equipment (including heavy mobile equipment) or other critical supplies such as tires and explosives, fuel, lubricants and other consumables of the type, quantity and/or size needed to meet production expectations;



•

the capacity of, and proximity to, rail transportation facilities and rail transportation delays or interruptions, including derailments;



•

delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits, including environmental permits, or mining or surface rights;



•

delays or difficulties in, the unavailability of, or unexpected increases in the cost of acquiring, developing and permitting new LBA acquisitions from the federal government and other new mining reserves and surface rights;



•

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;



•

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



•

current and future health, safety and environmental regulations or changes in interpretations of current regulations, including the classification of plant and animal species near our mines, including the potential listing of the sage grouse, as endangered or threatened species;



•

inability to acquire or maintain adequate financial sureties for mining and reclamation purposes or to meet other governmental or private bonding requirements; and



•

the value of the U.S. dollar relative to other currencies, particularly where imported products are required for the mining process, such as tires and petroleum products.

        These changes, conditions and events may materially increase our cost of mining and delay or halt production at particular mines either permanently or for varying lengths of time.

Competition within the coal production industry and with producers of competing energy sources may materially and adversely affect our ability to sell coal at a favorable price.

        We compete with numerous other coal producers in various regions of the U.S. 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, including the overall demand for electricity in foreign markets; currency exchange rates; ocean freight rates; port and shipping capacity; the demand for foreign-produced 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 eastern U.S. coal increased significantly during 2008 but declined during 2009. A further decline in foreign demand for U.S. could cause competition among coal producers for sales in the U.S. to intensify, potentially resulting in significant additional downward pressure on domestic coal prices, including in the PRB.

        In addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas and crude oil. A decline in price for these fuels could cause demand for coal to decrease and adversely affect the price of our coal. For example, the average price for natural gas has recently declined from $5.87 per thousand cubic feet as of December 2008 to $4.44 per thousand cubic feet as of December 2009, leading to, in some instances, decreased coal consumption by electricity-generating utilities. If alternative energy sources, such as nuclear, hydroelectric, wind or solar, become more cost-competitive on an overall basis, demand for coal could decrease and the price of coal could be materially and adversely affected, including in the PRB. Further, legislation requiring the use and dispatch of these alternative energy sources and fuels or legislation providing financing or

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incentives to encourage continuing technological advances in this area could further enable alternative energy sources to become more competitive with coal.

Excess production and production capacity in the coal industry could put downward pressure on coal prices and, as a result, materially and adversely affect our revenues and profitability.

        During the mid-1970s and early 1980s, increased demand for coal attracted new investors to the coal industry in the PRB, 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 during recent periods encouraged the development of expanded capacity by coal producers. Some of these planned capacity increases and existing production plans have been delayed or reduced due to coal price reductions since mid-2008 and the global economic downturn. However, these capacity increases may be restarted in the future. Any overcapacity and increased production in the future 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 customers primarily use our coal as fuel for domestic electricity generation. Overall economic activity and the associated demands 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. 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, could reduce our revenues and materially and adversely affect our business and results of operations.

        In 2009, we sold approximately 95% of our coal to domestic electric power generators. Domestic electric power generation accounted for approximately 94% of all U.S. coal consumption in 2009, according to the Energy Information Administration, or EIA. 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 and solar power;



•

technological developments, including those related to alternative energy sources; and



•

subsidies designed to encourage the use of alternative energy sources.

        Gas-fired generation has the potential to displace coal-fired generation, particularly from older, less efficient coal-powered generators. We expect that many of the new power plants needed to meet increasing demand for domestic electricity generation will be fired 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-fired generators. In recent periods, governmental regulators at the federal, state and local levels have shown increased interest in limiting greenhouse gas emissions. This has resulted in increased regulation of coal mining and of coal-fired power plants and other end-users of coal, increasing the cost of burning coal compared to alternative

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energy sources. In addition, environmental activists concerned with climate change issues have attempted to use the regulatory and judicial processes to block the construction of new coal-fired power plants or capacity expansions to existing plants. Further, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal. Many 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 federal proposals have been enacted to date, the Obama Administration has indicated its support for a federal renewable energy standard, and federal legislation imposing such a mandate is currently under consideration by Congress. 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 U.S. 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.

New and potential future regulatory requirements and public concerns relating to greenhouse gas emissions could 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.

        One major by-product of burning coal is carbon dioxide, which is considered a greenhouse gas and is a major source of public concern with respect to global warming, also known as climate change. Climate change continues to attract public and scientific attention, and increasing government attention is being paid to reducing greenhouse gas emissions, including from coal-fired power plants.

        There are many regulatory approaches currently in effect or being considered to address greenhouse gases, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program and regulation by the EPA.

•

The federal government has indicated its support for a mandatory cap-and-trade program to reduce greenhouse gas emissions, and the U.S. Congress is considering various proposals to reduce greenhouse gas emissions, mandate electricity suppliers to use renewable energy sources to generate a certain percentage of power and require energy efficiency measures. In June 2009, the U.S. House of Representatives passed a comprehensive climate change and energy bill, the American Clean Energy and Security Act, and the U.S. Senate is considering similar legislation that would, among other things, impose a nationwide cap on greenhouse gas emissions and require major sources, including coal-fired power plants, to obtain "allowances" to meet that cap.



•

In September 2009, the EPA promulgated a rule requiring certain emitters of greenhouse gases, including coal-fired power plants, to monitor and report their greenhouse gas emissions to the EPA. In addition, in response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA that the EPA has authority to regulate carbon dioxide emissions under the Clean Air Act, the EPA has issued and is considering several additional proposals, including one that would require best available control technology for greenhouse gas emissions whenever certain stationary sources, such as a power plants, are built or significantly modified.



•

State and regional climate change initiatives intended to limit or affect the emission of greenhouse gas emissions from certain sources, such as the Regional Greenhouse Gas Initiative covering certain northeastern and mid-Atlantic states, the Western Climate Initiative, the Midwestern Greenhouse Gas Reduction Accord and the California Global Warming Solutions Act, either have already taken effect or may take effect before federal action.

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•

The State of California recently approved a fee to be paid by certain emitters of greenhouse gases, and other jurisdictions have or are also considering imposing similar fees or taxes.

        The permitting of new coal-fired power plants has also recently been contested, at times successfully, by state regulators and environmental organizations due to concerns related to greenhouse gas emissions from the new plants. Additionally, two U.S. federal appeals courts have reinstated lawsuits permitting individuals, state attorneys general and others to pursue claims against major utility, coal, oil and chemical companies on the basis that those companies have created a public nuisance due to their emissions of carbon dioxide.

        Climate change initiatives and other efforts to reduce greenhouse gas emissions like those described above or otherwise may require additional controls on coal-fired power plants and industrial boilers, may cause some users of coal to switch from coal to a lower carbon fuel and may result in the closure of coal-fired power plants or in reduced construction of new plants. Any switching of fuel sources away from coal, closure of existing coal-fired power plants, or reduced construction of new coal-fired power plants could have a material adverse effect on demand for and prices received for our coal.

Our business requires substantial capital investment and maintenance expenditures, which we may be unable to provide.

        Our business plan and strategy are dependent upon our acquisitions of additional reserves, which require substantial capital expenditures. We also require capital for, among other purposes, acquisition of surface rights, equipment and the development of our mining operations, capital renovations, maintenance and expansions of plants and equipment and compliance with environmental laws and regulations. To the extent that cash on hand, cash generated internally and cash available under our credit facility are not sufficient to fund capital requirements, we will require additional debt and/or equity financing. However, additional debt or equity financing may not be available to us or, if available, may not be available on satisfactory terms. Additionally, our debt instruments may restrict our ability to obtain such financing. Furthermore, the recent tightening and volatility of the credit markets has resulted in more stringent lending standards and terms and higher volatility in interest rates. These trends together with significant write-offs in the financial services sector, re-pricing of credit risk and weak economic conditions generally could adversely impact our ability to obtain additional debt financing or the cost of debt if obtained. If we are unable to obtain additional capital, we may not be able to maintain or increase our existing production rates and we could be forced to reduce or delay capital expenditures or change our business strategy, sell assets or restructure or refinance our indebtedness, all of which could have a material adverse effect on our business or financial condition.

If we are unable to acquire or develop additional coal reserves that are economically recoverable, our profitability and future success and growth may be materially and adversely affected.

        Our profitability depends substantially on our ability to mine, in a cost-effective manner, coal reserves that possess the quality characteristics our customers desire. Because our reserves decline as we mine our coal, our future success and growth depend upon our ability to acquire additional coal that is economically recoverable. If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted. As a result, to maintain our production capacity and competitive position, we will need to acquire significant additional coal through the federal competitive leasing process that can be mined on an economically recoverable basis.

        Our ability to obtain additional 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 debt instruments, competition from other coal companies for properties, the lack of suitable acquisition or LBA

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opportunities or the inability to acquire coal properties or LBAs on commercially reasonable terms. In addition, we may not be able to mine future reserves as profitably as we do at our current operations. Furthermore, the price we receive for our coal impacts the economic recoverability of our existing coal. Our ability to develop economically recoverable reserves will be materially adversely impacted if prices for coal sold decrease significantly.

Because most of the coal in the vicinity of our mines is owned by the U.S. federal government, our future success and growth could be materially and adversely affected if we are unable to acquire additional reserves through the federal competitive leasing process.

        The U.S. federal government owns most of the coal in the vicinity of our mines. Accordingly, the LBA process is the most significant means of acquiring additional reserves. There is no requirement that the federal government lease coal subject to an LBA, lease its coal at all or give preference to any LBA applicant, and our bids may compete with other coal producers' bids in the PRB. In the current coal pricing environment, LBAs are becoming increasingly more competitive and expensive to obtain, and the review process to submit an LBA for bid continues to lengthen. We expect that this trend may continue. The increasing size of potential LBA tracts may make it easier for new mining operators to enter the market on economical terms and may, therefore, increase competition for LBAs. Increased opposition from non-governmental organizations and other third parties may also lengthen, delay or complicate the LBA process. In order to win a lease in the LBA process and acquire additional coal, our bid for a coal tract must meet or exceed the fair market value of the coal based on the internal estimates of the BLM, which they do not publish. We have maintained a history of timely payments related to our LBAs. If we are unable to maintain our "good payer" status, we would be required to seek bonding for any remaining payments.

        The LBA process also requires us to acquire rights to mine from surface owners overlying the coal, and these rights are becoming increasingly more difficult and costly to acquire. Certain federal regulations provide a specific class of surface owners, also known as qualified surface owners, or QSOs, with the ability to prohibit the BLM from leasing its coal. If a QSO owns the land overlying a coal tract, federal laws prohibit us from leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO. This right of QSOs allows them to exercise significant influence over negotiations to acquire surface rights and can delay the LBA process or ultimately prevent the acquisition of an LBA. If we are unable to successfully negotiate access rights with QSOs at a price and on terms acceptable to us, we may be unable to acquire LBAs for coal on land owned by the QSO. If the prices to acquire land owned by QSOs increase, it could materially and adversely affect our profitability.

If we are unable to acquire surface rights to access our coal, we may be unable to obtain a permit to mine coal we own and may be required to employ expensive techniques to mine around those sections of land we cannot access in order to access other sections of coal reserves, which could materially and adversely affect our business and our results of operations.

        After we acquire coal through the LBA process or otherwise, we are required to obtain a permit to mine the coal through the applicable state agencies prior to mining the acquired coal. In part, the permitting requirements provide that, under certain circumstances, we must obtain surface owner consent if the surface estate has been split from the mineral estate, which is commonly known as a "split estate." We have in the past and may in the future be required to negotiate with multiple parties for the surface access that overlies coal we acquired through the LBA process or otherwise. If we are unable to successfully negotiate surface access with any of these surface owners, or do so on commercially reasonable terms, we may be denied a permit to mine some of our coal or may find that we cannot mine the coal at a profit. If we are denied a permit, this would create significant delays in our mining operations and materially and adversely impact our business and results of operations.

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Furthermore, if we determine to alter our plans to mine around the affected areas, we could incur significant additional costs to do so, which could increase our operating expenses considerably and could materially and adversely affect our results of operations.

We may be unable to acquire state leases for coal, or to do so on a cost-effective basis, which could materially and adversely affect our business strategy and growth plans.

        We acquire a small percentage of our coal through state leasing processes. Nearly all of the state leases in Wyoming have already been acquired by various mining operations in the PRB, including ours. If, as part of our growth strategy, we desire to expand our operations into areas requiring state leases, we may be required to negotiate with competing Wyoming mining operations. If we are unable to do so on a cost-effective basis, our business strategy could be adversely affected. We do not typically acquire state leases in Montana significantly in advance of mining operations due to the complexity of the leasing process in Montana.

Conflicts of interest with competing holders of mineral rights could materially and adversely affect our ability to mine coal or do so on a cost-effective basis.

        The federal government leases many different mineral rights in addition to coal, such as coalbed methane, natural gas and crude oil reserves. Some of these minerals are located on, or are adjacent to, some of our coal and LBA areas, potentially creating conflicting interests between us and the lessees of those interests. If conflicting interests arise, we may be required to negotiate our ability to mine with the holder of the competing mineral rights. If we are unable to reach an agreement with these holders, or do so on a cost-effective basis, we may incur increased costs and our ability to mine could be impaired, which could materially and adversely affect our business and results of operations.

Our management team does not have experience managing our business as a stand-alone public company, and if they are unable to manage our business as a stand-alone public company, our business may be harmed.

        We have historically operated as part of Rio Tinto. The majority of our management team does not have experience managing a business on a stand-alone basis or as a public company. If we are unable to manage and operate our company as a stand-alone public company, our business and results of operations will be adversely affected.

We are incurring increased costs as a result of being a public company, and the requirements of being a public company may divert management attention from our business. If we are unable to achieve and maintain effective internal controls, our operating results and financial condition could be harmed.

        As a public company, we incur significant legal, accounting and other expenses that we did not incur as a private company. In addition, we are subject to a number of additional requirements, including the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act and the listing standards of New York Stock Exchange. These requirements will cause us to incur increased costs and might place a strain on our systems and resources. The Exchange Act requires, among other things, that we file annual, quarterly and current reports with respect to our business and financial condition. The Sarbanes-Oxley Act requires, among other things, that we maintain effective disclosure controls and procedures and internal control over financial reporting, and also requires that our internal control over financial reporting be assessed by management and attested to by our auditors as of December 31 of each year commencing with the year ending December 31, 2010. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal control over financial reporting, significant resources and management oversight will be required. As a result, our management's

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attention might be diverted from other business concerns, which could have a material adverse effect on our business, prospects, financial condition and results of operations.

We have identified material weaknesses in our internal controls over financial reporting that have contributed to a restatement of our 2005, 2006 and 2007 consolidated financial statements and June 30, 2008 interim consolidated financial statements. If not remediated satisfactorily, these material weaknesses could result in further material misstatements in our consolidated financial statements in future periods.

        For purposes of filing our registration statement on Form S-1 in connection with our IPO, we prepared consolidated financial statements as of December 31, 2007 and 2008 and for each of the three years in the period ended December 31, 2008 in accordance with U.S. generally accepted accounting principles (U.S. GAAP). During this process, we identified material weaknesses in our internal controls over financial reporting that contributed both to a restatement of our 2005, 2006 and 2007 consolidated financial statements and June 30, 2008 interim consolidated financial statements. Specifically, as an indirect wholly-owned subsidiary of Rio Tinto, we were not required to and we did not maintain a sufficient complement of personnel with an appropriate level of accounting, taxation and financial reporting knowledge, experience and training in the application of U.S. GAAP commensurate with our financial reporting requirements on a stand-alone basis and the complexity of our operations and transactions. We also did not maintain an adequate system of processes and internal controls sufficient to support our financial reporting requirements and produce timely and accurate U.S. GAAP consolidated financial statements consistent with being a stand-alone public company.

        A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. A deficiency in internal control over financial reporting exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent or detect misstatements on a timely basis.

        In connection with our IPO, we have begun implementing changes and improvements in our internal control over financial reporting to remediate the control deficiencies that gave rise to the material weaknesses. These remedial steps will need to be placed in operation for a sufficient period of time before we can evaluate the overall effectiveness of our remediation plan and be able to conclude that the material weaknesses have been remediated.

        Our remediation actions may not be effective to correct the material weaknesses. If not remediated satisfactorily, these material weaknesses could result in further material misstatements in our consolidated financial statements in future periods. If we continue to experience material weaknesses, investors could lose confidence in our financial reporting, particularly if such weaknesses result in a restatement of our financial results, and our stock price could decline. See Item 9A below.

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 and analyzed by our internal geologists and engineers. Our estimates of proven and probable coal reserves as to both quantity and quality are updated 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

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mine, coal reserves, any one of which may vary considerably from actual results. These factors and assumptions include:

•

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;



•

the percentage of coal ultimately recoverable;



•

the assumed effects of regulation, including the issuance of required permits, and 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.

If our highwalls or spoil-piles fail, our mining operations and ability to ship our coal could be impaired and our results of operations could be materially and adversely affected.

        Our operations could be adversely affected and we may be unable to produce coal if our highwalls fail due to conditions, which may include geological abnormalities, poor ground conditions, water or blasting shocks, among others. In addition to making it difficult and more costly to recover coal, a highwall failure could also damage adjacent infrastructure such as roads, power lines, railways and gas pipelines. Further, in-pit spoil-pile failure due to conditions such as material type, water ingress, floor angle, floor roughness, spoil volume or otherwise, can impact coal removal, reduce coal recovery, increase our costs or interrupt our production and shipments. Highwall and spoil-pile failures could materially and adversely affect our operations, thereby reducing our profitability.

Major equipment and plant failures could reduce our ability to produce and ship coal and materially and adversely affect our results of operations.

        We depend on several major pieces of equipment and plant to produce and ship our coal, including draglines, shovels, coal crushing plants, critical conveyors, major transformers and coal silos. If any of these pieces of equipment or plant suffered major damage or were destroyed by fire, abnormal wear, flooding, incorrect operation, damage from highwall or spoil-pile failures or otherwise, we may be unable to replace or repair them in a timely manner or at a reasonable cost, which would impact our ability to produce and ship coal and materially and adversely affect our results of operations.

Significant increases in the royalty and production taxes we pay on the coal we produce could materially and adversely affect our results of operations.

        We pay federal, state and private royalties and federal, state and county production taxes on the coal we produce. A substantial portion of our royalties and production taxes are levied as a percentage

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of gross revenues with the remaining levied on a per ton basis. For example, we pay production royalties of 12.5% of gross proceeds to the federal government. We incurred royalties and production taxes which represented 29.1% of proceeds from the coal we produced for the year ended December 31, 2009. If the royalty and production tax rates were to significantly increase, our results of operations could be materially and adversely affected.

        In addition, the Wyoming state severance tax is significantly less than the state severance tax in Montana. Because a substantial portion of our operations are in Wyoming and therefore subject to the more favorable Wyoming severance tax rate, if Wyoming were to increase this tax or any other tax applicable solely to our Wyoming operations, we may be significantly impacted and our results of operations could be materially and adversely affected.

Increases in the cost of raw materials and other industrial supplies, or the inability to obtain a sufficient quantity of those supplies, could increase our operating expenses, disrupt or delay our production and materially and adversely affect our profitability.

        We use considerable quantities of explosives, petroleum-based fuels, tires, steel and other raw materials, as well as spare parts and other consumables in the mining process. If the prices of steel, explosives, tires, petroleum products or other materials increase significantly or if the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses will increase, which could materially and adversely impact our profitability. Additionally, a limited number of suppliers exist for certain supplies, such as explosives and tires, as well as certain mining equipment, and any of our suppliers may divert their products to buyers in other mines or industries or divert their raw materials to produce other products that have a higher profit margin. Shortages in raw materials used in the manufacturing of supplies and mining equipment, which, in some cases, do not have ready substitutes, or the cancellation of our supply contracts under which we obtain these raw materials and other consumables, could limit our ability to obtain these supplies or equipment. As a result, we may not be able to acquire adequate replacements for these supplies or equipment on a cost-effective basis or at all, which could also materially increase our operating expenses or halt, disrupt or delay our production.

Significant increases in the price of diesel fuel could materially and adversely affect our earnings.

        Operating expenses at our mining locations are sensitive to changes in certain variable costs, particularly diesel fuel prices, which are our largest variable cost after personnel costs. Any increase in the price we pay for diesel fuel will have a negative impact on our results of operations. See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations—Cost of Product Sold."

The majority of our coal sales contracts are forward sales contracts at fixed prices. If the production costs underlying these contracts increase, our results of operations could be materially and adversely affected.

        The majority of our coal sales contracts are forward sales contracts under which customers agree to pay a specified price under their contracts for coal to be delivered in future years. The profitability of these contracts depends on our ability to adequately control the costs of the coal production underlying the contracts. These production costs are subject to variability due to a number of factors, including increases in the cost of labor, supplies or other raw materials, such as diesel fuel. Historically we have not entered into hedge or other arrangements to offset the cost variability underlying these forward sale contracts. In the future, we may enter into these types of arrangements, but we may not be successful in hedging the volatility of our costs. To the extent our costs increase but pricing under these coal sales contracts remains fixed, we will be unable to pass increasing costs on to our customers. If we are unable to control our costs, our profitability under our forward sales contracts may be impaired and our results of operations could be materially and adversely affected.

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Our ability to operate our business effectively could be impaired if we fail to attract and retain key personnel.

        Our ability to operate our business and implement our strategies depends, in part, on the continued contributions of our executive officers and other key employees. The loss of any of our key senior executives could have a material adverse effect on our business unless and until we find a qualified replacement. A limited number of persons exist with the requisite experience and skills to serve in our senior management positions. We may not be able to locate or employ qualified executives on acceptable terms. In addition, we believe that our future success will depend on our continued ability to attract and retain highly skilled personnel with coal industry experience. Competition for these persons in the coal industry is intense, and we may not be able to successfully recruit, train or retain qualified managerial personnel. As a public company, our future success also will depend on our ability to hire and retain management with public company experience. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future. Our failure to retain or attract key personnel could have a material adverse effect on our ability to effectively operate our business.

We rely on an affiliate of RTEA to provide us with certain key services related to our information technology systems. If we cannot replace such services with our own stand-alone systems prior to the expiration of the agreement, our business may be adversely impacted.

        Currently, we rely on an affiliate of RTEA to provide systems and support related to our information technology systems under the terms of a transition services agreement entered into in connection with our IPO. This agreement expires in August of 2010. If we cannot successfully transition these systems to our own stand-alone systems, or cannot find a third-party to replace the systems and support provided by an affiliate of RTEA, we may be unable to continue running our systems at full capacity or at all, which may adversely and negatively impact our business and could potentially result in a material weakness in our internal control over financial reporting.

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.

        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, mercury 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 is expected to be proposed or become effective in the near future. In addition, federal and state mandates and incentives designed to encourage energy efficiency and the use of alternative energy sources have been proposed and implemented in recent years. 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. New regulations are in the process of being developed, and many existing and potential regulatory initiatives are 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-fired 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 resulting in a reduced need to construct new coal-fired power plants. Any switching of fuel sources away from coal, closure of existing coal-fired power plants, or reduced construction of new coal-fired power plants could have a material adverse effect on demand for, and prices received for,

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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.

Extensive environmental laws and regulations impose significant costs on our mining operations, and future laws and 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; and



•

the effects of mining on surface water and groundwater quality and availability.

        The costs, liabilities and requirements associated with the laws and regulations related to these and other environmental matters may be significant and time-consuming and may delay commencement or continuation of exploration or production operations. Because of the extensive regulatory environment in which we operate, while we may be in compliance in all significant respects, we cannot assure complete compliance with all 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.

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

        Our operations use hazardous materials and generate hazardous and non-hazardous wastes. In addition, many of the locations that we own, lease or operate were used for coal mining and/or involved the generation, use, storage and disposal of hazardous substances either before or after we

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were involved with these locations. We may be subject to claims under federal and state statutes and/or common law doctrines for toxic torts, natural resource damages and other damages, as well as for the investigation and clean up of soil, surface water, groundwater and other media. These claims may arise, for example, out of current or former conditions at sites that we own, lease or operate currently, as well as at sites that we or predecessor entities owned, leased or operated in the past, and at contaminated third-party sites at which we have disposed of hazardous substances and waste. As a matter of law, and despite any contractual indemnity or allocation arrangements or acquisition agreements to the contrary, our liability for these claims may be joint and several, so that we may be held responsible for more than our share of any contamination, or even for the entire share.

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

Extensive governmental regulations pertaining to employee safety and health impose significant costs on our mining operations, which could materially and adversely affect our results of operations.

        Federal and state safety and health regulations in the coal mining industry are among the most comprehensive and pervasive systems for protection of employee safety and health affecting any segment of U.S. industry. Compliance with these requirements imposes significant costs on us and can result in reduced productivity. Moreover, the possibility exists that new health and safety legislation and/or regulations and orders may be adopted that may materially and adversely affect our mining operations.

        We must compensate employees for work-related injuries. If we do not make adequate provisions for our workers' compensation liabilities, it could harm our future operating results. In addition, the erosion through tort liability of the protections we are currently provided by workers' compensation laws could increase our liability for work-related injuries and materially and adversely affect our operating results. Under federal law, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and contribute to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry before January 1, 1970. The trust fund is funded by an excise tax on coal production. If this tax increases, or if we could no longer pass it on to the purchasers of our coal under our coal sales agreements, our operating costs could be increased and our results could be materially and adversely harmed. If new laws or regulations increase the number and award size of claims, it could materially and adversely harm our business.

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

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

        Mining companies must obtain a number of 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 EISs 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 EISs or performance of mining activities. Recently, environmental groups made extensive comments to an EIS prepared in connection with one of our federal mining lease applications. These groups argued that the EIS failed to satisfactorily consider climate change risks. If this or any other permits or leases are not issued or renewed in a timely fashion or at all, or if permits or leases issued or renewed are conditioned in a manner that restricts our ability to efficiently and economically conduct our mining activities, we could suffer a material reduction in our production, and our cash flow or profitability could be materially and adversely affected.

Failure to obtain, maintain or renew our security arrangements, such as surety bonds or letters of credit, in a timely manner and on acceptable terms could affect our ability to secure reclamation and coal lease obligations and materially and adversely affect our ability to mine or lease coal.

        Federal and state laws require us to secure the performance of certain long-term obligations, such as mine closure or reclamation costs and federal and state workers' compensation costs, including black lung. The amount of these security arrangements is substantial with total amounts of surety bonds and letters of credit in place for such obligations at December 31, 2009 of $574.6 million. Certain business transactions, such as coal leases and other obligations, may also require bonding. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including putting up letters of credit, posting cash collateral 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, our 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-party surety bond issuers of their right to refuse to renew the surety bonds and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of any credit arrangements then in place. Surety bond issuers may demand terms that are less favorable to us than the terms we currently receive, and there may be fewer companies willing to issue these bonds. Further, due to recent economic conditions and the volatility of the financial markets, surety bond providers may be less willing to provide us with future surety bonds or maintain existing surety bonds, and we may have greater difficulty satisfying the liquidity requirements under our existing surety bond contracts. If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our ability to mine or lease coal could be materially and adversely affected.

Because we produce and sell coal with low-sulfur content, a reduction in the price of sulfur dioxide emission allowances or increased use of technologies to reduce sulfur dioxide emissions could materially and adversely affect the demand for our coal and our results of operations.

        Our customers' demand for our low-sulfur coal, and the prices that we can obtain for it, are affected by, among other things, the price of sulfur dioxide emission allowances. The Clean Air Act

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places limits on the amounts of sulfur dioxide that can be emitted by an electric power plant in any given year. If a plant exceeds its allowable limits, it must purchase allowances, which are tradable in the open market. Regulatory uncertainty following the action by the U.S. Court of Appeals for the District of Columbia Circuit to vacate the CAIR in July 2008, and its subsequent temporary reinstatement, which established a cap-and-trade program for sulfur dioxide and nitrogen oxide emissions from power plants in certain states, caused a significant decrease in the price of sulfur dioxide allowances in 2008 and 2009 and delayed the installation of technology to reduce emissions at some power plants. Low prices of these emissions allowances could make our low-sulfur coal less attractive to our customers. In addition, more widespread installation by electric utilities of technology that reduces sulfur emissions, which could be accelerated by increases in the prices of sulfur dioxide emission allowances, may make high sulfur coal more competitive with our low-sulfur coal. This competition could materially and adversely affect our business and results of operations.

The risk that we cannot collect payments from our customers could increase if their creditworthiness deteriorates.

        The risk that we do not receive payment for coal sold and delivered increases if the continued creditworthiness of our customers declines. The recent economic volatility and tightening credit markets increase the risk that we may not be able to collect payments from our customers or be required to continue to deliver coal even if a customer's creditworthiness deteriorates. A worsening of recent economic conditions or a prolonged global or U.S. recession could also impact the creditworthiness of our customers. If we determine that a customer is not creditworthy, we can demand credit enhancements from the customer. If we are unsuccessful or feel the credit enhancement is insufficient, we may not be required to deliver coal under the customer's coal sales contract. If we are able to withhold shipments, we may decide to sell a 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 fall 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.

Our ability to mine and ship coal is affected by adverse weather conditions, which could have an adverse effect on our revenues.

        Adverse weather conditions can impact our ability to mine and ship our coal and our customers' ability to take delivery of our coal. Lower than expected shipments by us during any period could have an adverse effect on our revenues and profitability. For example, previously our volume of coal shipments has been impacted by severe heavy rain, which reduced the capacity of the railroads by which our customers contract to transport coal from our mines. In addition, severe weather, including droughts and dust, may adversely affect our ability to conduct our mining operations.

The availability and reliability of transportation and increases in transportation costs, particularly for rail systems, could materially and adversely affect the demand for our coal or impair our ability to supply coal to our customers.

        Transportation costs, particularly rail transportation costs, represent a significant portion of the total cost of coal for our customers, and the cost of transportation is a key factor in a customer's purchasing decision. Increases in transportation costs or the lack of sufficient rail capacity or availability could make coal a less competitive source of energy or could make the coal produced by us less

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competitive than coal produced from other regions, either of which could lead to reduced coal sales and/or reduced prices we receive for the coal.

        Our ability to sell coal to our customers depends primarily upon third-party rail systems. If our customers are unable to obtain rail or other transportation services, or to do so on a cost-effective basis, our business and growth strategy could be adversely affected. Alternative transportation and delivery systems are generally inadequate and not suitable to handle the quantity of our shipments or to ensure timely delivery to our customers. In particular, much of the PRB is served by two rail carriers, and the Northern PRB is only serviced by one rail carrier. The loss of access to rail capacity in the PRB could create temporary disruption until this access was restored; significantly impairing our ability to supply coal and resulting in materially decreased revenues. Our ability to open new mines or expand existing mines may also be affected by the availability and cost of rail or other transportation systems available for servicing these mines.

        We are a party to certain transportation contracts. During recent periods, we have entered into an increasing number of exports whereby we enter into transportation agreements pursuant to which we arrange for rail transport and port charges. However, typically our coal customers contract for, and pay directly for, transportation of coal from the mine or port to the point of use. Disruption of these transportation services because of weather-related problems; mechanical difficulties; train derailment; bridge or structural concerns; infrastructure damage, whether caused by ground instability, accidents or otherwise; strikes; lock-outs; lack of fuel or maintenance items; fuel costs; transportation delays; accidents; terrorism or domestic catastrophe or other events could temporarily or over the long term impair our ability to supply coal to our customers and our customers' ability to take our coal and, therefore, could materially and adversely affect our business and results of operations.

Due to the long-term nature of our coal sales agreements, the prices we receive for our coal at any given time may not reflect the then-existing current market prices for coal.

        We have historically sold most of our coal under long-term coal sales agreements, which we generally define as contracts with a term of one to five years. The remaining amount not subject to long-term coal sales agreements is sold as spot sales in term allotments of less than twelve months. For the year ended December 31, 2009, approximately 97% of our revenues were derived from coal sales that were made under long-term coal sales agreements. The prices for coal sold under these agreements are typically fixed for an agreed amount of time. Pricing in some of these contracts is subject to certain adjustments in later years or under certain circumstances, and may be below the current market price for similar type coal at any given time, depending on the timeframe of the contract. As a consequence of the substantial volume of our forward sales, we have less coal available to sell under short-term contracts with which to immediately capitalize on higher coal prices, if and when they arise. At times, spot market prices have fallen below the prices established in many of our long-term coal sales agreements, and we have realized prices for our coal that are higher than the prices we would receive from sales in the spot market. However, to the extent spot market prices increase and become higher than the prices established in our long-term coal sales agreements, our ability to realize those higher prices may be restricted when customers elect to purchase additional volumes allowable under some contracts at contract prices that are lower than spot prices.

Changes in purchasing patterns in the coal industry may make it difficult for us to enter into new contracts with customers, or do so on favorable terms, which could materially and adversely affect our business and results of operations.

        Although we currently sell the majority of our coal under long-term coal sales agreements, as electric utilities customers continue to adjust to increased price volatility, increased fungibility of coal products, frequently changing regulations and the increasing deregulation of their industry, some customers are becoming less willing to enter into long-term coal sales contracts. In addition, the prices

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for coal in the spot market have decreased at times and may be lower than the prices previously set under many of our long-term coal sales agreements. As our contracts with customers expire or are otherwise renegotiated, our customers may be less willing to extend or enter into new long-term coal sales agreements under their existing or similar pricing terms or our customers may decide to purchase fewer tons of coal than in the past. We have one significant broker sales contract which contributed $140.4 million of revenues for the year ended December 31, 2009, and income before tax of $46.3 million for the same period after other related costs, including amortization charges for the related contract rights of $28.7 million. Our delivery obligations under this contract are substantially complete.

        These trends in purchasing patterns in the coal industry could continue in the future and, to the extent our customers shift away from long-term supply contracts, it will be more difficult to predict our future sales. As a result, we may not have a market for our future production at acceptable prices. The prices we receive in the spot market may be less than the contractual price an electric utility is willing to pay for a committed supply. Furthermore, spot market prices tend to be more volatile than contractual prices, which could result in decreased revenues.

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated or be incurred sooner than anticipated.

        All of our mines are surface mining operations. SMCRA and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining. We estimate our total reclamation and mine-closing liabilities based on permit requirements, engineering studies and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers. At the Decker mine, the reclamation liability is estimated by the third-party operator. The estimated liability can change significantly if actual costs vary from our original assumptions or if governmental regulations change significantly. U.S. GAAP requires that asset retirement obligations be recorded as a liability based on fair value, which reflects the present value of the estimated future cash flows. In estimating future cash flows, we consider the estimated current cost of reclamation and apply inflation rates and a third-party profit, as necessary. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on behalf of us. The resulting estimated reclamation and mine closure obligations could change significantly if actual amounts or the timing of those expenses change significantly from our assumptions, which could have a material adverse effect on our results of operation and financial condition.

If the third-party sources we use to supply coal are unable to fulfill the delivery terms of their contracts, our results of operations could be materially and adversely affected.

        To fulfill deliveries under our coal sales agreements, we may from time to time purchase coal through third-party sources. For the year ended December 31, 2009, we purchased 10.1 million tons from third-party sources for delivery during that period. We also from time to time use third-party sources to sell our coal. Our profitability and exposure to loss on these transactions or relationships is dependent upon the reliability, including the financial viability, of the third-party coal producer, and on the price of the coal supplied by the third party or sold by us. Operational difficulties, changes in demand and other factors could affect the availability, pricing and quality of coal purchased by us. Disruptions in the quantities or qualities of coal purchased by us could affect our ability to fill our customer orders or require us to purchase coal, including at higher prices, from other sources in order to satisfy those orders. This could cause us to lose existing customers, which would negatively and adversely impact our results of operations.

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Certain provisions in our coal sales contracts may provide limited protection during adverse economic conditions or may result in economic penalties or suspension upon a failure to meet contractual requirements, any of which may cause our revenues and profits to suffer.

        Most of our sales contracts contain provisions that allow for the base price of our coal in these contracts to be adjusted due to new statutes, ordinances or regulations that affect our costs related to performance. Because these provisions only apply to the base price of coal, these terms may provide only limited protection due to changes in regulations. A few of our sales contracts also contain provisions that allow for the purchase price to be renegotiated at periodic intervals. A price re-opener provision is one in which either party can renegotiate the price of the contract, sometimes at pre-determined times. Index provisions allow for the adjustment of the price based on a fixed formula. These provisions may reduce the protection available under long-term contracts from short-term coal price volatility. Price re-opener and index provisions are present in contracts covering approximately 39% of our future tonnage commitments as of December 31, 2009. Any adjustment or renegotiations leading to a significantly lower contract price could result in decreased revenues.

        Quality and volumes for the coal 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 quality of the coal. In a relatively small number of contracts, customers are allowed to vary the amount of coal taken under the contract. 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 ash fusion temperature. Failure to meet these specifications can result in economic penalties, including price adjustments, suspension, rejection or cancellation of deliveries or termination of the contracts.

        Many of our contracts contain clauses that require us and our customers to maintain a certain level of creditworthiness or provide appropriate credit enhancement upon request. The failure to do so can result in a suspension of shipments under the contract. A number of our contracts also contain clauses which, in some cases, may allow customers to terminate the contract in the event of certain changes in environmental laws and regulations.

Upon the occurrence of a force majeure, we or our customers may be permitted to temporarily suspend performance under our coal sales contracts, which could cause our revenues and profits to suffer.

        Our coal sales agreements typically contain force majeure provisions allowing temporary suspension of performance by us or our customers during the duration of specified events beyond the control of the affected party, including events such as strikes, adverse mining conditions, mine closures, serious transportation problems that affect us or the buyer or unanticipated plant outages that may affect the buyer. Some contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer. During 2009, a greater than normal number of our customers sought to reduce the amount of tons delivered to them under our coal sales agreements through contractual remedies, such as force majeure provisions. 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 the event that we are required to suspend performance under any of our coal sales contracts, or we are required to purchase additional tonnage during the period in which performance under the contract is suspended, our revenues and profits could be materially and adversely affected.

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

        We have focused on strategic acquisitions and subsequent expansions of large, low-cost, low-sulfur operations in the PRB and replacement of, and additions to, our reserves through the acquisition of

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companies, mines and reserves. We may pursue acquisition opportunities in the future. If we are unable to successfully integrate the businesses or properties we acquire, or reserves that we lease or otherwise acquire, our business, financial condition or results of operations could be negatively affected. Acquisition transactions involve various risks, including:

•

uncertainties in assessing the strengths and potential profitability, and the related weaknesses, risks, contingent and other liabilities, of acquisition candidates;



•

changes in business, industry, market or general economic conditions that affect the assumptions underlying our rationale for pursuing the acquisition;



•

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



•

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



•

the nature and composition of the workforce, including the acquisition of a unionized workforce;



•

diversion of our management's attention from other business concerns;



•

regulatory challenges for completing and operating the acquired business, including opposition from environmental groups or regulatory agencies;



•

environmental or geological problems in the acquired properties, including factors that make the coal unsuitable for intended customers due to ash, heat value, moisture or contaminants;



•

inability to acquire sufficient surface rights to enable extraction of the coal resources;



•

outstanding permit violations associated with acquired assets;



•

difficulties or unexpected issues arising from our evaluation of internal control over financial reporting of the acquired business; and



•

risks related to operating in new jurisdictions, including increased exposure to foreign government and currency risks with respect to any international acquisitions.

        Any one or more of these factors could cause us not to realize the benefits we might anticipate from an acquisition. Moreover, any acquisition opportunities we pursue could materially increase our liquidity and capital resource needs and may require us to incur indebtedness, seek equity capital or both. We may not be able to satisfy these liquidity and capital resource needs on acceptable terms or at all. In addition, future acquisitions could result in our assuming significant long-term liabilities relative to the value of the acquisitions.

We do not currently operate the Decker mine and our results of operations could be adversely affected if the third-party mine operator fails to effectively operate the mine or if our joint venture partner fails to perform its obligations. In addition, our credit arrangements may limit our ability to contribute cash to the Decker mine.

        Through our indirect, wholly-owned subsidiary, we hold a 50% non-operating interest in the Decker mine in Montana through a joint venture agreement with a joint venture partner. The Decker mine is operated by a third-party mine operator. While we participate in the management committee of the Decker mine under the terms of the joint venture agreement, we do not control and our employees do not participate in the day-to-day operations of the Decker mine. If the third-party mine operator fails to operate the Decker mine effectively, our results of operations could be adversely affected.

        We share the profits, operating expenses, reclamation obligations and liabilities and assets associated with the Decker mine equally with our joint venture partner. Under the terms of the joint venture agreement, we are required to contribute cash or other property and equipment as may be

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necessary to operate the business. While capital contributions to the Decker joint venture have historically been made at the discretion of the management committee, under the terms of the joint venture agreement we may be required to contribute our proportional share of funds to carry on the business of the joint venture or to cover liabilities. In the event that either joint venture partner does not contribute its share of operating expenses, including reclamation expenses when due, or other liabilities, the other partner is not required to assume their obligation. However, we may have joint and several liability as a matter of law for these expenses and other liabilities, including for operational liabilities. Accordingly, our financial obligations with respect to the Decker mine are subject to the creditworthiness of our joint venture partner, which is outside of our control. In addition, if we do not provide our proportional share or our joint venture partner does not provide its proportional share, our interest in the profits from the Decker mine will be adjusted proportionally. CPE Resources' current debt instruments and future credit arrangements may include provisions limiting our ability to make contributions to the Decker joint venture.

A shortage of skilled labor in the mining industry could reduce labor productivity and increase costs, which could materially and adversely affect our business and results of operations.

        Efficient coal mining using modern techniques and equipment requires skilled laborers in multiple disciplines such as electricians, equipment operators, mechanics, engineers and welders, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. In the future, we may utilize a greater number of external contractors for portions of our operations. The costs of these contractors have historically been higher than that of our employed laborers. If coal prices decrease in the future and/or our labor and contractor prices increase, or if we experience materially increased health and benefit costs with respect to our employees, our results of operations could be materially and adversely affected.

Our work force could become unionized in the future, which could adversely affect the stability of our production and materially reduce our profitability.

        All of our mines, other than the Decker mine, which we do not operate, are operated by non-union employees. Our employees have the right at any time under the National Labor Relations Act to form or affiliate with a union, and in the past, unions have conducted limited organizing activities in this regard. If our employees choose to form or affiliate with a union and the terms of a union collective bargaining agreement are significantly different from our current compensation and job assignment arrangements with our employees, these arrangements could adversely affect the stability of our production and materially reduce our profitability. In addition, even if our managed operations remain non-union, our business may still be adversely affected by work stoppages at unionized companies or unionized transportation and service providers.

        We hold a 50% interest in the Decker mine, which is a union-based operation. These union-represented employees could strike, which could adversely affect production at the Decker mine, increase its costs and disrupt shipments of coal from the Decker mine to its customers, all of which could materially and adversely affect its profitability and the value of our investment in the Decker joint venture.

Provisions in our federal and state lease agreements, or defects in title or the loss of a leasehold interest in certain property or reserves or related surface rights, could limit our ability to mine our coal reserves.

        The vast majority of our coal interests are acquired by lease from state of federal governments. Under these leases, the BLM or the applicable state regulatory agency can terminate the lease prior to the expiration of its term if the leased coal reserves are not diligently developed during the initial 10 years of the leases or if certain other terms of the leases are not complied with, including the

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requirement to produce a minimum quantity of coal or pay a minimum advance production royalty, if applicable. If any of our leases are terminated, we would be unable to mine the affected coal and our business and results of operations could be materially adversely affected.

        Furthermore, a title defect on any lease, whether private or through a governmental entity, or the surface rights related to any of our reserves could adversely affect our ability to mine the associated coal reserves. Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing. Title to properties leased from private third parties is not usually fully verified until we make a commitment to develop a property, which may not occur until we have obtained the necessary permits and completed exploration of the property. In addition, these leasehold interests may be subject to superior property rights of other third parties. Title or other defects in surface rights held by us or other third parties could impair our ability to mine the associated coal reserves or cause us to incur unanticipated costs.

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

        Terrorist attacks and threats, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the U.S. or its allies, or military or trade disruptions affecting our customers may significantly affect our operations and those of our customers. Strategic targets such as energy-related assets and transportation assets may be at greater risk of future terrorist attacks than other targets in the U.S. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business and results of operations, including from delays or losses in transportation, decreased sales of our coal or extended collections from customers that are unable to timely pay us in accordance with the terms of their supply agreement.

Risks Related to Our Indebtedness

Our substantial indebtedness could adversely affect our results of operations and financial condition and prevent us from fulfilling our financial obligations.

        On November 25, 2009, our subsidiary, CPE Resources, entered into a $400 million revolving credit facility and $600 million aggregate principal amount of senior notes. At December 31, 2009, we had approximately $600.0 million of total debt outstanding (excluding the discounted obligations payable under our coal leases and approximately $9.3 million of other long-term debt incurred in connection with land acquisitions). In addition, at December 31, 2009, $51.8 million of capacity under the revolving credit facility was being used for letters of credit securing our reclamation obligations. As a result, at year end, the capacity under our revolving credit facility was $348.2 million. Our outstanding indebtedness could have important consequences such as:

•

limiting our ability to obtain additional financing to fund growth, such as mergers and acquisitions; working capital; capital expenditures; debt service requirements; LBA payments or other cash requirements;



•

requiring much of our cash flow to be dedicated to interest obligations and making it unavailable for other purposes;



•

with respect to any indebtedness under the revolving credit facility or other variable rate debt, exposing us to the risk of increased interest costs if the underlying interest rates rise on our variable rate debt;

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•

limiting our ability to invest operating cash flow in our business (including to obtain new LBAs or make capital expenditures) due to debt service requirements;



•

causing us to need to sell assets and properties at an inopportune time;



•

limiting our ability to compete effectively with companies that are not as leveraged and that may be better positioned to withstand economic downturns;



•

limiting our ability to acquire new coal reserves and/or LBAs and plant and equipment needed to conduct operations; and



•

limiting our flexibility in planning for, or reacting to, and increasing our vulnerability to, changes in our business, the industry in which we operate and general economic and market conditions.

        If our indebtedness is further increased, the related risks that we now face, including those described above, could intensify.

If we are unable to comply with the covenants or restrictions contained in the CPE Resources' debt instruments, the lenders could declare all amounts outstanding under those instruments to be due and payable, which could materially and adversely affect our financial condition.

        The debt instruments include covenants that, among other things, restrict our ability to dispose of assets, incur additional indebtedness, pay dividends or make other restricted payments, create liens on assets, make investments, loans or advances, make acquisitions, engage in mergers or consolidations and engage in certain transactions with affiliates (including with Rio Tinto or its affiliates). The debt instruments also include change of control provisions that accelerate or may require the repurchase of outstanding indebtedness in the event of certain change of control events. The debt instruments also require compliance with various financial covenants. Because CPE Resources (which entered into the debt instruments) is our only direct operating subsidiary, complying with these restrictions may prevent us from taking actions that we believe would help us to grow our business. These restrictions could limit our ability to plan for or react to market conditions or meet extraordinary capital needs or otherwise restrict corporate activities.

        The breach of any of the covenants or restrictions, unless cured within the applicable grace period, would result in a default under the debt instruments that would permit the lenders to declare all amounts outstanding to be due and payable, together with accrued and unpaid interest. In such an event, we may not have sufficient assets to repay such indebtedness. As a result, any default could have serious consequences to our financial condition. An event of default or an acceleration under one of our debt instruments could also cause a cross-default or cross-acceleration of another debt instrument or contractual obligation, which would adversely impact our liquidity.

        In addition, failure to comply with any of the covenants in our existing or future debt instruments could result in a default under those debt instruments and under other agreements containing cross-default provisions. A default would permit lenders to accelerate the maturity of the debt under these debt instruments and to foreclose upon any collateral securing the debt. Under these circumstances, we might not have sufficient funds or other resources to satisfy all of our obligations. In addition, the limitations imposed by the debt instruments on our ability to incur additional debt and to take other actions might significantly impair our ability to obtain other financing. We may not be granted waivers or amendments to these debt instruments if for any reason we are unable to comply with these debt instruments, and we may not be able to refinance our debt on terms acceptable to us, or at all.

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Provisions in our indenture could discourage an acquisition of us by a third party.

        Certain provisions of our indenture could make it more difficult or more expensive for a third party to acquire us. Upon the occurrence of certain transactions constituting a "change in control" as defined in the indenture, holders of our notes could require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase.

Risks Related to Our Corporate Structure and Our IPO Structuring Transactions

We are required to pay RTEA for most of the tax benefits we may claim as a result of the tax basis step-up we received in connection with our IPO and related IPO structuring transactions. In certain cases, payments to RTEA may be accelerated or exceed our actual cash tax savings. These provisions may deter a change in control of our company.

        In connection with our IPO and the acquisition of our membership units of CPE Resources, we entered into a tax receivable agreement, or the Tax Receivable Agreement, with RTEA that requires us to pay to RTEA approximately 85% of the amount of cash tax savings, if any, that we realize as a result of the increases in tax basis that we obtained in connection with the initial acquisition of our interest in CPE Resources, subsequent acquisitions of RTEA's units in CPE Resources, as well as payments made by us under the Tax Receivable Agreement. Due to the size of the increases in the tax basis of our share of CPE Resources' tangible and intangible assets, as well as the increase in our basis in the equity of CPE Resources' subsidiaries and assets held by those subsidiaries, we expect to make substantial payments to RTEA under the Tax Receivable Agreement. Based on the tax basis of our assets as of December 31, 2009 and CPE Resources' operating plan, the future payments under the Tax Receivable Agreement with respect to our controlling interest in CPE Resources are estimated to be approximately $54.5 million in the aggregate and are estimated to be payable over the next 18 years. This estimate is based on assumptions related to our business that could change, and the actual payments could differ materially from this estimate. Payments would be significantly greater if we generate income significantly in excess of the amounts used in our operating plan, for example, because we acquire additional LBAs beyond our existing LBAs , and as a result, we realize the full tax benefit of such increased tax basis (or an increased portion thereof). In addition, if we or CPE Resources acquire RTEA's remaining units in CPE Resources (or a significant portion thereof), we would likely receive a further step-up in our tax basis based on the value we or CPE Resources pay for RTEA's units at such time and, accordingly, our obligations under the Tax Receivable Agreement to pay RTEA 85% of any benefits we receive as a result of such further step-up would significantly increase. Our obligation may also increase if there are changes in law, including the increase of current corporate income tax rates. The payment obligations under the Tax Receivable Agreement are not conditioned upon RTEA's or its affiliate's continued ownership of an interest in CPE Resources or our available cash resources.

        Distributions from CPE Resources to enable us to fulfill our obligations under the Tax Receivable Agreement must be made pro rata to all holders of units of CPE Resources.    As managing member, we intend to cause CPE Resources to distribute cash to us to enable us to fulfill all of our obligations under the Tax Receivable Agreement. These distributions will be made on a per-unit basis, meaning corresponding distributions will be made to all holders of units in CPE Resources, including RTEA, in proportion to their percentage interests on the date of the distribution. These distributions will affect CPE Resources' available cash, which may impact CPE Resources' ability to fund capital expenditures or may result in CPE Resources needing to draw down on its existing credit facility or incur debt to finance these distributions to the extent that its cash resources are insufficient to make such distributions as a result of timing discrepancies or otherwise.

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        Certain changes in control require us to make payments to RTEA, which could exceed our actual cash savings and could require us to provide credit support.    If we or CPE Resources undergo a change in control other than a change in control caused by RTEA and within 180 days of such change in control RTEA no longer holds any units in CPE Resources, and we do not otherwise elect to terminate the Tax Receivable Agreement as discussed below, payments to RTEA under the Tax Receivable Agreement will continue on a yearly basis but will be based on an agreed upon set of assumptions. In this case, our assumed cash tax savings, and consequently our payments due under the Tax Receivable Agreement, could exceed our actual cash tax savings each year by material amounts. If we undergo such a change in control and our credit rating is impaired, we will be required to obtain credit support with regard to all remaining payments under the agreement. The change of control provisions may deter a potential sale of our company to a third party and may otherwise make it less likely a third party would enter into a change of control transaction with us.

        Certain asset transfers outside the ordinary course of our business may require us to make additional or accelerated payments under the Tax Receivable Agreement.    In addition to our obligations to make payments to RTEA with respect to our actual cash tax savings, if CPE Resources sells any asset with a gross value greater than $10 million outside the ordinary course of its business in a wholly or partially taxable transaction, we will be required to make yearly payments to RTEA equal to RTEA's deemed cost of financing its accelerated tax liabilities with respect to such sale, and after such asset sales, we will be required to make certain adjustments to the calculation of our actual cash tax savings for taxable years following sales or redemptions of RTEA's units in CPE Resources. These adjustments could result in an acceleration of our obligations under the Tax Receivable Agreement. In addition, our debt instruments contain limitations on CPE Resources' ability to make distributions, which could affect our ability to meet these payment obligations. These limitations on CPE Resources' ability to make distributions may limit our ability to engage in certain taxable asset sales or dispositions outside the ordinary course of our business.

        Default under the Tax Receivable Agreement will permit RTEA to accelerate our obligations.    If we default on our obligations under the Tax Receivable Agreement (including by reason of insufficient cash distributions from CPE Resources), such default will permit RTEA to enforce its rights under the Tax Receivable Agreement, including by acceleration of our obligations thereunder.

        Our ability to achieve benefits from any tax basis increase, and, therefore, the payments expected to be made under the Tax Receivable Agreement, depends upon a number of factors, as discussed above, including the timing and amount of our future income. The U.S. Internal Revenue Service could challenge one or more of our tax positions relevant to the Tax Receivable Agreement and a court could sustain such a challenge. Such a challenge could result in a decrease in our tax benefits, as well as our obligations under the Tax Receivable Agreement. We must obtain RTEA's consent prior to settlement of any such challenge if it may affect RTEA's rights and obligations under the Tax Receivable Agreement.

        For a description of our agreements with Rio Tinto and its affiliates, including the Tax Receivable Agreement, refer to the information included under the caption Certain Relationships and Related Transactions in our Proxy Statement to be distributed to our stockholders in connection with our 2010 annual meeting.

Our results as a separate, stand-alone public company will be significantly different from those portrayed in our historical financial results.

        The historical financial information for all periods prior to our IPO included in this report was derived from the consolidated financial statements of Rio Tinto and does not reflect what our financial position, results of operations, cash flows, costs or expenses would have been had we been a separate, stand-alone public company during those periods presented. Rio Tinto did not account for us, and we

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were not operated, as a separate, stand-alone public company for the historical periods presented prior to our IPO. The historical costs and expenses reflected in our consolidated financial statements also include allocations of certain general and administrative costs and Rio Tinto's headquarters costs. These expenses are estimates and were based on what we and Rio Tinto considered to be reasonable allocations of the historical costs incurred by Rio Tinto to provide these services required in support of our business.

        As a separate, stand-alone public company, our cost structure is different and includes both additional recurring costs and nonrecurring costs. Accordingly, our historical consolidated financial information is not reflective of our financial position, results of operations or cash flows or costs had we been a separate, stand-alone public company during all of the periods presented, and the historical financial information is not a reliable indicator of what our financial position, results of operations or cash flows will be in the future.

Rio Tinto may benefit from corporate opportunities that might otherwise be available to us.

        Rio Tinto holds certain coal assets in the U.S. and abroad, such as the Colowyo mine in Colorado. If Rio Tinto exercises its right to require CPE Resources to acquire by redemption all of their common membership units in CPE Resources and we use our assumption right to acquire their common membership units in exchange only for shares of our common stock, Rio Tinto would indirectly own approximately 48.3% of all outstanding shares of our common stock, based on our common stock outstanding as of December 31, 2009.

        Rio Tinto may expand, through development of its remaining coal business, acquisitions or otherwise, its operations that directly or indirectly compete with us. For one year following our IPO, RTEA and its affiliates will not pursue any competitive activity or acquisition in the coal industry within the PRB. Rio Tinto and its affiliates will not be prohibited from pursuing any competitive activity or acquisition outside of the PRB, whether during or after this one-year period, including selling coal or other goods produced outside of the PRB to customers located in the PRB or who are otherwise our customers. If a corporate opportunity is offered to Rio Tinto or its affiliates or any of Rio Tinto's or its affiliates' executive officers or directors that relates to any competitive activity or acquisition in the coal industry:

•

within the PRB after the one-year period referred to above; or



•

outside of the PRB,

no such person shall be liable to us or any of our shareholders for breach of any fiduciary or other duty unless the business opportunity is expressly offered to the director or executive officer in his or her capacity as an executive officer or director of us.

        In addition, Rio Tinto may have other business interests and may engage in any other businesses not specifically prohibited which could compete with us, and these potential conflicts of interest could have a material adverse effect on our business, financial condition, results of operations or prospects.

Our directors and executive officers have potential conflicts of interest with us and your interests as shareholders.

        Preston Chiaro, one of our directors, is also an executive officer of Rio Tinto or its affiliates. Mr. Chiaro owes fiduciary duties to our shareholders, which may conflict with his role as an executive officer of Rio Tinto or its affiliates. As a result, in connection with any transaction or other relationship involving both companies, Mr. Chiaro may, but is not required to, recuse himself and would therefore not participate in any board action relating to these transactions or relationships.

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        Both Colin Marshall, our chief executive officer and a director, and Mr. Chiaro own shares of Rio Tinto or options to purchase Rio Tinto common stock. Mr. Barrett, Mr. Orchard, Mr. Rivenes and Mr. Taylor, who are also our executive officers, own shares of Rio Tinto or options to purchase Rio Tinto common stock. These ownership interests may be of greater value than their ownership of our common stock. Ownership of Rio Tinto shares by our directors and executive officers could create, or appear to create, potential conflicts of interest when directors and executive officers are faced with decisions that could have different implications for Rio Tinto or its affiliates than they do us.

        Prior to our IPO, at the time of agreeing to certain matters related to our IPO and IPO Structuring Agreements, Cloud Peak Energy Inc. was a wholly-owned subsidiary of Rio Tinto. As a result, the Cloud Peak Energy Inc. directors at that time owed a fiduciary duty solely to Rio Tinto in its capacity as the sole owner of Cloud Peak Energy Inc. and did not owe a fiduciary duty to our post-IPO stockholders. Keith Bailey, William T. Fox III and Chris Tong, all of whom are current "independent" directors of Cloud Peak Energy Inc. under applicable NYSE rules, were also Cloud Peak Energy Inc. directors prior to our IPO and therefore owed a fiduciary duty to Rio Tinto. Upon the effectiveness of our IPO in November 2009, Rio Tinto's ownership of Cloud Peak Energy Inc. was terminated and, accordingly, Messrs. Bailey, Fox and Tong no longer owe a fiduciary duty to Rio Tinto.

Our agreements with Rio Tinto and its affiliates related to our IPO are likely less favorable to us than similar agreements negotiated between unaffiliated third parties.

        We entered into various agreements with Rio Tinto and its affiliates in connection with our IPO which address, among other things, the allocation of assets and liabilities between Rio Tinto and us, responsibility for the disclosures made in our IPO prospectus and in the offering memorandum used in the senior notes offering, our obligation to provide Rio Tinto financial information needed for its public filings, certain ongoing commercial relationships and our responsibility as the manager of CPE Resources to Rio Tinto as a non-managing member. CPE Resources has agreed to indemnify Rio Tinto for any losses experienced pursuant to these agreements, in certain instances on a dollar-for-dollar basis and in certain other instances by providing additional indemnification calculated on a dollar-for-dollar basis plus a fraction of a dollar equal to the ownership interest of Rio Tinto and its affiliates in CPE Resources at the time the indemnity is payable to Rio Tinto. Because these agreements were entered into while we were part of Rio Tinto, some of the terms of these agreements are likely less favorable to us than similar agreements negotiated between unaffiliated third parties. For a description of our agreements with Rio Tinto and it affiliates, refer to the information included under the caption Certain Relationships and Related Transactions in our Proxy Statement to be distributed to our stockholders in connection with our 2010 annual meeting.

Third parties may seek to hold us responsible for liabilities of Rio Tinto that we did not assume.

        Third parties may seek to hold us responsible for liabilities of Rio Tinto that we did not assume in connection with our IPO, including liabilities related to the Jacobs Ranch and Colowyo mines, as well as the uranium mining venture that we do not own. Under the IPO Structuring Agreements, Rio Tinto America will indemnify us for certain claims and losses relating to these liabilities. If those liabilities are significant and we are ultimately held liable for them, we may not be able to recover the full amount of our losses from Rio Tinto America.

We are a holding company with no direct operations of our own and depend on distributions from CPE Resources to meet our ongoing obligations.

        We are a holding company with no direct operations of our own and have no independent ability to generate revenue. Consequently, our ability to obtain operating funds depends upon distributions from CPE Resources and payments under our management services agreement. Pursuant to a management services agreement between us and CPE Resources, CPE Resources will make payments

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to us in the form of a management fee and cost reimbursements to fund our day-to-day operating expenses, such as payroll for our officers. However, if CPE Resources cannot make the payments pursuant to the management services agreement, we may be unable to cover these expenses.

        The distribution of cash flows by CPE Resources to us will be subject to statutory restrictions under the Delaware Limited Liability Company Act and contractual restrictions under CPE Resources' debt instruments that may limit the ability of CPE Resources to make distributions. In addition, any distributions and payments of fees or costs will be based upon CPE Resources' financial performance. Any distributions of cash will be made on a pro-rata basis to all holders of units in CPE Resources, including us, Rio Tinto in accordance with each holders' respective percentage interest.

        As a member of CPE Resources, we will incur income taxes on our allocated share of any net taxable income of CPE Resources. Our debt instruments allow CPE Resources to distribute cash pro rata to its members (including us and RTEA) in amounts sufficient for us to pay our tax liabilities payable to any governmental entity, and, in the ordinary course of business, our obligations under our tax receivable agreement, if any. To the extent we need funds for any other purpose, and CPE Resources is unable to provide such funds because of limitations in its debt instruments, it could have a material adverse effect on our business, financial condition, results of operations or prospects.

Rio Tinto or its affiliates may have interests that differ from your interests as stockholders and they have specified consent rights in CPE Resources.

        As of December 31, 2009, Rio Tinto indirectly owns approximately 48.3% of the common membership units in CPE Resources. It also has consent rights over certain actions by us or CPE Resources. Rio Tinto's interests may differ from your interests as stockholders, and Rio Tinto may not consent to us or CPE Resources taking certain actions that are in your interests as stockholders. In general, so long as Rio Tinto owns, directly or indirectly, at least 30% of the common membership units of CPE Resources that were outstanding as of the effective date of our IPO, Rio Tinto's consent will be required prior for any of the following actions:

•

approval of any transaction that would result in a change of control of us, including CPE Resources, or a change in the manager of CPE Resources;



•

the merger, consolidation, dissolution or liquidation of CPE Resources or any merger, consolidation, dissolution or liquidation of any subsidiary of CPE Resources (with customary exceptions);



•

the direct or indirect sale, transfer, lease or other disposition of property or assets (including capital stock of any subsidiary) of CPE Resources and its subsidiaries outside of the ordinary course of business in excess of $500 million;



•

any fundamental change outside of the ordinary course in the nature (but not size or methods) of CPE Resources' coal business as in effect as of the effective date of our IPO, but only insofar as such fundamental change does not relate to the normal operation or activities of CPE Resources' coal business or any business or operation reasonably related or ancillary to CPE Resources' business;



•

the acquisition of any other business or asset that has a purchase price in excess of $500 million or that would result in the issuance of equity interests by us or CPE Resources in excess of $500 million;



•

the assumption, incurrence or issuance of indebtedness in excess of 125% of the indebtedness amounts included in CPE Resources' operating plan, other than indebtedness to fund ordinary course business operations or to fund any capital expenditures that do not require Rio Tinto's consent;

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•

making or committing to make, in any calendar year period, capital expenditures outside the ordinary course of business; provided that the following capital expenditures shall be deemed to be in the ordinary course of business (x) committed LBA payments included in CPE Resources' operating plan and (y) the aggregate amount of all other capital expenditures not in excess of 125% of the sum of (1) uncommitted LBA payments included in CPE Resources' operating plan, (2) non-LBA capital payments included in CPE Resources' operating plan and (3) the cumulative amount by which the actual capital expenditures in preceding years for capital expenditures other than committed LBA payments is less than the sum of total uncommitted LBA payments and non-LBA payments for the prior years; and



•

except as otherwise set forth in any other structuring-related agreement, settling claims as to which Rio Tinto would have liability.

        The consent of Rio Tinto, as a non-managing member of CPE Resources, is required for any amendment to the limited liability company agreement until Rio Tinto owns less than 10% of the common membership units of CPE Resources that were outstanding on the effective date of our IPO. Further, if Rio Tinto owns any common membership units, we will generally be prohibited from causing CPE Resources to make tax elections or take positions on tax issues that we know or would reasonably be expected to know would harm Rio Tinto.

Any future redemption by Rio Tinto or Cloud Peak Energy of common membership units in CPE Resources in exchange for shares of our common stock will significantly dilute your voting power.

        Pursuant to the terms of the LLC agreement, Rio Tinto has the right to have their common membership units acquired by means of redemption by CPE Resources in exchange for a cash payment equal to, on a per unit basis, the market price of one share of our common stock. If Rio Tinto exercises their redemption right, we will be entitled to assume CPE Resources' rights and obligations to acquire common membership units from Rio Tinto and elect to acquire such in exchange for, at our determination, shares of our common stock on a one-for-one basis or a cash payment equal to, on a per unit basis, the market price of one share of our common stock or a combination of both. We refer to this entitlement as our "assumption right". In addition, if the Rio Tinto members own in the aggregate less than 5% of the common membership units of CPE Resources that were outstanding as of the effective date of our IPO, CPE Resources will have the right to acquire by redemption all of the common membership units then held by the Rio Tinto members for a cash payment equal to, on a per unit basis, the market price of one share of our common stock. We maintain the same right to assume CPE Resources' rights and obligations to acquire the common membership units from the Rio Tinto members as described above. We refer to this entitlement as our "CPE redemption assumption right."

        As of December 31, 2009, Rio Tinto America indirectly held 48.3% of the common membership units in CPE Resources. If Rio Tinto exercises its redemption right with respect to a significant number of common membership units and we elect to exercise our assumption right and issue common stock rather than cash, the voting power of our stockholders would be significantly diluted. For example, if Rio Tinto exercises their right to require CPE Resources to acquire by redemption all of their common membership units in CPE Resources and we use our assumption right to acquire their common membership units in exchange only for shares of our common stock, Rio Tinto America would indirectly own approximately 48.3% of all outstanding shares of our common stock as of December 31, 2009. Any such occurrence, whether it occurs through our CPE redemption assumption right or our assumption right as described above, could result in Rio Tinto retaining significant influence over decisions that require the approval of our stockholders (such as the election of our directors) regardless of whether our other stockholders believe that such decisions are in our own best interests.

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If we are determined to be an investment company, we would become subject to burdensome regulatory requirements and our business activities could be restricted.

        We do not believe that we are an "investment company" under the Investment Company Act of 1940, as amended. As managing member of CPE Resources, we control CPE Resources and believe our interest in CPE Resources is neither a "security" nor an "investment security," as those terms are defined in the Investment Company Act. If we were to stop participating in the management of CPE Resources, our interest in CPE Resources could be deemed an "investment security" for purposes of the Investment Company Act. Generally, a company is an "investment company" if it owns investment securities having a value exceeding 40% of the value of its total assets (excluding U.S. government securities and cash items). Our sole asset is our managing membership interest in CPE Resources. A determination that this interest is an investment security could result in our being considered an investment company under the Investment Company Act. As a result, we would become subject to registration and other burdensome requirements of the Investment Company Act. In addition, the requirements of the Investment Company Act could restrict our business activities, including our ability to issue securities.

        We and CPE Resources intend to conduct our operations so that we are not deemed an investment company under the Investment Company Act. However, if anything were to occur that would cause us to be deemed to be an investment company, we would become subject to restrictions imposed by the Investment Company Act. These restrictions, including limitations on our capital structure and our ability to enter into transactions with our affiliates, could make it impractical for us to continue our business as currently conducted and could have a material adverse effect on our financial performance and operations.

Future sales of our common stock or other securities convertible into our common stock could cause our stock price to decline.

        Sales of substantial amounts of our common stock in the public market, including by Rio Tinto if they exercise their right to require CPE Resources to acquire by redemption their common membership units and we choose to issue shares of our common stock, or the perception that these sales may occur, could cause the market price of our common stock to decrease significantly.

        As part of our IPO, Rio Tinto entered into a lock-up agreement that prevents the redemption of their common membership units of CPE Resources for up to 180 days after the date of our IPO, subject to certain carve outs and an extension in certain circumstances. This lock-up agreement may be waived sooner than 180 days by the underwriters from our IPO. Following the expiration or any earlier waiver of the lock-up, Rio Tinto will have the right, subject to certain conditions, to require us to register under the federal securities laws the sale of any shares of our common stock that may be issued to and held by them in connection with our assumption right. We may also offer additional shares of our common stock to the public in order to satisfy a redemption request by Rio Tinto with cash in connection with our assumption right or for other corporate purposes. In addition, we have granted Rio Tinto and their permitted transferees certain "piggyback" registration rights, which allow them to include their shares in any future registrations of our equity securities, whether that registration relates to a primary offering by us or a secondary offering by or on behalf of any of our stockholders. In particular, during the first three years following our IPO, Rio Tinto will have priority over us and any other of our stockholders in any registration that is an underwritten offering. Any such filing or the perception that such a filing may occur, could cause the prevailing market price of our common stock to decline and may impact our ability to sell equity to finance the operations of CPE Resources or make strategic acquisitions.

        A decline in the trading price of our common stock due to the occurrence of any future sales might impede our ability to raise capital through the issuance of additional shares of our common stock

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or other equity securities and may cause you to lose part or all of your investment in our shares of common stock.

Anti-takeover provisions in our charter documents and other aspects of our structure, including Rio Tinto's substantial holdings in CPE Resources and its rights to approve a change in control of CPE Resources or us or a change in the manager of CPE Resources could discourage, delay or prevent a change in control of our company and may adversely affect the trading price of our common stock.

        Certain provisions in our amended and restated certificate of incorporation and amended and restated bylaws and other aspects of our structure, including Rio Tinto's substantial holdings in CPE Resources and its rights to approve a change in control of CPE Resources or us, or a change in the manager of CPE Resources may discourage, delay or prevent a change in our management or a change in control over us that stockholders may consider favorable. Among other things, our amended and restated certificate of incorporation and amended and restated bylaws:

•

provide for a classified board of directors, which may delay the ability of our stockholders to change the membership of a majority of our board of directors;



•

authorize the issuance of "blank check" preferred stock that could be issued by our board of directors to thwart a takeover attempt;



•

do not provide for cumulative voting;



•

provide that vacancies on the board of directors, including newly created directorships, may be filled only by a majority vote of directors then in office;



•

limit the calling of special meetings of stockholders;



•

provide that stockholders may not act by written consent;



•

provide that our directors may be removed only for cause;



•

require supermajority voting to effect certain amendments to our certificate of incorporation and our bylaws; and



•

require stockholders to provide advance notice of new business proposals and director nominations under specific procedures.

        In addition, CPE Resources' limited liability agreement requires that we conduct all our business operations through CPE Resources.

Item 1B.    Unresolved Staff Comments.

        None

Item 2.    Properties.

        See Item 1 "Business—Mining Operations" for specific information about our mining operations.

Coal Reserves

        As of December 31, 2009, we controlled approximately 1.0 billion tons of proven and probable coal reserves. All of our proven and probable reserves are classified as steam coal.

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        The following table summarizes the tonnage of our coal reserves that is classified as proven or probable, and assigned, as well as our property interest, as of December 31, 2009:

        The following table provides the "quality" (sulfur content and average Btu content per pound) of our coal reserves as of December 31, 2009:

        We also control certain coal deposits that are contiguous to or near our primary reserve bases. The tons in these deposits are classified as non-reserve coal deposits and are not included in our reported reserves. These non-reserve coal deposits are as follows:

Antelope Mine:          80 million tons

Cordero Rojo Mine:  175 million tons

        Our reserve and non-reserve coal deposit estimates as of December 31, 2009 were prepared by our staff of geologists and engineers, who have extensive experience in PRB coal. These individuals are responsible for collecting and analyzing geologic data within and adjacent to leases controlled by us.

        Prior to our IPO, our coal reserve reporting process was reviewed by Rio Tinto and a complete review of our 2008 reserves assessments was completed in April 2009 by John T. Boyd Company, mining and geological consultants, and covered our reserves as of December 31, 2008. While we intend to periodically retain outside experts to independently verify our estimates of our coal reserves going forward, our estimates of proven and probable reserves as of December 31, 2009 were prepared by our staff of geologists and engineers, whose experience ranges from 9 to over 30 years. We also have a chief manager of geology whose primary responsibility is to track changes in reserve estimates,

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supervise our other geologists and coordinate periodic third-party reviews of our reserve estimates by qualified mining consultants.

        Our coal reserve estimates are based on data obtained from our drilling activities and other available geologic data. All of our reserves are assigned, associated with our active coal properties, and incorporated in detailed mine plans. Estimates of our reserves are based on an excess of 8,500 drill holes. Our proven reserves have a typical drill hole spacing of 1,500 feet or less, and our probable reserves have a typical drill hole spacing of 2,500 feet or less.

        Along with the geological data we assemble for our coal reserve estimates, our staff of geologists and engineers also analyzes the economic data such as cost of production, projected sales price and other data concerning permitting and advances in mining technology. Various factors and assumptions are utilized in estimating coal reserves, including assumptions concerning future coal prices and operating costs. These estimates are periodically updated to reflect past coal production and other geologic or 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. We maintain reserve information in secure computerized databases, as well as in hard copy.

Reserve Acquisition Process

        Since our inception, we have focused on growth through, among other things, the federal competitive leasing process, including the LBA process, and we continue to identify federal coal leasing opportunities. For example, in 2007 we acquired 107.5 million tons of reserves in an LBA for our Spring Creek mine. In addition, in 2008 we acquired 161 million tons of reserves in an LBA for our Cordero Rojo mine. Similarly, in May 2009 we acquired an additional 48 million tons of reserves with the North Maysdorf LBA tract, for our Cordero Rojo mine.

        We acquire a significant portion of our coal through the LBA process, and as a result, substantially all of our coal is held under federal leases. Under this process, before a mining company can obtain new federal coal, the company must nominate a coal tract for lease and then 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 and begins the process to permit the coal for mining, which generally takes another two to five years.

        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 whether 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.

        The BLM also allows for small tracts of coal to be acquired through a leasing process known as a Lease by Modification, or LBM. An LBM is a non-competitive leasing process and is used in circumstances where a lessee is seeking to modify an existing federal coal lease by adding less than 960 acres in a configuration that is deemed non-competitive to other coal operators. We have nominated an LBM area at our Spring Creek mine.

        If the BLM determines to continue the application, the company that submitted the application will pay for a BLM-directed environmental analysis or an EIS to be completed. This analysis or impact statement is subject to publication and public comment. The BLM may consult with other government

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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 EIS 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 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 EIS, 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 next complete the permitting process before it can mine the coal. See "—Environmental and Other Regulatory Matters—Mining Permits and Approvals."

        Each of our federal coal leases has an initial term of 20 years, renewable for subsequent 10-year periods and for so long thereafter as coal is produced in commercial quantities. The lease requires diligent development within the first ten years of the lease award with a required coal extraction of 1% 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, or 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. We currently have an LMU for our Antelope mine. We pay to the federal government an annual rent of $3.00 per acre and production royalties of 12.5% of gross revenues on surface mined coal. The federal government remits approximately 50% of the production royalty payments to the state after deducting administrative expenses. Some of our mines are also subject to coal leases with the states of Montana or Wyoming, as applicable, 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.

        Most of the coal we lease from the United States comes from "split estate" lands in which one party, typically the federal government, owns the coal and a private party owns the surface. In order to mine the coal we acquire through the LBA process, we must also acquire rights to mine from the owners of the surface lands overlying the coal. Certain federal regulations provide a specific class of

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surface owners, Qualified Surface Owners, or QSOs, with the ability to prohibit the BLM from leasing its coal. If the land overlying a coal tract is owned by a QSO, federal laws prohibit us from leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO, which would allow us to conduct our mining operations. Furthermore, the state permitting process requires us to demonstrate surface owner consent for split estate lands before the state will issue a permit to mine coal. This consent is separate from the QSO consent required before leasing federal coal. The right of QSOs and certain other surface owners allows them to exercise significant influence over negotiations and prices to acquire surface rights and can delay the LBA or permitting processes or ultimately prevent the acquisition of the LBA or permit over that land entirely. There are QSOs that own land adjacent to or near our existing mines that may be attractive acquisition candidates for us. Typically, we seek to purchase the land overlying our coal or enter into option agreements granting us an option to purchase the land upon acquiring an LBA. In some instances, however, we enter into separate lease arrangements with surface owners allowing us to conduct our mining operations on the land. We own substantially all of the land over our reserves.

        We also enter into surface leases with other third parties from time to time. The majority of these third-party leases have a term that continues until the exhaustion of the "mineable and merchantable" coal in the lease area. Some of our leases extend for a specific number of years rather than to the exhaustion of the particular mine's reserves, but in all these cases, we believe that the term of years will allow the recoverable reserve to be fully extracted in accordance with our projected mine plan. Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing. Title to properties leased from private third parties is not usually fully verified until we make a commitment to develop a property, which may not occur until we have obtained the necessary permits and completed exploration of the property.

Office Space

        Our corporate headquarters is located in Gillette, Wyoming, where we own approximately 32,000 square feet of office space. In addition, we lease approximately 7,500 square feel of additional office space in Gillette, Wyoming, under two annual leases expiring on June 30, 2010 and May 31, 2010, and we sublease approximately 13,000 square feet of office space in Greenwood Village, Colorado under a sublease that expires on January 1, 2011. As of December 31, 2009, all of our long-lived assets were located in the U.S. See Note 18 of Notes to Consolidated Financial Statements in Item 8.

Item 3.    Legal Proceedings.

MMS Litigation—Decker

        The Minerals Management Service, or MMS, a federal agency with responsibility for collecting royalties on coal produced from federal coal leases, issued two disputed assessments against Decker Coal Company: one for coal produced from 1986-1992, and the other for coal produced from 1993-2001. Both assessments concern coal sold by Decker to Big Horn Coal Company, or Big Horn, and Black Butte Coal Company, or Black Butte, and in turn resold by those entities to Commonwealth Edison Company to satisfy requirements under long-term contracts between those entities and Commonwealth Edison. The MMS maintained that Decker's royalties should not be based on the prices at which Decker actually sold coal to Big Horn and Black Butte because MMS does not believe those prices represent the results of arm's length negotiation. MMS based this conclusion on the facts that those entities were both affiliates of KCP, Inc., formerly known as Kiewit Coal Properties, Inc., which is also a 50% owner of Decker, and that the sales were contingent on Big Horn's and Black Butte's ability to resell the coal to Commonwealth Edison, which did not leave Big Horn and Black Butte at market risk. Instead, the MMS assessed Decker's royalties based on the higher prices set under Big Horn's and Black Butte's separate long-term contracts with Commonwealth Edison.

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        With respect to the period 1986-1992, Decker appealed the assessment through the administrative process with the MMS and that appeal was unsuccessful. A further appeal was filed before the United States District Court for the District of Montana. In March 2009, the District Court set aside the MMS assessment and entered judgment for Decker (Decker I). MMS did not appeal that ruling.

        With respect to the period 1993-2001, the MMS has not issued a final decision concerning Decker's challenge to the assessment. On January 5, 2009, the Interior Board of Land Appeals, or IBLA, issued a decision affirming the MMS's decision requiring Decker to pay additional royalties. On February 16, 2010, the United States District Court for the District of Montana vacated the IBLA decision and remanded the matter to the MMS for further administrative review in light of the District Court's holding in Decker I. As of December 31, 2009, the estimated additional assessed royalties (inclusive of interest) for the period 1993-2001 were approximately $11 million. Decker estimates that even if the assessment for the 1993-2001 period were to be upheld, MMS's eventual recovery may be nothing but could be up to $11 million.

        We have not accrued a liability in our consolidated financial statements with respect to this matter as any potential losses are not considered to be probable and reasonably estimable. In addition to its substantive challenges to the assessments, Decker believes that it has contractual price escalation protection from any increased assessments for 1993-2001; that, in addition, Commonwealth Edison has indemnified Black Butte with respect to the 1993-2001 assessment, and that in furtherance of that obligation, Commonwealth Edison or its parent company, Exelon Generation, Inc., has therefore agreed to indemnify Decker directly for such matters. If the assessment was upheld and the indemnities and/or price protections were ultimately not available to Decker, the resulting Decker liability could be material. As a result of our 50% ownership interest in Decker, our financial results could in turn be materially adversely affected. We consider those conclusions to be reasonable; however, we have not relied upon this indemnification in reaching our decision that any potential losses are not considered probable and reasonably estimable.

Caballo Coal Company Litigation—Spring Creek

        In September 2009, Caballo Coal Company, or Caballo, a subsidiary of Peabody Energy Corporation, commenced an action in Wyoming state court against Spring Creek Coal Company, or Spring Creek, our wholly-owned subsidiary, asserting that Spring Creek repudiated its allegedly remaining obligation under a 1987 agreement to purchase an additional approximately 1.6 million tons of coal, for which it seeks unspecified damages. Spring Creek believes that it has meritorious defenses to the claim, including that Caballo breached the agreement by failing to make required deliveries in 2006 and 2007. Spring Creek also believes that it has meritorious counterclaims against Caballo. If, however, the case was determined in an adverse manner to us, the payment of any judgment could be material to our results of operations.

Other Legal Proceedings

        We are currently involved in other legal proceedings arising in the ordinary course of business and may become involved in additional proceedings from time to time. We believe that there are no other legal proceedings pending that are likely to have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Nevertheless, we cannot predict the impact of future developments affecting our claims and lawsuits, and any resolution of a claim or lawsuit or an accrual within a particular fiscal period may adversely impact our results of operations for that period.

Item 4.    Reserved.

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PART II

Item 5.    Market for Registrant's Common Equity and Related Stockholder Matters.

        The registration statement for the initial public offering of 30,600,000 shares of our common stock was declared effective on November 19, 2009, and our common stock began trading on a "when issued" basis on November 20, 2009. We completed our initial public offering and issued our common shares to the public on November 25, 2009. The net proceeds from the offering were used to repay a promissory note that was issued on November 19, 2009 in exchange for a 51% managing member interest in CPE Resources. Our common stock is listed on the NYSE, under the symbol "CLD." As of February 28, 2010, there were 1,540 holders of record of our common stock.

        The high and low sales price for our common stock on the NYSE for the period from November 20, 2009 to December 31, 2009 was $17.51 and $12.53, respectively. The closing sale price on December 31, 2009 was $14.56.

Dividend Policy

        We have not and we do not anticipate that we will pay cash dividends on our common stock in the near term. Any determination to pay dividends to holders of our common stock in the future will be at the discretion of our Board of Directors and will depend on many factors, including our financial condition; results of operations; general business conditions; contractual restrictions, including those under our debt instruments and the CPE Resources limited liability company agreement; capital requirements; business prospects; restrictions on the payment of dividends under Delaware Law; and any other factors our Board of Directors deems relevant. See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations—Senior Unsecured Notes and—Senior Secured Revolving Credit Facility."

Stock Performance Graph

        The following performance graph compares the cumulative total return on our common stock with the cumulative total return of the following indices: (i) the Standard & Poor's ("S&P") MidCap 400 stock index and (ii) the Custom Composite Index comprised of Alpha Natural Resources, Inc., Arch Coal, Inc., CONSOL Energy, Inc., Massey Energy Company and Peabody Energy Corp. The graph assumes that you invested $100 in our common stock and in each index at the closing price on November 20, 2009, that all dividends were reinvested and that you continued to hold your investment through December 31, 2009.

        These indices are included for comparative purposes only and do not necessarily reflect management's opinion that such indices are an appropriate measure of the relative performance of the stock involved, and are not intended to forecast or be indicative of possible future performance of our common stock.

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CUMULATIVE TOTAL RETURN
Based upon an initial investment of $100 on November 20, 2009
with dividends reinvested

        In accordance with SEC rules, the information contained in the Stock Performance Graph above shall not be deemed to be "soliciting material," or to be "filed" with the SEC or subject to the SEC's Regulation 14A or 14C, other than as provided under Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended, except to the extent that we specifically request that the information be treated as soliciting material or specifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.

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Item 6.    Selected Financial Data.

        The following tables set forth selected consolidated financial and other data on a historical basis. The information below should be read in conjunction with Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Item 8 "Financial Statements and Supplementary Data" included elsewhere in this report.

        We have derived the historical consolidated financial data as of December 31, 2009 and 2008 and for each of the three years in the period ended December 31, 2009 from our audited consolidated financial statements included in Item 8 of this report. We have derived the historical consolidated balance sheet data as of December 31, 2007 and 2006 and the historical consolidated statement of operations data for the year ended December 31, 2006 from the audited consolidated financial statements of RTEA not included in this report. We have derived the historical consolidated financial data as of December 31, 2005 and for the year then ended from the unaudited consolidated financial statements of RTEA not included in this report.

        The historical financial information for all periods prior to our IPO included in this report was derived from the consolidated financial statements of RTEA and does not reflect what our financial position, results of operations, and cash flows would have been had we been a separate, stand-alone public company during those periods. We were not operated as a separate, stand-alone public company for the historical periods presented prior to our IPO. The historical costs and expenses reflected in our consolidated financial statements include allocations of certain general and administrative expenses incurred by Rio Tinto America and other Rio Tinto affiliates. We believe these allocations were reasonable; however the allocated expenses are not necessarily indicative of the expenses that would have been incurred if we had been a separate, independent entity.

        As a separate, stand-alone public company, our cost structure is different. It includes both additional recurring costs and nonrecurring costs. Accordingly, our historical consolidated financial information is not reflective of our financial position, results of operations or cash flows had we been a separate, stand-alone public company during all of the periods presented, and is not a reliable indicator of what our financial position, results of operations or cash flows will be in the future.

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Selected Consolidated Financial and Other Data

 

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