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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 Resources LLC

(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: None

Securities Registered Pursuant to Section 12(g) of the Act: None

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

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

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 x  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 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. x

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 x

At February 28, 2011, all of the outstanding common membership units of Cloud Peak Energy Resources LLC were held by Cloud Peak Energy Inc.

DOCUMENTS INCORPORATED BY REFERENCE

None

Cloud Peak Energy Resources LLC meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form with the reduced disclosure format.

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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:

·                  future economic conditions;

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

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

·                  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;

·                  future legislation, changes in regulations or governmental policies or changes in interpretations thereof, and third-party regulatory challenges, including with respect to carbon emissions, safety standards and regulatory processes and approvals required to lease and obtain permits for coal mining operations or to transport coal to domestic and foreign customers;

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

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

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

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

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

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

·                  timing of reductions or increases in customer coal inventories;

·                  risks inherent to surface coal mining;

·                  weather conditions or catastrophic weather-related damage;

·                  changes in energy policy;

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·                  competition;

·                  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;

·                  railroad, export terminal capacity and other transportation performance, costs and availability;

·                  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;

·                  our assumptions concerning coal reserve estimates;

·                  the terms of Cloud Peak Energy Resources LLC’s indebtedness;

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

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

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

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

·                  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.

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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 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 x 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 as determined by the BLM.  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.

NOx.  Nitrogen oxides.  NOx 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 (the “SEC”) standards until a final comprehensive evaluation based on unit cost per ton, 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.

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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.

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.

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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.  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:

·                  “Cloud Peak Energy,” “we,” “us,” “our” or the “Company” refer collectively to Cloud Peak Energy Resources LLC (“CPE Resources”), a Delaware limited liability company, formerly known as Rio Tinto Sage LLC, and its consolidated subsidiaries;

·                  “Holdings” or the “manager” refers to Cloud Peak Energy Inc., a Delaware corporation and a holding company whose only business and material asset is its managing member interest in us;

·                  “IPO Structuring Agreements” refers to the following agreements entered into in connection with Holdings’s initial public offering (the “IPO”):  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.  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, Related IPO Structuring Transactions, and Secondary Offering” in Note 2 of Notes to Consolidated Financial Statements in Item 8; and

·                  “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” or “Rio Tinto America”), which is the owner of RTEA and KMS.

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PART I

Item 1.  Business.

Overview

We are the third largest producer of coal in the U.S. and in the Powder River Basin, or PRB, based on our 2010 coal production of 95.3 million tons.  We had revenues from our continuing operations of $1.4 billion in 2010.  We operate some of the safest mines in the industry.  According to Mine Safety and Health Administration, or MSHA, data, in 2010 we had one of the lowest employee all injury incident rate among the 10 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 47 customers with over 108 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 2010, the coal we produced generated approximately 4% of the electricity produced in the U.S.  As of December 31, 2010, we controlled approximately 970 million tons of proven and probable reserves.

We are a wholly-owned subsidiary of Cloud Peak Energy Inc.  Cloud Peak Energy Inc., a Delaware corporation organized on July 31, 2008, is a holding company that has no business operations or material assets other than its ownership interest as of December 31, 2010 of 100% of the common membership units in CPE Resources as discussed more fully in “History” below.  Holdings’s only source of cash flow from operations is distributions from us pursuant to the CPE Resources limited liability company agreement.  Holdings also receives management fees pursuant to a management services agreement between us and Holdings as reimbursement of certain administrative expenses.

History

We were formed 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 the 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 the IPO on November 25, 2009.

On December 15, 2010, Cloud Peak Energy Inc. priced a secondary offering of 29,400,000 shares of its common stock on behalf of Rio Tinto (the “Secondary Offering”).  In connection with the Secondary Offering, Cloud Peak Energy Inc. exchanged 29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the Secondary Offering, resulting in a divestiture of 100% of Rio Tinto’s holdings in CPE Resources.  As a result of this transaction, CPE Resources is now a wholly-owned subsidiary of Cloud Peak Energy Inc.

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The following condensed diagram depicts our organizational structure as of December 31, 2010:

(1) Operated together as the Cordero Rojo mine.

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.

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.

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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 314 GW, utilities accounting for a capacity of over 168 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 content of the post-combustion 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 35% 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.

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.  Trucks and shovels 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 92% or more of the economic coal seam for 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

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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 the majority 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, 2010.

(1)           Based on the respective mine’s current air quality permit restrictions.

(2)           Post-combustion ash from Spring Creek coal contains an average of approximately 8% sodium oxide. Earthen materials can be selectively blended with the coal within the crushing facility to reduce the post-combustion sodium level and enable the production of a range of products tailored for customers requiring lower sodium levels.

(3)           Tons sold numbers reflect our 50% interest in the Decker mine.

(4)           The tonnage shown for “Other” represents our purchases from third-party sources that we have resold, including coal we have purchased and resold from the Jacobs Ranch mine, which our predecessor used to own. See “—Customers and Coal Contracts—Broker Sales and Third-Party Sources.”

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.

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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 an LBA, a large coal tract adjacent to our existing operation.  The 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, subject to the outcome of legal challenges filed in 2010 against the BLM and the Secretary of the Interior by environmental organizations with respect to the EIS and other matters associated with the West Antelope II LBA.  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 we now believe the BLM will schedule for lease in 2011 or 2012.  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.

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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 export terminals in the Pacific northwest, 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 2010, we shipped approximately 3.3 million tons of Spring Creek coal through the Westshore terminal.  In June 2010, we entered into a Modified Coal Lease (the “Lease Modification”) with the BLM.  The Lease Modification modified Coal Lease MTM-069782 (the “Existing Lease”) and added approximately 48 million tons of proven and probable reserves to the Existing Lease.

Decker Mine

The Decker mine is located immediately to the southeast of our Spring Creek mine in Montana.  We own a non-operating 50% interest in the mine.  The Decker mine is a union based operation; however, we do not employ any of the Decker mine employees.  A third party operates the Decker mine for us and the other 50% owner 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.  In April 2010, the Decker mine entered into a coal sales contract that will extend production and mine life into 2013.  The operator continues to seek commercial market opportunities for additional leased and permitted coal tonnage at the Decker mine.

Customers and Coal Contracts

We focus on building long-term relationships with customers through our reliable performance and commitment to customer service.  We supply coal to over 47 electric utilities and over 91% of our sales were to customers with an investment grade credit rating as of December 31, 2010.  Furthermore, over 72% of our 2010 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:

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

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

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

As of December 31, 2010, we had 17 employees in our sales and marketing department.

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Customers

Our primary customers are domestic utility companies with over 108 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 2010.  During 2010, approximately 49% of our revenues were derived from our top 10 customers.  No customer accounted for 10% or more of our revenues in 2010.  The following map shows the percentage of our shipped tons of coal by state of destination during 2010 from coal produced at the three mines we own and operate.  We also exported approximately 4% of the tons produced at these mines in 2010.

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, 2010, approximately 64% 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, 2010, 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 10 years.

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.

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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 certain contracts covering 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 that 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 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.

Our coal sales agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers for 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 transaction or transactions under the agreement.  Some contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer.

Agreements between our customers and the railroads servicing our mines may also contain force majeure provisions.  Generally, our coal sales agreements allow our customer to suspend performance in the event that the railroad fails to provide its services due to circumstances that would constitute a force majeure.

In 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, was 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

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were all executed, our selling price for the coal was higher than our purchasing price.  Under this contract, we sold approximately 6.8 million tons per year.  This broker sales contract contributed $13.7 million of revenues in 2010.  The contract expired following final deliveries under the contract in the first quarter of 2010.  See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview.”

For delivery during the year ended December 31, 2010, we purchased 1.7 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 heavy mobile equipment, 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 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—Increases in the cost of 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 consumables.  Since the IPO, we are not a party to any Rio Tinto supply contracts other than those transferred to us as part of the IPO.  While some of our heavy mobile equipment supplies and equipment are still being delivered under purchase orders entered into prior to the 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. and, for our export sales, internationally.  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, 2010, we had 1,524 full-time 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

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we have good relations with our employees.  As of December 31, 2010, we had 250 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 Rio Tinto Energy America Inc. (“RTEA”), an indirect subsidiary of Rio Tinto plc and the former parent company of Cloud Peak Energy Resources LLC, from June 2006 until November 2009.  From March 2004 to May 2006, Mr. Marshall served as General Manager of Rio Tinto’s Pilbara Iron’s west Pilbara iron ore operations in Tom Price, West Australia, from June 2001 to March 2004, he served as General Manager of RTEA’s Cordero Rojo mine in Wyoming and from August 2000 to June 2001, he served as Operations Manager of RTEA’s Cordero Rojo mine.  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 the Rio Tinto Pacific Coal business unit based in Brisbane Australia.  Mr. Marshall received his bachelor of engineering degree and his master’s degree in mechanical engineering from Brunel University and his master of business administration 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 from December 2001 to November 2004, he served as Principal Business Analyst of Rio Tinto Iron Ore’s new business development group.  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 served as General Manager for RTEA’s Jacobs Ranch mine, from October 2006 to September 2007, he served as General Manager for RTEA’s Antelope mine and from November 2003 to September 2006, he served as Manager, Mine Operations for RTEA’s Antelope mine.  Prior to that, he worked for RTEA in a variety of operational and technical positions for RTEA’s Antelope, Colowyo and Jacobs Ranch mines since 1992.  Mr. Rivenes holds a bachelor of science in mining engineering from Montana College of Mineral, Science & Technology.

Cary 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

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until May 2006.  In these capacities, Mr. Martin’s responsibilities included oversight of employee and labor relations, workforce planning, employee development, compensation administration, policies and procedures and other responsibilities that are common for a human resources executive.  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.

Todd Myers has served as our Senior Vice President, Business Development since July 2010.  Previously, he served as President of Westmoreland Coal Sales Company.  Prior to that, Mr. Myers served in other senior leadership positions with Westmoreland Coal Sales Company in marketing and business development during two periods dating to 1989.  In his various capacities with Westmoreland, Mr. Myers’s responsibilities included developing and implementing corporate merger and acquisition strategies, divesting coal related assets, negotiating complex transactions and other responsibilities generally attributable to the management of coal businesses.  Mr. Myers also spent five years with RDI Consulting, a leading consulting firm in the energy industry, where he led the energy and environment consulting practice.  In 1987, Mr. Myers served as a staff assistant in the U.S. House of Representatives.  Mr. Myers earned his bachelor of arts in political science from Pennsylvania State University in University Park, Pennsylvania, and his masters in international management from the Thunderbird Graduate School of Global Management in Glendale, Arizona.

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 bachelor of science 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 to January 2010.  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 to March 2007, and was Deputy General Counsel and Secretary for Unocal Corporation, an international energy company acquired by Chevron Corporation in 2005, from March 2004 until October 2005.  While in these capacities, Mr. Pechersky’s responsibilities included advising corporate clients regarding various legal, regulatory and compliance matters, transactions and other responsibilities that are common for a general counsel and corporate secretary.  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.

Heath Hill has served as our Vice President and Chief Accounting Officer since September 2010.  Previously, Mr. Hill served in various capacities with PricewaterhouseCoopers LLP, our independent public accountants, from September 1998 to September 2010, including Senior Manager from September 2006 to September 2010, and Manager from September 2003 to September 2006.  While with PricewaterhouseCoopers LLP, Mr. Hill’s responsibilities included assurance services primarily related to SEC registrants, including annual audits of financial statements and internal controls, public debt offerings and IPO transactions.  From June 2003 to June 2005 he held a position with PricewaterhouseCoopers in Germany serving US registrants throughout Europe.  Mr. Hill earned his bachelor’s degree in accounting from the University of Northern Colorado.

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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 relating to global 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.  As an example, all of the mines we operate are certified to the international standard for environmental management systems (ISO 14001).  Our industry is highly regulated and the laws and regulations which apply to our operations are extensive, change frequently, and tend to become stricter over time.  We have procedures in place, which are designed to enable us to comply with these laws and regulations.  We believe we are substantially in compliance with applicable laws and regulations.  However, we cannot assure you that we have been or will be at all times in complete compliance.

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 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 impact of the production and usage of coal on global climate change, which resulted in extensive comments from environmental groups on the EIS prepared in connection with the West Antelope II LBA, and subsequent legal challenges were filed in 2010 against the BLM and the Secretary of the Interior with respect to this LBA, which we have nominated.  This may result in further delays or an inability to obtain this lease.  Future nominations or lease applications may also be subject to delays or challenges, which may result in 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 limit or delay commencement or continuation of mining operations.  In the states where we operate, the applicable laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if officers, directors, shareholders with specified interests or certain other affiliated entities with specified interests in the applicant or permittee have, or are affiliated with another entity that has, outstanding permit violations.  Thus, past or ongoing violations of applicable laws and regulations by these interested persons and entities could provide a basis to revoke our existing permits and to deny the issuance of additional permits.

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

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

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Surface Mining Control and Reclamation Act

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 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 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 2010, we recorded $29.1 million of expense related to these reclamation fees for our three owned and operated mines.

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.  Prior to the 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 and such instruments have been accepted as replacements by the appropriate agencies.

As of December 31, 2010, there were approximately $525.0 million in surety bonds outstanding to secure the performance of our reclamation obligations (including our obligations with respect to the Decker mine).  In addition, we have

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a letter of credit for $10.5 million that we use to secure our 50% share of additional reclamation obligations at the Decker mine.  At December 31, 2010, we had $182.1 million of restricted cash used as collateral for our surety bonds.

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 (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 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.  Recent underground mine accidents have resulted in, and may continue to result in, state and federal legislatures and regulatory authorities increasing scrutiny of mine safety matters and passing more stringent laws governing mining.  For example, in 2006, Congress enacted the Mine Improvement and New Emergency Response 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.  Our compliance with these or any new mine health and safety regulations could increase our mining costs.

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 data, in 2009 we had one of the lowest employee all injury incident rate among the 10 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 2010, we recorded $42.6 million of expense related to this excise tax for our three owned and operated mines.

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 air pollutants, including 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

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recent years, Congress has considered legislation that would require increased reductions in emissions of sulfur dioxide, nitrogen oxide and mercury.  In addition to the 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:

·                  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.

·                  Particulate Matter.  The Clean Air Act requires the EPA to set standards, referred to as 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 PM2.5.  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 PM2.5 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 located in non-attainment areas for PM2.5 that were designated in 2004.  New, more stringent NAAQS for PM2.5 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 PM2.5 NAAQS to the EPA.  The 2006 PM2.5 NAAQS remain in effect pending either the promulgation of a new NAAQS or an adequate justification of the 2006 PM2.5 NAAQS by the EPA.  Any new PM2.5 NAAQS may be more stringent than the 2006 version.  In November 2009, the EPA designated non-attainment areas for the revised PM2.5 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 PM2.5 NAAQS or any new version in non-attainment areas may require reductions of nitrogen oxide and sulfur dioxide emissions, in addition to requiring reductions of PM2.5 emissions that are separate and distinct from the reductions that may be required under any other program.  Although our operations are not currently located in non-attainment areas, enforcement of the 2006 PM2.5 NAAQS or the promulgation of any new standard will affect many power plants, especially coal-fired plants in non-attainment areas.  We are unable to predict the magnitude of the impact on the demand for, or price of, lower sulfur coals from the PRB.  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, the EPA has set more stringent emissions standards for coal preparation plants that took effect on October 8, 2009.  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.

·                  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.  In January 2010, the EPA proposed to adopt even more stringent primary NAAQS for ozone, between the range of 60-70 parts per billion (“ppb”) (compared with the 75 ppb standard adopted in 2008).  Stringent secondary standards to protect sensitive vegetation and ecosystems also were proposed.  The EPA has extended the deadline for adopting new standards to the end of July 2011; non-attainment designations will be made by July 2013; state plans to implement the standards will be due by the end of 2016; and attainment of the standards must be achieved by 2018 or later, depending on the severity of the problem.  The combination of these actions may impact demand for coal nationally, but we are unable to predict the magnitude of the impact.

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·                  NAAQS for Other Pollutants.  On June 22, 2010, the EPA published a final rule that tightens the NAAQS for sulfur dioxide.  The new regulations are aimed at preventing short term exposure to sulfur dioxide and are specifically meant to curb the negative public health effects associated with sulfur dioxide emissions.  For the first time, a 1-hour standard has been adopted at a level of 75 ppb, abandoning the existing 24-hour standard and annual NAAQS for sulfur dioxide.  Non-attainment designations will be finalized by June 2012; state implementation plans are due in the winter of 2014; and the deadline to achieve attainment is the summer of 2017.  We do not know whether or to what extent these developments might affect our operations.

·                  Nitrogen Dioxide.  On February 9, 2010, the EPA published a revised NAAQS for nitrogen dioxide.  For the first time, the EPA has adopted a 1-hour standard at a level of 100 ppb, as well as retaining 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.

·                  NOx SIP Call.  The NOx 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.

·                  Clean Air Interstate Rule.  The EPA’s Clean Air Interstate Rule 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.  The EPA released its proposed replacement of CAIR, which is CATR on July 6, 2010.  Under the proposed rule, which will be subject to public comment and possible amendments, the EPA would require reductions in annual sulfur dioxide and nitrogen oxide emissions from power plants in 28 states.  A final rule is expected in July 2011 and the emissions reductions would start in 2012.  When combined with other EPA and state efforts, the EPA predicts that CATR will result in sulfur dioxide reductions of 71% and nitrogen oxide reductions of 52% from 2005 levels by 2014.  In addition, legislation has been introduced in the Senate that would require an 80% reduction in power plants’ sulfur dioxide emissions by 2018, a 50% reduction in nitrogen oxide emissions by 2015 and a 90% reduction in mercury emissions by 2015.  Under CAIR, the proposed CATR, and any replacement rule with similarly stringent caps, although some coal-fired power plants might elect to use more low-sulfur coal, which could increase the demand, other plants might be required to install additional pollution control equipment.  This pollution control equipment, such as scrubbers, 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.

·                  Mercury.  In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the EPA’s Clean Air Mercury Rule (“CAMR”), 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 (“MACT”), for these emissions.  The MACT standards for mercury are likely to impose stricter limitations on mercury emissions from power plants than the vacated CAMR, as well as limits on other hazardous air pollutants.  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

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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.

·                  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.

·                  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.  In June, 2010, Earthjustice filed a petition with EPA on behalf of several environmental organizations that requested the agency to: 1) list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the Clean Air Act; 2) establish standards of performance to reduce emissions from new and modified coal mine sources of methane (due to global climate change concerns), particulate matter (including fugitive particulates), volatile organic compounds and nitrogen oxides; and 3) establish standards of performance to reduce emissions of methane from existing coal mine sources.  We do not know whether EPA will grant the petition and propose regulations accordingly.  If EPA should propose regulations, we do not know what they might require or what impact they might have on our operations.

Global 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, recent regulatory initiatives and litigation with respect to global climate change and global warming.  In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (the “Kyoto Protocol”), 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 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 the 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 gas emissions 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.  Passage of comprehensive global 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 subject to regulation by the EPA pursuant to the Clean Air Act.  In response to the 2007 U.S. Supreme Court ruling Massachusetts v. EPA, the EPA has taken several steps towards promulgating and implementing regulations regarding the emission of greenhouse gases.  On December 7, 2009, the EPA issued a final finding that the presence of carbon dioxide and certain other greenhouse gases in the atmosphere endangers public health and welfare.  This finding was a prerequisite to EPA regulation of greenhouse gas emissions from motor vehicles under the Clean Air Act.  As a result of this finding, EPA has promulgated further regulations

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subjecting greenhouse gas emissions from stationary sources that exceed certain emission thresholds (these emission thresholds would cover power plants as well as other large industrial sources) will also become subject to various requirements, including certain air permitting requirements, under the Clean Air Act beginning on January 2, 2011.  These requirements would include the mandatory use of best available control technology for greenhouse gas emissions whenever the construction or modification of a facility would increase greenhouse gas emissions by 75,000 tons per year or more as well as other burdensome and time-consuming permitting requirements.  As a result of these regulations, our customers may reduce the amount of coal they purchase from us.  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.

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.  Ten northeastern states (Connecticut, Delaware, Maine, Massachusetts, Maryland, New Hampshire, New Jersey, New York, Rhode Island and Vermont) have formed the Regional Greenhouse Gas Initiative (“RGGI”), the only operating cap-and-trade system in the United States.  RGGI is 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 at 2005 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 observers.  RGGI has begun holding quarterly carbon dioxide allowance auctions for its 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.

Global 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 global 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 Western Climate Initiative envisions an economy-wide cap-and-trade program that would include fossil fuels (such as coal) production and processing.  Thus, our coal mines could incur additional 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.

RGGI, the Western Climate Initiative and the Midwestern Greenhouse Gas Reduction Accord have released a joint policy paper stating that they share a common vision on offsets and signaling that the three programs may be moving closer toward acting together to form a national cap-and-trade program.  Offsets are greenhouse gas reduction projects outside a mandatory cap that entities can turn to if they fail to meet greenhouse gas reductions targets at their own facilities.

Additionally, two U.S. federal appeals courts (5th and 2nd Circuits) 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, including increasing the adverse effects of Hurricane Katrina.  One of these appeals court decisions was subsequently vacated, without being decided on the merits, when a request to rehear the case en banc was granted but the court rehearing the case failed to establish a quorum.  The 2nd Circuit case is now pending before the U.S. Supreme Court.

These and other current or future global 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

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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 the permitting and building of new coal-fired power plants evaluate the use of natural gas generating stations 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 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 (or more distant) future.

Even in the absence of comprehensive federal or state legislation on greenhouse gas emissions, global climate change and greenhouse gas emissions have increasingly become issues that must be addressed in connection with the preparation of EISs necessary to obtain additional federal coal leases.  For example, we received extensive comments from several environmental groups pertaining to the extent of global climate change discussion that should be included within the EIS document for the federal coal lease application for the West Antelope II LBA, which we have nominated.  This LBA is also the subject of pending legal challenges filed in 2010 against the BLM and the Secretary of the Interior by environmental organizations.  It is possible that in the future we may be unable to obtain future coal leases on a timely basis, or at all, which could have an adverse impact on our business.

Clean Water Act

The federal Clean Water Act (the “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:

·                  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 (“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, litigation, 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 (“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.

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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.

·                  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 (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 (“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 and in response to a federal judge’s ruling in March 2009 that the use of permits by the Corps to circumvent its statutory obligations to thoroughly examine the environmental impacts of mountaintop mining was illegal, in June 2010 the Corps suspended the use of NWP 21 in six Appalachian region states.  The permit continues to be available in other regions of the country.  The suspension of the NWP 21 in Appalachia will remain in effect until the Corps takes further action or until the permit expires on March 18, 2012.  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 suspension of NWP 21.  However, decisions that restrict the issuance of permits pursuant to NWP 21, lawsuits challenging the use of NWP 21 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 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.

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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 (“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.  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, in June 2010 the EPA released two competing proposals for the regulation of coal combustion byproducts.  One would regulate the byproducts as hazardous or special waste and the other would classify the byproducts as non hazardous waste.  A further revised draft is expected to be published late in 2011.  If coal combustion wastes were classified as a special or 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 (“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 primary 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 (the “ESA”) and counterpart state legislation protect species threatened with possible extinction.  The U.S. Fish and Wildlife Service (the “USFWS”) works closely with the 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 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.  Similarly, in Wyoming, the Buffalo Field Office of the BLM is engaged in revising its Resource Management Plan (“RMP”) to include additional sage grouse protective measures in its RMP.  Once adopted, this plan may impose limitations on future development and/or further mitigation measures within sage grouse habitat on lands administered by the Buffalo Field Office, including the PRB.  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.  This finding imposes no legal obligation to protect the bird.  Three environmental groups have filed a lawsuit against USFWS challenging its failure to provide ESA protection to the sage grouse.  On June 29, 2010, the USFWS issued a notice reinstating the proposed rule for relating to the listing of the mountain plover as threatened under the ESA and

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requesting public comment.  If finalized by May 2011, the threatened species listing could lead to new land use restrictions to protect nesting plovers in Wyoming and Montana.  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 and other information with the 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 (720) 566-2900 or by mail at Cloud Peak Energy Resources LLC, 385 Interlocken Crescent, Suite 400, Broomfield, Colorado, 80021, Attention:  Vice President, Investor Relations.  The information on our website is not part of this 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 Form 10-K.  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

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 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.

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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; weather disruption; 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 U.S. coal has increased and decreased over the last decade because of these factors.  Decline in foreign demand for U.S. coal 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 natural gas could cause demand for coal to decrease and adversely affect the price of our coal.  For example, the average price for natural gas declined from $4.44 per thousand cubic feet as of December 2009 to $4.15 per thousand cubic feet as of December 2010, leading to, in some instances, decreased coal consumption by electricity-generating utilities.  If alternative energy sources, such as 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 incentives to encourage continuing technological advances and deployment in this area could further enable alternative energy sources to become more competitive with coal.

Global or U.S. economic and market conditions may have a material adverse affect 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, had an adverse impact on the coal industry generally including our company.  For example, the demand for electricity in our target markets decreased during 2009, which led to a decrease in coal consumption by customers.  As a result, stockpiles of coal by our customers increased during this time leading to our customers curtailing future orders.  In 2009, we also 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.  We cannot predict the timing of such economic disruptions or their long-term impact on domestic and international economies or the magnitude and pace of any recovery.  Any actions we may take in response to such economic conditions may be insufficient.  A return to the global recession or a recession in the U.S. economy, or further disruptions in the financial and credit 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, the average sales price we receive for our coal may lag behind any general economic recovery in the U.S.

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

Mining companies must obtain a number of permits and licenses that impose strict regulations on various environmental and operational matters in connection with coal mining.  These include permits and licenses issued by various federal, state and local agencies and regulatory bodies.  The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by the regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing operations or the development of future mining operations.  The public, including non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and submit objections to requested permits and environmental impact statements (each an “EIS”) prepared in connection with applicable regulatory processes, and otherwise engage in the permitting and licensing process, including bringing citizens’ lawsuits to challenge the issuance of permits, the validity of EIS or performance of mining activities.  For example, the EIS and other regulatory matters associated with the West Antelope II LBA are being legally challenged by several non-governmental organizations, which could create a delay or uncertainty in acquiring the coal lease.  If this or any other permits, licenses 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

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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.

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 or are delayed in the acquisition of 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.  For example, the West Antelope II LBA is subject to pending legal challenges filed in 2010 against the BLM and the Secretary of the Interior by environmental organizations.  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 (each, a “QSO”), with the ability to prohibit the BLM from leasing its coal.  For example, in connection with a pending LBA that we nominated for our Cordero Rojo mine, the BLM has indicated that certain surface owners satisfy the regulatory definition of QSO.  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.

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 were delayed or reduced due to coal price reductions since mid-2008 and the concurrent global economic downturn.  However, these capacity increases may be restarted.  Any overcapacity and increased production in the future could materially reduce coal prices and, therefore, materially reduce our revenues and profitability.

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;

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·                  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;

·                  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, including challenges by non-governmental or environmental organizations or other third parties;

·                  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 and the mountain plover, 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, which could have a material adverse effect on our results of operations.

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 electricity 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 2010, we sold approximately 96% of our coal to domestic electric power generators.  Domestic electric power generation accounted for approximately 93% of all U.S. coal consumption from October 2009 through September 2010,

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according to the U.S. Energy Information Administration (the “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 or legal mandates 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 (“GHG”) 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 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 current Administration has indicated its support for a federal renewable energy standard as part of energy and climate change legislative initiatives.  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 GHG 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 GHG and is a major source of regulatory attention 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 GHG emissions, including from coal-fired power plants.

There are many regulatory approaches currently in effect or being considered to address GHGs, 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 U.S. Environmental Protection Agency (the “EPA”).

·                  The current Administration has indicated its support for a mandatory cap-and-trade program to reduce GHG emissions, and the U.S. Congress has considered various proposals to reduce GHG emissions, mandate electricity suppliers to use renewable energy sources to generate a certain percentage of power and require energy efficiency measures.  For example, in June 2009, the U.S. House of Representatives passed a comprehensive climate change and energy bill, the American Clean Energy and Security Act.

·                  In September 2009, the EPA promulgated a rule requiring certain emitters of GHGs, including coal-fired power plants, to monitor and report their GHG emissions to the EPA.  In addition, following the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA has declared that anthropogenic GHGs “endanger” public health and welfare and issued a series of rules requiring extensive regulation, starting January 2, 2011, of GHG emissions from mobile sources and stationary sources, including imposing new permitting requirements and obligations to use best available control technology for the reduction of GHG emissions whenever certain stationary sources, such as power plants, are built or significantly modified.

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·                  State and regional climate change initiatives intended to limit or affect the emission of GHG 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 in the foreseeable future.

·                  The State of California approved a fee to be paid by certain emitters of GHGs, 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 GHG emissions from the new plants.  Additionally, at least one U.S. federal appeals court reinstated a lawsuit permitting individuals, state attorneys general and others to pursue claims against industrial companies on the basis that they have created a public nuisance due to their emissions of carbon dioxide and its alleged effects on climate (e.g.  sea level and storm severity).

Climate change initiatives and other efforts to reduce GHG 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 to acquire additional coal leases.  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.  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.  Furthermore, any significant delay in acquiring reserves, due to delays in the federal competitive leasing process or otherwise, could negatively impact our production rate.  As a result, to maintain our production capacity and competitive position, we will need to acquire significant additional coal reserves 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 opportunities, the delay in the federal leasing process caused by third-party legal challenges 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.

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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.  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.

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 recently has been adopted and/or 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, 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.

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Our customers are also subject to other existing and potential environmental regulations, such as EPA’s publication in June 2010 of proposed regulations for the management and disposal of coal combustion by-products.  While we are unable to determine the likely ultimate regulatory requirements, any significant changes in the management of coal combustion by-products could require our customers to comply with more stringent storage and disposal requirements, which in turn could increase their costs and reduce the demand 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, 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 manager has limited 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 Holdings’s management team has limited experience managing a business on a stand-alone basis or as a public company.  If Holdings is unable to manage and operate our company as a stand-alone public company, our business and results of operations will be adversely affected.

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

As public companies, we and Holdings incur significant legal, accounting and other expenses that we did not incur as a subsidiary of Rio Tinto.  In addition, we and Holdings are subject to a number of additional requirements, including the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) and Holdings is subject to the listing standards of New York Stock Exchange.  These requirements have caused us and Holdings to incur increased costs and have placed increased demands on our systems and resources.  The Exchange Act requires, among other things, that we and Holdings file annual, quarterly and current reports with respect to our business and financial condition.  The Sarbanes-Oxley Act requires, among other things that Holdings maintains effective disclosure controls and procedures and internal control over financial reporting, and also requires that Holdings’s internal control over financial reporting be assessed by management and attested to by its auditors as of December 31 of each year.  Due to a transition period established by rules of the SEC for newly public companies, we will not be subject to certain requirements of the Sarbanes-Oxley Act until the year ending December 31, 2011.  In order to maintain and improve the effectiveness of our and Holdings’s disclosure controls and procedures and internal control over financial reporting, significant resources and management oversight will be required.  As a result, our manager’s 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 identified material weaknesses in our internal controls over financial reporting that 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.

During the preparation of our 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. GAAP, 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 a 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.

In preparation for the filing of Holdings’s annual report on Form 10-K for the year ended December 31, 2009, our manager performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2009, and concluded that the previously identified material weaknesses were not yet remediated.

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.

Our manager has implemented changes and improvements in its disclosure controls and procedures and its internal control over financial reporting to remediate the control deficiencies that gave rise to the material weaknesses.  If we experience future material weaknesses, investors could lose confidence in our financial reporting, particularly if such weaknesses result in a restatement of our financial results.

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.

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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 plants 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 plants 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 royalties or in severance 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 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 severance and production taxes which represented 30.5% and 29.1% of proceeds from the coal we produced for the years ended December 31, 2010 and 2009, respectively.  If royalties or severance and production tax rates were to significantly increase or if we are required to make additional payments as a result of governmental audits, 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

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negative impact on our results of operations.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cost of Product Sold” within Item 7 and “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risks” in Item 7A.

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.

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 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.

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

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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.

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 manager’s 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.

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 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 through our workers compensation insurance funds.  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

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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.

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 places limits on the amounts of sulfur dioxide that can be emitted by an electric power plant, among other sources, 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 Clean Air Interstate Rule (“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 from 2008 to date, 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 for the near-term.  In July 2010, the EPA proposed the Clean Air Transport Rule (“CATR”) as a replacement for CAIR.  If promulgated, CATR would phase in requirements for sources of sulfur dioxide and nitrogen oxide beginning in 2012; subject sources would include power plants.  Under CATR, the EPA has proposed state-specific emissions and allocation budgets and intrastate cap-and-trade mechanisms for allocations, with very limited to no interstate trading provisions in the EPA options under consideration.  The effects which these intrastate and interstate provisions will have on CATR allowance markets remain uncertain.  For select states, the emissions budgets will be further reduced in 2014.  Coincident with these proposed changes is the finalization of revised National Ambient Air Quality Standards (“NAAQS”) for nitrogen dioxide and sulfur dioxide that occurred in January 2010 and June 2010, respectively.  More widespread installation by electric utilities of technology that reduces sulfur emissions could be accelerated to meet the requirements of the revised NAAQS and/or requirements from the finalization of CATR and 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.  Alternatively, compliance with the revised NAAQS and/or the finalization of CATR could entail utilization of controls in combination with low-sulfur coal.  In the CATR proposal, the EPA has projected that to meet the proposed CATR requirements, utilities would need to install 11 GWs of new sulfur dioxide scrubbers in addition to those controls already planned or in place.  The EPA recently published a notice of data availability and stated that the new data might impact the agency’s assessment of which states contribute to pollution problems in downwind states, which in turn might lead to pressure to expand the number of states subject to the CATR.  If additional states are obligated to comply with CATR, it may adversely affect the demand for our coal.

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

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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 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.

If we do not maintain and grow our export sales, our results may be adversely affected.

A portion of our coal sales in recent years have been into export markets in Asia, and we seek to make additional export sales in the future to Asia and potentially other international locations.  Our ability to maintain and grow our export sales revenues and margins depends on a number of factors, including the existence of sufficient and cost-effective export terminal capacity for the shipment of thermal coal to foreign markets and demand by customers in Asia and in other potential export markets for PRB coal.  Our access to existing and any future terminal capacity may be adversely affected by regulatory and permit requirements, environmental and other legal challenges, public perceptions and resulting political pressures, operational issues at terminals and competition among domestic coal producers for access to limited terminal capacity, among other factors.  If we fail to maintain and grow terminal capacity for the export of our coal on commercially reasonable terms, or at all, our results from our export transactions will be materially adversely affected.  Foreign customer demand for PRB coal, and the prices those customers may be willing to pay for PRB coal and related transportation costs, can be affected by a variety of matters, including supplier diversity and security considerations, economic conditions and demand for electricity in the relevant markets, international energy policies and regulatory requirements, and availability and pricing for thermal coal delivered from alternative international basins.

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, 2010 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

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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 time frame 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 in order 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 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.

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.  The Surface Mining Control and Reclamation Act (“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, and by government regulators.  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.

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.  Recent past economic volatility and tightening credit markets increased 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

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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.

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 certain contracts covering our future tonnage commitments.  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.

Failure to maintain our surety bonds 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 $525.0 million of surety bonds and $10.5 million of letters of credit issued as of December 31, 2010, to support reclamation and lease obligations.  We may have difficulty procuring or maintaining our surety bonds.  Our bond issuers may demand terms less favorable to us, higher fees, or additional collateral in the form of letters of credit or cash collateral 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.

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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.  As a result of the economic downturn, a greater than normal number of our customers in 2009 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 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

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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 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 the other 50% owner 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 the other 50% owner.  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 the other 50% owner.  Under the terms of the joint venture agreement, we are required to contribute cash or other property and equipment as may be 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 50% owner does not contribute its share of operating expenses, including reclamation expenses when due, or other liabilities, the other owner 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 the other 50% owner, which is outside of our control.  In addition, if we do not provide our proportional share or the other 50% owner does not provide its proportional share, our interest in the profits from the Decker mine will be adjusted proportionally.  Our current debt instruments and future credit arrangements may limit 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 has union members.  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.

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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 or 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 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.

At December 31, 2010, we had $600 million of senior notes outstanding and approximately $8.1 million of other long-term debt incurred in connection with land acquisitions.  In addition, at December 31, 2010, $10.5 million of capacity under our $400 million revolving credit facility was being used for letters of credit securing our reclamation obligations reducing the capacity under the revolving credit facility to $389.5 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;

·                  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;

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·                  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 and Holdings now face, including those described above, could intensify.  Moreover, these risks also apply to certain of our domestic restricted subsidiaries that are guarantors of our indebtedness and may apply to Holdings if it becomes a guarantor of our debt in the future.  In addition to the principal repayments on outstanding debt, we have other demands on our cash resources, including significant maintenance and other capital expenditures, including LBAs, and operating expenses and distributions to Holdings to fund required payments under the Tax Receivable Agreement (See “Risk Factors—Risks Related to Our Corporate Structure and the IPO Structuring Transaction”).  Our ability to pay our debt depends upon the operating performance of our business.  In particular, economic conditions could cause revenues to decline, and hamper our ability to repay indebtedness.  If we do not have enough cash to satisfy our debt service obligations, we may be required to refinance all or part of our debt, sell assets, limit certain capital expenditures, including LBAs, or reduce spending or Holdings may be required to issue equity.  We may not be able to, at any given time, refinance our debt or sell assets and Holdings may not be able to, at any given time, issue equity, in either case on acceptable terms or at all.

We may be able to incur substantially more debt.  This could exacerbate the risks associated with our substantial indebtedness.

We and our subsidiaries may be able to incur substantially more debt in the future.  Although our debt instruments contain restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions and, under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial.  We are able to incur up to $400 million (subject to reduction by the amount of our letters of credit) in total indebtedness under our revolving credit facility (with a potential incremental increase of up to $50 million, subject to certain conditions).  Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness.  To the extent new debt or new obligations are added to our current levels, the risks described above could substantially increase and we may not be able to meet all of our debt obligations.

If we are unable to comply with the covenants or restrictions contained in our 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.  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.  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.

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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.

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

Certain provisions of our debt instruments 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 the senior 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 the IPO Structuring Transactions

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

In connection with the IPO, Holdings entered into the Tax Receivable Agreement with RTEA that requires Holdings to pay to RTEA approximately 85% of the amount of cash tax savings, if any, that Holdings realizes as a result of the increases in tax basis that Holdings obtained in connection with the initial acquisition of Holdings’s interest in us, Holdings’s subsequent acquisition of RTEA’s remaining units in us, as well as payments made by Holdings under the Tax Receivable Agreement.  Due to the size of the increases in the tax basis of Holdings’s share of our tangible and intangible assets, as well as the increase in Holdings’s basis in the equity of our subsidiaries and assets held by those subsidiaries, Holdings expects to make substantial payments to RTEA under the Tax Receivable Agreement.  As a result of Holdings’s acquisition of RTEA’s remaining units in us, Holdings has received a further step-up in Holdings’s tax basis and, accordingly, Holdings’s obligations under the Tax Receivable Agreement to pay RTEA 85% of any benefits Holdings receives as a result of such further step-up has significantly increased.  Holdings’s obligation may further 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 us or Holdings’s available cash resources.  Based on the tax basis of our assets as of December 31, 2010 and our operating plan, the future payments under the Tax Receivable Agreement are estimated to be approximately $190.1 million in the aggregate and are estimated to be payable over the next 20 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 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, Holdings realizes the full tax benefit of such increased tax basis (or an increased portion thereof).

Certain changes in control require Holdings to make payments to RTEA, which could exceed our actual cash savings and could require Holdings to provide credit support.  If we or Holdings undergo a change in control other than a change in control caused by RTEA and Holdings does not 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, Holdings’s assumed cash tax savings, and consequently Holdings’s payments due under the Tax Receivable Agreement, could exceed Holdings’s actual cash tax savings each year by material amounts.  If Holdings undergoes such a change in control and its credit rating is impaired, Holdings 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.

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Certain asset transfers outside the ordinary course of our business may require Holdings to make additional or accelerated payments under the Tax Receivable Agreement.  In addition to Holdings’s obligations to make payments to RTEA with respect to our actual cash tax savings, if we sell any asset with a gross value greater than $10 million outside the ordinary course of our business in a wholly or partially taxable transaction, Holdings 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, Holdings will be required to make certain adjustments to the calculation of its actual cash tax savings for taxable years following sales.  These adjustments could result in an acceleration of Holdings’s obligations under the Tax Receivable Agreement.  In addition, our debt instruments contain limitations on our ability to make distributions, which could affect Holdings’s ability to meet these payment obligations.  These limitations on our 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 Holdings’s obligations.  If Holdings defaults on its obligations under the Tax Receivable Agreement (including by reason of insufficient cash distributions from us), such default will permit RTEA to enforce its rights under the Tax Receivable Agreement, including by acceleration of Holdings’s obligations thereunder.

Holdings’s 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 or Holdings’s 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 Holdings’s tax benefits, as well as Holdings’s obligations under the Tax Receivable Agreement.  Holdings 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.

Our results as a separate, stand-alone public company are significantly different from those portrayed in our pre-IPO financial results.

The historical financial information for all periods prior to the IPO included in this Form 10-K 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 were not operated, as a separate, stand-alone public company for the historical periods presented prior to the IPO.  The historical costs and expenses reflected in our consolidated financial statements for periods prior to the IPO 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.

Prior to the IPO, Holdings’s directors and executive officers had potential conflicts of interest with Holdings and its shareholders.

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

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

We and Holdings entered into various agreements with Rio Tinto and its affiliates in connection with the IPO which address, among other things, the allocation of assets and liabilities between subsidiaries of Rio Tinto and us, responsibility for the disclosures made in the 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 Holdings’s responsibility in its role as our manager to RTEA and KMS as former non-managing members.  We have 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 us at the time the indemnity is payable to Rio Tinto.  Because these agreements were entered into while we and Holdings were part of Rio Tinto, some of the terms of these agreements are likely less favorable to us and Holdings than similar agreements negotiated between unaffiliated third parties.

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 the IPO, including liabilities related to the Jacobs Ranch and Colowyo mines, as well as the uranium mining venture that we do not own.  Under certain of the IPO Structuring Agreements, RTA 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 RTA.

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, 2010, we controlled approximately 970 million tons of proven and probable coal reserves.  All of our proven and probable reserves are classified as steam coal.

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, 2010:

(1)                                  Based on our 50% interest in the Decker mine.

(2)           Total reflects rounding.

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The following table provides the “quality” (sulfur content and average Btu content per pound) of our coal reserves as of December 31, 2010:

(1)           Average Btu per pound includes weight of moisture in the coal on an as-sold basis.

(2)           All our coal is considered to be compliance coal under the Clean Air Act.

(3)           Based on our 50% interest in the Decker mine.

(4)           Total reflects rounding.

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:   176 million tons

Our reserve and non-reserve coal deposit estimates as of December 31, 2010 were prepared by our staff of geologists and engineers, who has extensive experience in PRB coal.  These individuals are responsible for collecting and analyzing geologic data within and adjacent to leases controlled by us.

A review of our 2010 resources and reserves assessments was completed in January 2011 by John T.  Boyd Company, mining and geological consultants, and covered our reserves as of December 31, 2010.  The results verified our reserve estimates.  Our reserve estimates of approximately 970 million tons for the year ended December 31, 2010 were confirmed by John T.  Boyd Company, as well as approximately 256 million tons of non-reserve coal deposits we held as of December 31, 2010.

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 more than 7,500 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

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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.  Third-party legal challenges, such as legal challenges filed in 2010 against the BLM and the Secretary of the Interior by environmental groups with respect to the LBA process in the PRB and the West Antelope II LBA, may result in delays and other adverse impacts on the LBA process.

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.  In June 2010, we entered into a modified coal lease with the BLM through the LBM process to add approximately 48 million tons of proven and probable reserves to one of the Spring Creek mine’s existing federal coal leases.

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 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.”

The federal coal leasing process is designed to be a public process, giving stakeholders and other interested parties opportunities to comment on the BLM’s proposed and final actions and allow third-party comments.  Because of this, third parties, including non-governmental organizations, can challenge the BLM’s actions, which may delay the leasing process.  If

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these challenges prove successful or are litigated for a prolonged period of time, a coal company’s ability to bid on or acquire a new coal lease could be significantly delayed, or could cause the BLM to not offer a lease for bid at all.  In 2010, environmental organizations filed legal challenges against the BLM’s findings on the final EIS and other matters associated with the West Antelope II LBA, which was nominated by our Antelope mine.  These challenges have created some uncertainty with respect to the timing of the LBA bid and lease acquisition and may ultimately delay the leasing process or prevent mining operations.  Even after a lease has been issued and a successful bidder has paid installment money to the BLM, legal challenges may still seek to delay or prevent mining operations.  It is possible that subsequent EISs for other mines in the PRB currently underway but not yet final could be similarly challenged.  There also exists the possibility of similar challenges to the permitting and licensing process, which is also a public process designed to allow public comments.

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 10 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 surface owners, Qualified Surface Owners, or QSOs, with the ability to prohibit the BLM from leasing its coal.  For example, in connection with a pending LBA that we nominated for our Cordero Rojo mine, the BLM has indicated that certain surface owners satisfy the regulatory definition of QSO.  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 feet of additional office space in Gillette, Wyoming, under

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two annual leases expiring on June 30, 2011 and May 31, 2012, and we lease approximately 28,100 square feet of office space in Broomfield, Colorado under a lease that expires in February 2021.  As of December 31, 2010, 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 Mine

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 did not believe those prices represented 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.

With respect to the period 1986-1992, the MMS assessment did not contain a specific dollar amount.  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”).  The MMS did not appeal the ruling.

With respect to the period 1993-2001, the MMS assessed approximately $7.5 million plus interest, which was estimated to be approximately $11 million inclusive of interest.  Decker appealed the MMS 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 February 2010, the District Court vacated the administrative order from the Interior Board of Land Appeals affirming the MMS assessment.  The District Court remanded the case to the MMS for further review and noted that the remand would not unduly prejudice Decker in light of the District Court’s opinion in Decker I.  There is no MMS assessment currently pending against Decker for the 1993 — 2001 period.

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.   If the MMS issues a new assessment for the 1993 — 2001 period, Decker believes it will have substantive challenges to any such assessment in light of the District Court’s decision in Decker I.  Decker also believes that it has contractual price escalation protection from any increased assessments for 1993-2001; and 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 a new assessment is issued by the MMS for the 1993 — 2001 period and is 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 Decker’s conclusions to be reasonable; however, we have not relied upon Decker’s conclusions 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 (“Caballo”), a subsidiary of Peabody Energy Corporation, commenced an action in Wyoming state court against Spring Creek Coal Company (“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.  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

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reasonably estimable.  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 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.  In addition to claims and lawsuits against us, our LBAs, permits and other industry regulatory processes and approvals may also be subject to legal challenges that may adversely impact our mining operations and results.  For example, the West Antelope II LBA, which we have nominated for lease with the Bureau of Land Management, is subject to pending legal challenges filed in 2010 against the Bureau of Land Management and the Secretary of the Interior by environmental organizations.

Item 4.  Reserved.

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PART II

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

As of December 31, 2010, there was no public trading market for our common membership units, 100% of which were held by Cloud Peak Energy Inc.

Dividend Policy

We do not pay, and do not anticipate paying, any dividends on our membership units.  Periodically we have made, and will continue to make, distributions to Holdings pursuant to the limited liability company agreement to fund Holdings’s required payments to RTEA under the Tax Receivable Agreement.  The indenture that governs the senior notes restricts our payment of dividends and distributions.  See Item 7.  “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 9 within Item 8.  “Notes to Consolidated Financial Statements.”

Item 6.  Selected Financial Data.

The following tables set forth our 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, 2010 and 2009 and for each of the three years in the period ended December 31, 2010 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, 2008, 2007 and 2006 and the historical consolidated statement of operations data for the years ended December 31, 2007 and 2006 from the audited consolidated financial statements of RTEA not included in this report.

The historical financial information for all periods prior to the 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 periods prior to the IPO.  The historical costs and expenses reflected in our consolidated financial statements for those periods 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 result of the IPO and the IPO structuring transactions, we now conduct substantially all activities necessary for Holdings to fulfill its responsibilities as a separate, stand-alone public company.  Consequently, our cost structure is different than it was when we were a subsidiary of Rio Tinto.  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 Holdings 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

(1)                                  For the year ended December 31, 2007, operating income reflects an $18.3 million asset impairment charge related to an abandoned ERP systems implementation.  The ERP systems implementation was a worldwide Rio Tinto initiative designed to align processes, procedures, practices and reporting across all Rio Tinto business units.  The implementation was abandoned in connection with Rio Tinto’s actions to divest our business.

(2)                                  Discontinued operations includes the operations, net of related income taxes, of the Colowyo coal mine, the Jacobs Ranch coal mine and the uranium mining venture, which RTEA disposed of prior to the IPO.  For the year ended December 31, 2009, discontinued operations includes the $264.8 million pre-tax gain on sale of the Jacobs Ranch coal mine.  Assets and liabilities of continuing operations exclude balances associated with discontinued operations.  See Note 4 of Notes to Consolidated Financial Statements in Item 8.

(3)                                  For periods prior to the IPO, income or loss attributable to the managing member’s equity reflects income or loss attributable to RTEA as the former parent company, and includes 100% of income or loss from CPE Resources and its subsidiaries.  For the period following the IPO up to the Secondary Offering, income or loss attributable to the managing member’s equity reflects its interest in CPE Resources and its subsidiaries.  Rio Tinto member’s equity at December 31, 2009 reflects the interest in CPE Resources held by RTEA and an affiliate of RTEA.  As of December

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31, 2010, as a result of the Secondary Offering completed in December 2010, CPE Resources is a wholly-owned subsidiary of Cloud Peak Energy Inc.

(4)                                  Federal coal leases and related obligations includes the current and long-term portions of discounted obligations pursuant to federal coal leases of $118.3 million, $169.1 million, $206.3 million, $67.6 million and $79.0 million as of December 31, 2010, 2009, 2008, 2007 and 2006, respectively.

(5)                                  EBITDA and Adjusted EBITDA are intended to provide additional information only and do not have any standard meaning prescribed by generally accepted accounting principles in the U.S., or U.S. GAAP.  A quantitative reconciliation of Adjusted EBITDA to income from continuing operations (as defined below) is found in the table below.

EBITDA represents income from continuing operations before (1) interest income (expense) net, (2) income tax provision, (3) depreciation and depletion, (4) amortization, and (5) accretion.  Adjusted EBITDA represents EBITDA as further adjusted to exclude specifically identified items that management believes do not directly reflect our core operations.  For the periods presented herein, the specifically identified item is the income statement impact of our significant broker contract that expired in the first quarter of 2010.

Adjusted EBITDA is an additional tool intended to assist our management in comparing our performance on a consistent basis for purposes of business decision-making by removing the impact of certain items that management believes do not directly reflect our core operations.  Adjusted EBITDA is a metric intended to assist management in evaluating operating performance, comparing performance across periods, planning and forecasting future business operations and helping determine levels of operating and capital investments.  Period-to-period comparisons of Adjusted EBITDA are intended to help our management identify and assess additional trends potentially impacting our company that may not be shown solely by period-to-period comparisons of income from continuing operations.  Adjusted EBITDA may also be used as part of our incentive compensation program for our executive officers and others.

We believe Adjusted EBITDA is also useful to investors, analysts and other external users of our consolidated financial statements in evaluating our operating performance from period to period and comparing our performance to similar operating results of other relevant companies.  Adjusted EBITDA allows investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and depletion, amortization and accretion and other specifically identified items that are not considered to directly reflect our core operations.

Our management recognizes that using Adjusted EBITDA as a performance measure has inherent limitations as compared to income from continuing operations or other U.S. GAAP financial measures, as these non-GAAP measures exclude certain items, including items that are recurring in nature, which may be meaningful to investors.  Adjusted EBITDA excludes interest expense and interest income; however, as we have historically borrowed money in order to finance transactions and operations, and have invested available cash to generate interest income, interest expense and interest income are elements of our cost structure and influence our ability to generate revenue and returns for shareholders.  Adjusted EBITDA excludes depreciation and depletion and amortization; however, as we use capital and intangible assets to generate revenues, depreciation, depletion and amortization are necessary elements of our costs and ability to generate revenue.  Adjusted EBITDA also excludes accretion expense; however, as we are legally obligated to pay for costs associated with the reclamation and closure of our mine sites, the periodic accretion expense relating to these reclamation costs is a necessary element of our costs and ability to generate revenue.  Adjusted EBITDA excludes income taxes; however, as our parent is organized as a corporation, the payment of taxes is a necessary element of our operations.  Finally, Adjusted EBITDA excludes income statement amounts attributable to our significant broker contract that expired in the first quarter of 2010; however, this historically represented a positive contribution to our operating results.

As a result of these exclusions, Adjusted EBITDA should not be considered in isolation and does not purport to be an alternative to income from continuing operations or other U.S. GAAP financial measures as a measure of our operating performance.

When using Adjusted EBITDA as a performance measure, management intends to compensate for these limitations by comparing it to income from continuing operations in each period, so as to allow for the comparison of the

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performance of the underlying core operations with the overall performance of the company on a full-cost, after-tax basis.  Using Adjusted EBITDA and income from continuing operations to evaluate the business allows management and investors to (a) assess our relative performance against our competitors and (b) ultimately monitor our capacity to generate returns for shareholders.

Because not all companies use identical calculations, our presentation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies or Holdings, as Holdings is subject to the Tax Receivable Agreement with RTEA.  Moreover, our presentation of Adjusted EBITDA is different than EBITDA as defined in our debt financing agreements.

A reconciliation of net income from continuing operations to Adjusted EBITDA for each of the periods presented is as follows (in thousands):

(6)                                  Based on our 50% interest in the Decker mine.

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

This Item 7 is intended to help the reader understand our results of operations and financial condition.  This discussion should be read in conjunction with our consolidated financial statements in Item 8, the section entitled “Cautionary Note Regarding Forward-Looking Statements” and Item 1A “Risk Factors.”

Overview

We are the third largest producer of coal in the U.S. and in the PRB based on 2010 coal production.  We operate some of the safest mines in the coal industry.  For 2010, MSHA data for employee injuries showed our mines had one of the lowest employee all injury incident rate among the 10 largest U.S. coal producing companies.  We operate solely in the PRB, the lowest cost 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, the Antelope Coal mine and the Cordero Rojo mine, are in Wyoming and one of which, the Spring Creek Coal mine, is in Montana.  We also own a 50% non-operating interest in a fourth surface coal mine in Montana, the Decker mine.  We produce sub-bituminous steam coal with low sulfur content and sell our coal primarily to domestic electric utilities.

Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering

Prior to the IPO and the related structuring transactions, CPE Resources was a wholly-owned subsidiary of RTEA, which is our predecessor for financial reporting purposes.  See “Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering” in Note 2 of Notes to Consolidated Financial Statements in Item 8.  On November 19, 2009, Cloud Peak Energy Inc. acquired from RTEA 51% of the common membership units in CPE Resources in exchange for a promissory note, which was repaid on November 25, 2009 using the proceeds from the IPO, and became the managing member of CPE Resources.  As a result of these transactions, Cloud Peak Energy Inc. became a publicly owned holding company with a controlling interest in CPE Resources and its subsidiaries.

On December 15, 2010, Cloud Peak Energy Inc. priced the Secondary Offering of 29,400,000 shares of its common stock on behalf of Rio Tinto.  In connection with the Secondary Offering, Holdings exchanged 29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the Secondary Offering, resulting in a divestiture of 100% of Rio Tinto’s holdings in CPE Resources.  As a result of this transaction, CPE Resources is now a wholly-owned subsidiary of Cloud Peak Energy Inc.  In addition, the elimination of Rio Tinto as a member results in the elimination of its interest in our consolidated balance sheet during the period.

The IPO structuring transactions and the IPO Structuring Agreements were entered into by Cloud Peak Energy Inc., CPE Resources, RTEA and other Rio Tinto affiliates while they were under common control by Rio Tinto.  In accordance with U.S. GAAP we did not adjust the historical financial reporting carrying amounts of our assets and liabilities in connection with the IPO structuring transactions or the Secondary Offering.

The IPO and the related structuring transactions had significant effects on the comparability of our 2009 and 2010 consolidated financial statements with our consolidated financial statements for prior annual periods.  These effects include the following:

·                  Related Party Transactions:  Prior to the IPO, our consolidated balance sheets included substantial amounts due from or to related parties, reflecting balances arising from services that we received from Rio Tinto and cash transfers pursuant to a cash management arrangement with Rio Tinto.  In connection with the IPO, substantially all amounts due from or to Rio Tinto were cancelled and converted to equity.  At December 31, 2010 and 2009, amounts due from or to related parties primarily reflect certain transitional arrangements with Rio Tinto that were concluded in 2010.

·                  Financing and Cash Management:  As a consequence of our participation in the Rio Tinto cash management arrangement prior to the IPO, we did not enter into any significant financing arrangements directly with third parties and we did not maintain any significant cash balances, except for cash balances held by our Decker joint venture which we consolidate on a pro rata basis.  In connection with the IPO, we received cash proceeds from the issuance of senior notes and entered into a revolving credit facility with third-party lenders.  We no longer participate in Rio Tinto’s cash management arrangement and we retained a substantial portion of the senior notes proceeds in order to

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fund a portion of our anticipated future operating, financing and capital expenditure requirements.  As a result of these transactions, our December 31, 2010 and 2009 consolidated balance sheets reflect significant amounts of cash and cash equivalents, restricted cash and long-term debt, which were not reflected in our balance sheets at prior reporting dates.  In addition, our operating results for the period following the IPO reflect interest expense related to our new debt financing arrangements.

·                  Cost Structure:  Prior to the IPO, we prepared our financial statements on a carve-out basis.  Accordingly, our pre-IPO operating results included allocations of general and administrative expenses incurred on our behalf by Rio Tinto affiliates.  In 2008 and 2009, our pre-IPO operating results also reflected significant expenses that were incurred in connection with Rio Tinto’s divestiture of our business.  Following the IPO, our operating results are no longer affected by Rio Tinto expense allocations and divestiture expenses.  However, during the second half of 2009 and through 2010, we incurred recurring and nonrecurring expenses that are necessary to operate effectively as a stand-alone public company.

·                  Income Taxes:  For periods prior to the IPO, our audited consolidated financial statements reflect income taxes recognized by RTEA.  RTEA was a member of an affiliated federal tax group and was party to a federal income tax sharing agreement with the other members of the affiliated federal income tax group.  However, for the purposes of our audited consolidated financial statements, which were prepared on a carve-out basis, RTEA’s current and deferred taxes were calculated on a stand-alone, separate return basis.  RTEA provided income taxes on substantially all pre-tax income reported in our audited consolidated financial statements for such pre-IPO periods.  For periods following the IPO and prior to the Secondary Offering, we were organized as a limited liability company and generally were not subject to income taxes, although several of our subsidiaries file separate corporate income tax returns and may incur minor amounts of income tax or may incur losses that cannot benefit other entities included in the consolidated financial results.  Because we generally were not a taxable entity for dates before the Secondary Offering, our unaudited consolidated financial statements reflect only income taxes on pre-tax income attributable to our corporate subsidiaries.  Subsequent to the Secondary Offering, CPE Resources is no longer treated as a partnership and must recognize income taxes on a stand-alone, separate return basis.

·                  Deferred Taxes:  In connection with the IPO and structuring transactions, we eliminated RTEA’s deferred income tax accounts from our consolidated balance sheet.  For the periods subsequent to the IPO but before the Secondary Offering, we recorded only small amounts of deferred income tax assets relative to our corporate subsidiaries.  CPE Resources did not have any deferred tax assets because it was organized as a limited liability company treated as a non-taxable entity.  For periods subsequent to the secondary offering, CPE Resources is no longer treated as a non-taxable entity for financial reporting purposes and must report its deferred taxes on a stand alone, carve-out basis.  Deferred assets and liabilities were calculated as of the date of the Secondary Offering and recorded to CPE Resources’ balance sheet with an offsetting entry to equity.

Discontinued Operations

Our historical consolidated financial statements include discontinued operations related to assets that were transferred or sold prior to the IPO and related structuring transactions:

·                  RTEA transferred its interests in the Colowyo mine, a coal mine in Colorado and the uranium mining venture to Rio Tinto America on October 7, 2008, and those interests were not contributed to us.

·                  In March 2009, CPE Resources entered into an agreement to sell its ownership interest in the Jacobs Ranch mine, a coal mine in Wyoming, to Arch Coal, Inc.  This transaction closed on October 1, 2009 and the proceeds from this sale were distributed to Rio Tinto America.

The assets, liabilities and results of operations of the Jacobs Ranch mine, the Colowyo mine, and the uranium mining venture are presented as discontinued operations in our historical consolidated financial statements.  Consequently, the discussion of our results of operations below focuses on continuing operations as reported in our historical consolidated financial statements.  Any forward-looking statements exclude the discontinued operations.

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Decker Mine

We hold a 50% non-operating interest in the Decker mine in Montana through a joint-venture agreement.  Under the terms of our joint-venture agreement, a third-party mine operator manages the day-to-day operations of the Decker mine.  We account for our pro-rata share of assets and liabilities in our undivided interest in the joint venture using the proportionate consolidation method, whereby our share of assets, liabilities, revenues and expenses are included in the appropriate classification in our consolidated financial statements.

Core Business Operations

As of December 31, 2010, we controlled approximately 970 million tons of proven and probable coal reserves.  For the year ended December 31, 2010, we produced 95.3 million tons of coal and sold 96.9 million tons of coal.

Our key business drivers include the following:

·                  the volume of coal produced and shipped domestically and internationally;

·                  the price for which we sell our coal;

·                  the costs of mining, including labor, repairs and maintenance, fuel, explosives, depreciation of capital equipment, depletion of coal leases and regulatory compliance; and

·                  capital expenditures to acquire property, plant and equipment.

The volume of coal that we sell and deliver in any given year is driven by the amount of global and domestic demand for electric power.  Demand for electric power may be affected by many factors including weather patterns, environmental and legal challenges, political influences, international and domestic economic conditions, and other factors discussed in this Item 7 and in Item 1A of this Form 10-K.

The price at which we sell our coal is a function of the demand relative to the supply for coal, domestically and internationally.  As a region’s demand increases, prices are also subject to increase, which improves the viability of transporting our coal to a more diverse customer base.  We typically enter into longer term contracts with our customers which helps mitigate the risks associated with any imbalance in supply and demand.  In addition, international demand has increased, enabling us to increase exports of coal.

We typically seek to enter into the year with expected production fully sold; however, as a result of our remaining unsold and index priced position for 2011 through 2012, we believe we are well positioned to benefit from continued near-term demand and pricing.  If, however, the U.S. and international coal markets return to the depressed levels experienced in 2009, our results could be adversely affected.

In line with the worldwide mining industry, we have experienced increased operating costs for mining equipment, diesel fuel and supplies, and employee wages and salaries.  Changes in the cost of commodities related to our production process, such as diesel fuel, will result in changes in the cost of coal production.  We have not entered into any hedging or other arrangements to reduce the volatility in the price of commodities used for our operations, although we may do so in the future.  As is common in the PRB, coal seams at our existing mines naturally deepen at a gradient of approximately 2% to 3%.  Strip ratios have a direct correlation with our costs.

Should the costs of acquiring future federal coal leases and associated surface rights increase, our depletion costs will also increase.

Global Climate Change

Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S. or some of its states or by other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources.  Additionally, the creation and issuance of subsidies designed to encourage use of alternative energy sources could decrease the demand of coal as an energy source.  The potential financial impact on us of future laws,

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regulations or subsidies will depend upon the degree to which electricity generators diminish their reliance on coal as a fuel source as a result of the laws, regulations or subsidies.  That, in turn, will depend on a number of factors, including the appeal and design of the subsidies being offered, the specific requirements imposed by any such laws or regulations, the time periods over which those laws or regulations would be phased in and the state of commercial development and deployment of carbon capture and storage technologies.  In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws or regulations may have on our results of operations, financial condition or cash flows.  See Item 1, “Business—Environmental and Other Regulatory Matters—Climate Change” and Item 1A, “Risk Factors” for additional discussion regarding how climate change and other environmental regulatory matters impact our business.

Results of Operations

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

Domestic shipments from our owned and operated mines increased from 89.3 million tons in 2009 to 90.4 million tons in 2010 while shipments to Asian export customers supplied by our Spring Creek mine increased from 1.6 million tons to 3.3 million tons resulting in total shipments increasing from 90.9 million tons to 93.7 million tons.  Deliveries to domestic customers increased due to improved economic conditions and weather patterns leading to higher demand for coal-fired electricity.  Export deliveries increased due to strengthening international demand for thermal coal.

Total 2010 shipments including our share of the Decker mine and broker sales decreased from 103.3 million tons in 2009 to 96.9 million tons in 2010.  This decrease is primarily due to the expiration of our significant broker sales contract in early 2010.  During 2009 and the beginning of 2010, we had one significant broker sales contract under which our subsidiary, Spring Creek Coal LLC, sold coal to a wholesale power generation company.  The contract expired following final deliveries made under the contract in the first quarter of 2010, and the related contract rights intangible asset has been fully amortized.  This broker sales contract contributed $140.4 million and $13.7 million of revenues for the years ended December 31, 2009 and 2010, respectively.  Income before tax related to this contract was $46.3 million and $5.0 million for those same periods, respectively, which is net of related expenses, including amortization of an intangible asset for the related contract rights of $28.7 million and $3.2 million, respectively.

Additionally in 2010, we continued to focus on our cost management efforts, which resulted in reducing employee overtime, and optimizing repairs and maintenance expense.  For our owned and operated mines, the weighted average cost of diesel fuel was $2.50 per gallon for the year ended December 31, 2010, compared to $1.87 per gallon for the year ended December 31, 2009.  Diesel fuel and lubricant expenses represented 9.2% and 7.8% of cost of coal production at our owned and operated mines for the year ended December 31, 2010 and 2009, respectively.

Revenues

The following table presents revenues for the years ended December 31, 2010 and 2009 (in millions):

The increase in revenue from our owned and operated mines reflects a 4.5% increase in the average price per ton of coal sold, from $11.79 in 2009 to $12.32 in 2010, and a 3.1 % increase in shipments, from 90.9 million tons in 2009 to 93.7 million in 2010.

The increase in average price per ton sold reflects the strong demand for PRB coal due to prevailing economic and industry conditions at the time we entered into the related coal supply contracts.

Other revenues consist primarily of our share of revenues from coal produced at the Decker mine, broker coal sales and billings for transportation and delivery services.  Our share of revenues from coal produced at the Decker mine decreased

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