10-K 1 a2207159z10-k.htm 10-K

Use these links to rapidly review the document
TABLE OF CONTENTS

Table of Contents

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

FORM 10-K

(Mark One)    

ý

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

or

o

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to              

Commission File Number: 001-34547
Commission File Number: 333-168639

LOGO

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

Delaware
Delaware

(State or other jurisdiction of
incorporation or organization)
  26-3088162
26-4073917

(I.R.S. Employer
Identification No.)

505 S. Gillette Ave., Gillette, Wyoming
(Address of principal executive offices)

 

82716
(Zip Code)

(307) 687-6000
(Registrant's telephone number, including area code)

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

Title of Each Class   Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share   New York Stock Exchange

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.

Cloud Peak Energy Inc.   Yes ý   No o
Cloud Peak Energy Resources LLC   Yes ý   No o

             Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Cloud Peak Energy Inc.   Yes o   No ý
Cloud Peak Energy Resources LLC   Yes o   No ý

             Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Cloud Peak Energy Inc.   Yes ý   No o
Cloud Peak Energy Resources LLC   Yes ý   No o

             Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Cloud Peak Energy Inc.   Yes ý   No o
Cloud Peak Energy Resources LLC   Yes ý   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. ý

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

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

Cloud Peak Energy Inc.

  ý   o   o   o

Cloud Peak Energy Resources LLC

  o   o   ý   o

             Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Cloud Peak Energy Inc.   Yes o   No ý
Cloud Peak Energy Resources LLC   Yes o   No ý

             As of June 30, 2011, the last business day of Cloud Peak Energy Inc.'s most recently completed second fiscal quarter, the aggregate market value of the voting and nonvoting stock held by non-affiliates of Cloud Peak Energy Inc. was approximately $1,298 million based on the closing price of Cloud Peak Energy Inc.'s common stock as reported that day on the New York Stock Exchange of $21.30 per share. In determining this figure, Cloud Peak Energy Inc. has assumed that all of its directors and executive officers are affiliates. Such assumptions should not be deemed conclusive for any other purpose.

             Number of shares outstanding of Cloud Peak Energy Inc.'s common stock, as of the latest practicable date: Common stock, $0.01 par value per share, 60,922,534 shares outstanding as of January 31, 2012. 100% of the common membership units of Cloud Peak Energy Resources LLC outstanding as of January 31, 2012 are held by Cloud Peak Energy Inc.

             This combined Form 10-K is separately filed by Cloud Peak Energy Inc. and Cloud Peak Energy Resources LLC. 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 allowed under that General Instruction.

DOCUMENTS INCORPORATED BY REFERENCE

             Portions of Cloud Peak Energy Inc.'s Proxy Statement to be filed with the Securities and Exchange Commission in connection with Cloud Peak Energy Inc.'s 2012 annual meeting of stockholders (the "Proxy Statement") are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.

   


Table of Contents

CLOUD PEAK ENERGY INC. AND
CLOUD PEAK ENERGY RESOURCES LLC

TABLE OF CONTENTS

 
   
  Page  

 

PART I

       

ITEM 1

 

BUSINESS

    1  

ITEM 1A

 

RISK FACTORS

    23  

ITEM 1B

 

UNRESOLVED STAFF COMMENTS

    46  

ITEM 2

 

PROPERTIES

    46  

ITEM 3

 

LEGAL PROCEEDINGS

    50  

ITEM 4

 

MINE SAFETY DISCLOSURES

    50  

 

PART II

       

ITEM 5

 

MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

    51  

ITEM 6

 

SELECTED FINANCIAL DATA

    52  

ITEM 7

 

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

    59  

ITEM 7A

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

    80  

ITEM 8

 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

    82  

ITEM 9

 

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

    149  

ITEM 9A

 

CONTROLS AND PROCEDURES

    149  

ITEM 9B

 

OTHER INFORMATION

    151  

 

PART III

       

ITEM 10

 

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

    152  

ITEM 11

 

EXECUTIVE COMPENSATION

    152  

ITEM 12

 

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

    152  

ITEM 13

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

    152  

ITEM 14

 

PRINCIPAL ACCOUNTING FEES AND SERVICES

    153  

 

PART IV

       

ITEM 15

 

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

    154  

Explanatory Note

        This combined Form 10-K is filed by Cloud Peak Energy Inc. and Cloud Peak Energy Resources LLC. Each Registrant hereto is filing on its own behalf all of the information contained in this report that relates to such Registrant. Each Registrant hereto is not filing any information that does not relate to such other Registrant, and therefore makes no representation as to any such information. Cloud Peak Energy Resources LLC is the sole direct subsidiary of Cloud Peak Energy Inc., providing 100% of Cloud Peak Energy Inc.'s total consolidated revenue for the year ended December 31, 2011 and constituting nearly 100% of Cloud Peak Energy Inc.'s total consolidated assets as of December 31, 2011.

        Unless the context indicates otherwise, the terms the "Company," "we," "us," and "our" refer to both Cloud Peak Energy Inc. and Cloud Peak Energy Resources LLC and their subsidiaries. Discussions or areas of this report that either apply only to Cloud Peak Energy Inc. or Cloud Peak Energy Resources LLC are clearly noted in such sections.

i


Table of Contents


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 current plans, strategies, prospects, and expectations concerning our business, operating results, financial condition, and other similar matters. While we believe that these forward-looking statements are reasonable as and when made, there may be events in the future that we are not able to predict accurately or control, and there can be no assurance that future developments affecting our business will be those that we anticipate. Additionally, all statements concerning our expectations regarding future operating results are based on current forecasts for our existing operations and do not include the potential impact of any future acquisitions. The factors listed under "Risk Factors," as well as any cautionary language in this report, describe the known material 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 may emerge from time to time, or those that we currently deem to be immaterial, could cause our actual results to differ, and it is not possible for us to predict all of them. You are cautioned not to place undue reliance on the forward-looking statements contained herein. 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 and adversely from our forward-looking statements:

    the prices we receive for our coal;

    competition with other producers of coal;

    competition with natural gas and other non-coal energy resources, which may be increased as a result of energy policies, regulations and subsidies or other government incentives that encourage or mandate use of alternative energy sources;

    coal-fired power plant capacity, including the impact of environmental regulations, energy policies and other factors that may cause utilities to phase out or close existing coal-fired power plants or reduce construction of any new coal-fired power plants;

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

    our ability to maintain and grow our export sales;

    domestic and international economic conditions;

    timing of reductions or increases in customer coal inventories;

    weather conditions or weather-related damage that impacts demand for coal, our mining operations, our customers or transportation infrastructure;

    risks inherent to surface coal mining;

    our ability to successfully acquire new coal reserves and surface rights at attractive prices and in a timely manner and our ability to effectively resolve issues with conflicting mineral development that may impact our mine plans;

    our ability to produce coal at existing and planned volumes and to effectively manage the costs of our operations;

    our plans and objectives for future operations and the development of additional coal reserves or acquisition opportunities, including risks associated with any acquisitions that we may pursue;

ii


Table of Contents

    the impact of current and future environmental, health, safety and other laws, regulations, treaties or governmental policies, or changes in interpretations thereof, and third-party regulatory challenges, including those affecting our coal mining operations or our customers' coal usage, carbon and other gaseous emissions or ash handling, as well as related costs and liabilities;

    the impact of required regulatory processes and approvals to lease and obtain permits for coal mining operations or to transport coal to domestic and foreign customers, including third-party legal challenges;

    any increases in rates or changes in regulatory interpretations with respect to royalties or severance and production taxes;

    railroad, export terminal and other transportation performance, costs and availability, including development of additional terminal capacity;

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

    disruptions in delivery or increases 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;

    our relationships with, and other conditions affecting, our customers and other counterparties, including economic conditions and the credit performance and credit risks associated with our customers and other counterparties, such as lenders under Cloud Peak Energy Resources LLC's credit agreement and financial institutions with whom we maintain accounts or enter hedging arrangements;

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

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

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

    our ability to maintain effective internal controls and to meet the systems and resource demands that we must incur as a public company;

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

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

iii


Table of Contents


GLOSSARY FOR SELECTED 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 remain after the combustion of 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, among other ways, as a by-product of the combustion of fossil fuels, including coal, or the burning of vegetable matter.

        CPE Inc.    Cloud Peak Energy Inc., a Delaware corporation. We, us, our or the Company means CPE Inc. and its consolidated subsidiary, CPE Resources, together with the businesses that CPE Resources operates.

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

        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.

        CSAPR.    Cross-State Air Pollution Rule.

iv


Table of Contents

        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.

        EPA.    United States Environmental Protection Agency.

        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.

        GHG.    Greenhouse gas.

        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 MSHA, based on 200,000 hours of employee exposure and calculated as follows:

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

        IPO Structuring Agreements.    The following agreements entered into in connection with the initial public offering of CPE Inc.: The master separation agreement, the acquisition agreement, the assignment agreement, the agency contract, the promissory note, the employee matters agreement, the escrow agreement, the CPE Resources limited liability company agreement, the management services agreement, registration rights agreement, the Rio Tinto Energy America coal supply agreement, the software license agreement, the tax receivable agreement, the trademark assignment agreement, the trademark license agreement, and the transition services agreement. For a description of our remaining operative agreements with Rio Tinto and its affiliates, refer to the information included under the caption "Certain Relationships and Related Transactions" in our Proxy Statement to be distributed to our stockholders in connection with our 2012 annual meeting. We refer generally to the transactions we entered into in connection with these IPO Structuring Agreements as IPO structuring transactions or structuring transactions. See "Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering" in Note 2 of Notes to Consolidated Financial Statements in Item 8.

        LBA.    Lease by Application. Before a mining company can obtain new coal leases on federal land, the company must nominate lands for lease. The BLM then reviews the proposed tract to ensure maximum coal recovery. The BLM 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

v


Table of Contents

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.

        MATS.    Mercury and Air Toxics Standards (formerly Utility Maximum Achievable Control Technology, or Utility MACTS).

        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, or 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.

        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,

vi


Table of Contents

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.

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

        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.

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

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

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

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

        Thermal 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.

vii


Table of Contents

        Tons.    A "short" or net ton is equal to 2,000 pounds. A "long" or British ton is 2,240 pounds. A "metric" ton 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.

viii


Table of Contents

PART I

Item 1.    Business.

Overview

        CPE Inc. is one of the largest producers of coal in the U.S. and in the PRB, based on our 2011 coal sales of 98.7 million tons. We had revenues from our continuing operations of $1.6 billion in 2011. We operate some of the safest mines in the coal industry. According to MSHA data, in 2011, we had one of the lowest employee all injury incident rates among the largest U.S. coal producing companies. We operate solely in the PRB, the lowest cost region of the major coal producing regions in the U.S., and operate two of the four largest coal mines 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% non-operating interest in a fourth surface coal mine in Montana. We produce sub-bituminous thermal coal with low sulfur content and sell our coal primarily to domestic and foreign electric utilities. We do not produce any metallurgical coal. Thermal coal is primarily consumed by electric utilities and industrial consumers as fuel for electricity generation. In 2011, the coal we produced generated approximately 4% of the electricity produced in the U.S. As of December 31, 2011, we controlled approximately 1.37 billion tons of proven and probable reserves. For information regarding our revenues and long-lived assets by geographic area, please see Note 21 of Notes to Consolidated Financial Statements in Item 8.

        CPE Inc., a Delaware corporation organized on July 31, 2008, is a holding company that manages its wholly-owned consolidated subsidiary CPE Resources, but has no business operations or material assets other than its ownership interest in CPE Resources as discussed more fully in "History" below. CPE Inc.'s only source of cash flow from operations is distributions from CPE Resources pursuant to the CPE Resources limited liability company agreement. CPE Inc. also receives management fees pursuant to a management services agreement between CPE Inc. and CPE Resources as reimbursement of certain administrative expenses.

History

        Our business operations are conducted by CPE Resources, formerly known as Rio Tinto Sage LLC, a Delaware limited liability company formed as a wholly-owned subsidiary of RTEA on August 19, 2008. RTEA is our predecessor for accounting purposes. RTEA, a Delaware corporation, formerly known as Kennecott Coal Company, was formed as a wholly-owned subsidiary of RTA 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% non-operating interest in the Decker coal mine. In December 2008, RTEA contributed RTA's western U.S. coal business to CPE Resources (other than the Colowyo mine). 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, CPE Inc. acquired from RTEA approximately 51.0% of the common membership units in CPE Resources in exchange for a promissory note which was repaid with proceeds from its initial public offering ("IPO"). As a result of these transactions, CPE Inc. became the sole managing member of CPE Resources.

        On December 15, 2010, CPE Inc. priced a secondary offering of its common stock on behalf of Rio Tinto (the "Secondary Offering"). In connection with the Secondary Offering, CPE Inc. exchanged shares of common stock for the remaining common membership units of CPE Resources held by Rio Tinto, resulting in a divestiture of 100% of Rio Tinto's holdings in CPE Resources. As a result of this transaction, CPE Resources became a wholly-owned subsidiary of CPE Inc.

1


Table of Contents

Coal Characteristics

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

Heat Value

        The heat value of coal is commonly measured in 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, other than lignite coal which has lower heat value than sub-bituminous coal but is typically only used to supply coal to utilities that are directly adjacent to the mine.

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. See "Environmental and Other Regulatory Matters—Clean Air Act." The sulfur content of coal can vary from seam to seam and within a single seam. The 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, such as scrubbers, which can reduce sulfur dioxide emissions by up to 90%. According to the EIA, in 2010, out of utilities with a coal generating capacity of approximately 317 GW, utilities accounting for a capacity of over 188 GW had been retrofitted with scrubbers. Furthermore, any 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.

        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.

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 coal 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 fusion temperatures are important characteristics of coal and help determine the suitability of the coal to specific 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 20% to 30%.

2


Table of Contents

        Trace elements within coal that are of primary concern are mercury for health and environmental reasons and chlorine for utility plant performance. Trace amounts of mercury and chlorine in PRB coal are relatively low compared to coal from other regions. However, the low chlorine content of PRB coal can promote the emission of mercury in an elemental form, which is more 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 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 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 coal 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. The other 50% mine owner has responsibility for the day-to-day operations. 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

3


Table of Contents

also utilize procedures designed to enhance the efficiencies of our operations. The following table provides summary information regarding our mines as of December 31, 2011.

 
  2011 As Delivered Average   Tons Sold (in millions)  
Mine
  Btu
per lb
  Ash
Content
  Sulfur Content   2011   2010   2009  
 
   
  (%)
  (%)
  (lbs SO2/mmBtu)
  (million tons)
 

Antelope

    8,879     5.15     0.25     0.56     37.1     35.9     34.0  

Cordero Rojo

    8,399     5.33     0.31     0.74     39.5     38.5     39.3  

Spring Creek

    9,237     5.13     0.32     0.69     19.1     19.3     17.6  

Decker(1)

    9,435     4.46     0.40     0.85     1.5     1.5     2.3  

Other(2)

    N/A     N/A     N/A     N/A     1.5     1.7     10.1  
                                       

Total

                            98.7     96.9     103.3  
                                       

(1)
Tons sold numbers reflect our 50% non-operating interest.

(2)
The tonnage shown for "Other" represents our purchases from third-party sources that we have resold. See "—Customers and Coal Contracts—Broker Sales and Third-Party Sources."

        Our Antelope and Cordero Rojo mines are served by the BNSF and UP railroads. Our Spring Creek mine and the Decker mine are served solely by the BNSF railroad.

        The following map shows the locations of our mining operations:

GRAPHIC

4


Table of Contents

Antelope Mine

        The Antelope mine is located in the southern end of the PRB approximately 60 miles south of Gillette, Wyoming. The mine extracts thermal coal from the Anderson and Canyon Seams, with up to 44 and 36 feet, respectively, in thickness. On June 30, 2011 and August 11, 2011, we entered into two separate Federal Coal Leases with the BLM. These leases increased our proven and probable reserves by approximately 383 million tons, but are currently subject to pending legal challenges against the BLM and the Secretary of the Interior by environmental organizations, which could impact our ability to mine the coal subject to those leases and/or delay our access to mine the coal. With the acquisition of the federal coal leases, we also gained access to approximately 81 million tons of coal in an adjacent State of Wyoming coal lease that we controlled but was not previously included in our coal reserve estimates, resulting in a combined total increase of 464 million tons. 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. Based on the average sulfur content of 0.52, the reserves at our Antelope mine are considered to be compliance coal under the Clean Air Act, and this coal is some of the lowest sulfur coal produced in the PRB.

Cordero Rojo Mine

        The Cordero Rojo mine is located approximately 25 miles south of Gillette, Wyoming. The mine extracts thermal 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 sometime in late 2012 or in 2013. The BLM ultimately determines 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. Based on the average sulfur content of 0.69, the reserves at our Cordero Rojo mine are considered to be compliance coal under the Clean Air Act.

Spring Creek Mine

        The Spring Creek mine is located in Montana approximately 35 miles north of Sheridan, Wyoming. The mine extracts thermal 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 2011, we shipped approximately 4.5 million tons of Spring Creek coal through terminals located in British Columbia, Canada. Based on the average sulfur content of 0.71, the reserves at our Spring Creek mine are considered to be compliance coal under the Clean Air Act.

Decker Mine

        The Decker mine is located immediately to the southeast of our Spring Creek mine in Montana. We own a 50% non-operating interest in the mine, which is a union-based operation. However, we do not employ any of the Decker mine employees. The other 50% mine owner has responsibility for the day-to-day operations and markets the thermal coal out of the Decker mine subject to the direction of the management committee. 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.

5


Table of Contents

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 80 domestic and foreign electric utilities and over 87% of our sales were to customers with an investment grade credit rating as of December 31, 2011. Furthermore, over 73% of our 2011 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 personnel. 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 and forward markets; and

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

        As of December 31, 2011, we had 16 employees in our sales and marketing department.

Customers

        Our primary customers are domestic utility companies with over 108 plants primarily located in the mid-west and south central U.S, although we also sell to other domestic and foreign utility companies, as well as to third-party brokers. Our coal supplies fueled approximately 4% of the electricity generated in the U.S. in 2011. During 2011, approximately 47% of our revenues were derived from our top ten customers. No customer accounted for 10% or more of our revenues in 2011. The following map shows the percentage of our shipped tons of coal by state of destination during 2011 from coal produced at

6


Table of Contents

the three mines we own and operate. We also exported approximately 5% of the tons produced at these mines in 2011 to foreign utility customers and brokers.

GRAPHIC

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, including our international customers, although those contracts typically have terms of one to three years. Some of our contracts are as short as one to six months and other contracts have terms longer than ten years. Multiple year contracts usually have specific and possibly different volume and pricing arrangements for each year of the contract. As of December 31, 2011, approximately 56% of our committed tons were associated with contracts that had three years or more remaining on their term. For the year ended December 31, 2011, approximately 81% of our revenues were derived from long-term supply contracts with a term of one year or greater.

        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, including demurrage fees for international contracts.

        Our coal supply contracts typically contain "hardship" 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 incurred as a result of 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. In addition, a small number of our contracts contain clauses that may allow customers to terminate the contract in the event of significant changes in environmental laws and regulations which result in the customer being unable to perform under the terms of the contract.

7


Table of Contents

        Most of our coal 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 domestic agreements that extend for a four- or five-year term or longer may include variable pricing. Our international coal supply agreements often contain a fixed price for the first year of sales, and then provide for future years' pricing to be negotiated at a specific point in time. These types of provisions allow customers to secure a supply for their future needs and provide us with greater predictability of sales volumes and prices. These price re-opener and index 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, including our international 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. Our sales also typically attempt to account for the low sulfur content of our coal by reflecting a market adjustment for the low sulfur in the contract price or through an adjustment calculated based on the as-delivered average sulfur content of our coal, or both.

        Quality and volumes for the coal are stipulated in coal sales agreements. 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 domestic 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 domestic coal sales agreements allow our customers 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 customers' 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 coal sales agreements and sell to brokers and third-party sources any excess produced coal, including selling through foreign brokers who sell to end users in foreign countries. For delivery during the year ended

8


Table of Contents

December 31, 2011, we purchased 1.5 million tons through brokers and third-party sources, and sold 1.5 million tons to 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. In limited circumstances, we sell coal on a delivered basis where we arrange and pay for the freight and charge our customers for this service. Our mines (including the Decker mine) are served by the BNSF and/or UP railways.

        Although the purchaser pays the freight, transportation costs still are important to coal mining companies because the purchaser may choose a supplier largely based on cost of transportation. Transportation costs borne by the customer vary greatly based on each customer's proximity to the mine. Barges, Great Lake carriers and ocean vessels move coal to export markets and domestic markets requiring shipment over the Great Lakes and several river systems.

        We generally sell coal to international customers at the export terminal, and we are usually responsible for the cost of transporting coal to the export terminal. We transport our coal primarily to terminals located in the Pacific Northwest for transportation to international customers. Our international customers are generally responsible for paying the cost of ocean freight.

        To help ensure export terminal capacity for a portion of our anticipated export sales, in 2011 we entered into a long-term throughput contract with Westshore Terminals Limited Partnership that expires in 2023, an export terminal located near Vancouver, British Columbia. This type of "take-or-pay" contract requires us to pay for a minimum quantity of coal to be transported on the railway or through the port regardless of whether we sell any coal. If we fail to acquire sufficient export sales to meet our minimum obligations under this throughput contract, we are still obligated to make payments. We may enter into similar arrangements with other export terminals or rail companies serving those export terminals to help ensure sufficient transportation capacity for our export sales.

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 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 adversely affect our profitability."

Competition

        The coal industry is highly competitive. See Item 1A "Risk Factors—Risks Related to Our Business and Industry—Competition with domestic and foreign coal producers and with producers of natural gas and other competing energy sources may negatively affect our sales volumes and our ability to sell coal at a favorable price." 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.

9


Table of Contents

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 and foreign electric generation industries. 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, 2011, we had approximately 1,600 full-time employees. None of our employees are currently parties to collective bargaining agreements. We believe that we have good relations with our employees. We hold a 50% non-operating interest in the Decker mine in Montana, which is a union-based operation. The other 50% mine owner has responsibility for the day-to-day operations. However, we do not employ any of the Decker mine employees. As of December 31, 2011, we had 323 external contractors on a full-time, equivalent basis.

Executive Officers

        Set forth below is information concerning our current executive officers as of December 31, 2011.

Name
  Age   Position(s)

Colin Marshall

    47   President, Chief Executive Officer and Director

Michael Barrett

    42   Executive Vice President and Chief Financial Officer

Gary Rivenes

    41   Executive Vice President and Chief Operating Officer

Cary Martin

    59   Senior Vice President, Human Resources

Todd Myers

    47   Senior Vice President, Business Development

James Orchard

    51   Senior Vice President, Marketing and Government Affairs

Bryan Pechersky

    41   Senior Vice President and General Counsel

A. Nick Taylor

    60   Senior Vice President, Technical Services

Heath Hill

    41   Vice President and Chief Accounting Officer

        Colin Marshall has served as our President, Chief Executive Officer and a director since July 2008. Previously, he served as the President and Chief Executive Officer of RTEA, an indirect subsidiary of Rio Tinto plc and the former parent company of CPE Resources, 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.

10


Table of Contents

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 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

11


Table of Contents

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 on 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 L.L.P. 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 U.S. registrants throughout Europe. Mr. Hill never worked on any engagements or projects for CPE Inc. or its predecessor, RTEA, while he was with PricewaterhouseCoopers LLP. Mr. Hill earned his bachelor's degree in accounting from the University of Northern Colorado and is an active Certified Public Accountant.

Environmental and Other Regulatory Matters

        Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment and the effects of mining on surface and groundwater quality and availability. These laws and regulations have had, and will continue to have, a significant effect on our production costs and our competitive position. Future laws, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, may require substantial increases in equipment and operating costs and delays, interruptions or a termination of operations, the extent of which we cannot predict. Future laws, regulations or orders, including those 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

12


Table of Contents

sources used to generate electricity. As a result, future laws, regulations or orders may materially adversely affect our mining operations, cost structure, the price we receive for our coal, 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 guarantee 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 against the BLM and the Secretary of the Interior with respect to the corresponding coal leases. 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, stockholders 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.

        Permitting requirements also require, under certain circumstances, that we must obtain surface owner consent if the surface estate has been split from the mineral estate. This requires us to negotiate with third parties for surface access that overlies coal we acquired or intend to acquire. These negotiations can be costly and are time consuming, lasting years in some instances, which can create additional delays in the permitting process. If we cannot successfully negotiate for land access, we could be denied a permit to mine coal we already own.

        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.

13


Table of Contents

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

Surface Mining Control and Reclamation Act

        SMCRA establishes mining, environmental protection, reclamation and closure standards for all aspects of surface coal mining. Mining operators must obtain SMCRA permits and permit renewals from the Office of Surface Mining Reclamation and Enforcement within the Department of the Interior ("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 regulations, 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

14


Table of Contents

$0.315 per ton of coal produced from surface mines. In 2011, we recorded $30.1 million of expense related to these reclamation fees for our three owned and operated mines.

Surety Bonds

        Federal and 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. As of December 31, 2011, there were approximately $568.1 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 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, 2011, we had $71.2 million of restricted cash used as collateral for our surety bonds. At some point, federal and state laws may be amended to require certain forms of financial assurance that are more costly to obtain, such as letters of credit.

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 arrangement 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.

        In 2006, in response to underground mine accidents, Congress enacted the Mine Improvement and New Emergency Response Act, which imposed additional obligations on coal operators, including, among other things, (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) establishment of mine rescue teams; (c) notification to federal authorities of incidents that pose a reasonable risk of death and (d) increased penalties for violations of the applicable federal laws and regulations. In response to the April 2010 explosion at Massey Energy Company's Upper Big Branch Mine, we expect enforcement scrutiny to continue to increase, 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, only some of which may be passed on to customers.

        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

15


Table of Contents

required by state or federal regulations that we consider important to the health and safety of our employees. According to MSHA data, in 2011, we had one of the lowest employee all injury incident rates among the largest U.S. coal producing companies.

Black Lung

        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 2011, we recorded $45.9 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 recent years, Congress has considered legislation that would require increased reductions in emissions of sulfur dioxide, nitrogen oxide and mercury. In addition to the GHG 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. These acid rain requirements would not be supplanted by CSAPR, were it to take effect.

    NAAQS for Criterion Pollutants.  The Clean Air Act requires the EPA to set standards, referred to as NAAQS, for six common air pollutants, including nitrogen oxide and sulfur dioxide. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. Meeting these limits may require reductions of nitrogen oxide and sulfur dioxide emissions. Although our operations are not currently located in 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 if that were to change. On February 9, 2010, the EPA published revised NAAQS for nitrogen dioxide. On June 22, 2010, the EPA published a final rule that tightens the NAAQS for sulfur dioxide. Non-attainment designations will be finalized by June 2012 for both rules; 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 or our customers' businesses.

    Clean Air Interstate Rule and Cross-State Air Pollution Rule.  CAIR calls for power plants in 28 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 June 2011, the EPA finalized CSAPR, a replacement rule to CAIR, which requires 28 states in

16


Table of Contents

      the Midwest and eastern seaboard of the United States to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions would commence in 2012 with further reductions effective in 2014. However, on December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit stayed the implementation of CSAPR pending resolution of judicial challenges to the rules and ordered the EPA to continue enforcing CAIR until the pending legal challenges have been resolved. We are unable to predict whether the CSAPR program will be upheld or reversed but for states to meet their requirements under CSAPR, a number of coal-fired electric generating units will likely need to be retired, rather than retrofitted with the necessary emission control technologies, reducing demand for thermal coal. On December 15, 2011, the EPA finalized a supplemental rulemaking to require Iowa, Michigan, Missouri, Oklahoma and Wisconsin to make summertime reductions to nitrogen oxide emissions under the CSAPR ozone-season control program.

    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.

    Mercury and Hazardous Air Pollutants.  On December 16, 2011, the EPA signed a rule that would regulate the emission of mercury and other metals, fine particulates and acid gases such as hydrogen chloride from coal- and oil-fired power plants, referred to as "MATS." Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed. 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. The North American Electric Reliability Corporation in its 2011 Long-Term Reliability Assessment noted that CSAPR, MATS and other proposed regulations could accelerate the retirement of a significant number of coal-fired power plants. We continue to evaluate the possible scenarios associated with CSAPR and MATS and the effects they may have on our business and our results of operations, financial condition or cash flows.

    Regional Haze, New Source Review and Ozone.  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. On December 23, 2011, the EPA Administrator signed a final rule under which the emission caps imposed under the CSAPR for a given state would supplant the obligations of that state with regard to visibility protection. That rule has not yet been published, and the EPA's plans about publishing this rule in light of the stay of the CSAPR have yet to be announced. In addition, the EPA's new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringent air emissions control equipment required of new plants. There is pending litigation to force the EPA to list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the Clean Air Act and establish standards to reduce emissions from sources of methane and other emissions related to coal mines.

17


Table of Contents

Global Climate Change

        There are three important sources of GHGs associated with the coal industry. The end use of our coal in electricity generation is a source of GHGs. Combustion of fuel for mining equipment used in coal production is another source of GHGs. In addition, coal mining can release methane, a GHG, directly into the atmosphere. These emissions from coal consumption and production are potentially subject to regulation as part of regulatory initiatives to address global climate change and global warming. These regulatory initiatives may increase our costs and decrease demand for our coal.

        The Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (the "Kyoto Protocol") became effective in 2005, and bound those developed countries that ratified it (which the U.S. has not, to date, done) to reduce their global GHG emissions. Discussions to develop a treaty to replace the Kyoto Protocol after its expiration in 2012 are still ongoing. Any future global agreement on climate change could further reduce demand for our coal.

        The EPA is attempting to regulate GHG emissions using existing statutory authorities. In 2009, the EPA issued a final finding that the presence of carbon dioxide and certain other GHGs in the atmosphere endanger public health and welfare of current and future generations. Legal challenges to these findings have been asserted, and Congress is considering legislation to delay or repeal the EPA's actions, but we cannot predict the outcome of these efforts. The EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act. These rules are currently subject to judicial challenge, but the U.S. Court of Appeals for the District of Columbia Circuit has refused to stay their implementation while the challenges are pending. Among the rules promulgated after the EPA's endangerment finding was the Tailoring Rule, which requires that all new or modified stationary sources of GHGs that will emit more than 75,000 tons of carbon dioxide per year and are otherwise subject to Clean Air Act regulation, and any other facilities that will emit more than 100,000 tons of carbon dioxide per year to undergo prevention of significant deterioration ("PSD") permitting. PSD permitting requires that the permitted entity adopt the best available control technology. Under a consent decree with environmental groups, the EPA is expected to finalize new source performance standards ("NSPS") for electric power generation facilities in 2012. As of early December 2011, the EPA reportedly has prepared a proposal to regulate GHG emissions from only new plants, not existing ones, but that proposal is pending review at the Office of Management and Budget, and is not yet public. The EPA's failure to propose rules by the required date will delay final action as well.

        The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including coal-fired electric power plants, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

        As a result of revisions to its preconstruction permitting rules that became fully effective on January 2, 2011, the EPA is now requiring new sources, including coal-fired power plants, to undergo control technology reviews for GHGs (predominately carbon dioxide) as a condition of permit issuance. These reviews may impose limits on GHG emissions, or otherwise be used to compel consideration of alternatives fuels and generation systems, as well as increase litigation risk for—and so discourage development of—coal-fired power plants.

        Various states and regions have adopted GHG 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 GHGs by certain facilities. A number of states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. These and other current or future global climate change laws, regulations, court orders or other legally enforceable mechanisms may in the future require additional controls on coal-fired power plants and

18


Table of Contents

industrial boilers and may even cause some users of coal to switch from coal to alternative sources of fuel.

        Likewise, GHG 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, several environmental groups commented on the global climate change discussion within an EIS document for the federal coal lease application for the West Antelope II LBA, which we nominated. Furthermore, the federal coal leases for the West Antelope II LBA, which we acquired in 2011, are the subject of pending legal challenges filed against the BLM and Secretary of the Interior by environmental organizations. Disputes regarding the level of evaluation required for climate change could complicate and protract the time required to obtain coal leases on a timely basis which could have an adverse impact on our business.

Clean Water Act

        The Clean Water Act ("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 spent 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. Failure to comply with the CWA or NPDES permits can lead to the imposition of 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. For instance, 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, which may lead to the adoption of more stringent discharge standards for our coal mines and could require more costly treatment.

      Anti-degradation policies may increase the cost, time and difficulty associated with obtaining and complying with NPDES permits and may also require more costly treatment.

    Dredge and Fill Permits.  Many mining activities, including the development of settling ponds and other impoundments, require a Section 404 permit from the Army Corps of Engineers (the "Corps"). Generally speaking, these Section 404 permits allow the placement of fill materials into navigable waters of the United States including wetlands, streams, and other regulated areas. The Corps has issued 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. NWP 21s are typically reissued for a five-year period and require appropriate mitigation, and permit holders must receive explicit authorization from the

19


Table of Contents

      Corps before proceeding with proposed mining activities. We currently utilize NWP 21 authorizations for our operations in Wyoming and Montana. Although the Corps has suspended the use of NWP 21 in six Appalachian region states, we have no operations in these states. To date, we are unaware of any intent by the Corps to similarly restrict the use of NWP 21 in the states where we operate.

      Because of the U.S. Supreme Court's divided decision in Rapanos v. United States, there is some regulatory uncertainty about what constitutes a jurisdictional wetland. On March 18, 2010, the Corps of Engineers determined that there are no jurisdictional wetlands at our Spring Creek mine. On March 22, 2011, the Corps of Engineers authorized proposed operations under NWP 21 for our Antelope mine. The Antelope mine is currently working on an individual permit to seek authorization for future activities. This individual permit is expected to be submitted in March of 2012. On March 30, 2011, the Corps of Engineers authorized proposed operations under NWP 21 for our Cordero Rojo mine. This authorization is valid until March 18, 2013. All jurisdictional determinations are resolved, where applicable. Our Wyoming coal mines continue to operate under their respective NWP 21 permits. We believe that the pending jurisdictional wetland determinations are likely to reduce the waters that are currently subject to NWP 21 permitting requirements, with concomitant decreases in the cost and time burdens associated with NWP 21 permit compliance.

Resource Conservation and Recovery Act

        The EPA determined that coal combustion wastes do not warrant regulation as hazardous wastes under the Resource Conservation and Recovery Act ("RCRA") in May 2000. Most state hazardous waste laws do not regulate coal combustion wastes as 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. Under both options, the EPA would establish dam safety requirements to address the structural integrity of surface impoundments to prevent catastrophic releases. The EPA conducted additional information collections in late 2011 and was expected to issue a final decision by the end of 2011. The EPA did not address in the proposed regulations the use of coal combustion wastes as minefill, but indicated that it would separately work with the OSM in order to develop effective federal regulations ensuring that such placement is adequately controlled. 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

20


Table of Contents

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. In the latter part of 2011, BLM drafted a proposed Instruction Memorandum on sage-grouse for 2012 finalization and began formal planning processes for conservation measures for the species. These actions could result in more stringent requirements being issued by the BLM. Should more stringent protective measures be applied, 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. On June 29, 2010, the USFWS issued a notice reinstating the proposed rule relating to the listing of the mountain plover as threatened under the ESA and requesting public comment. In May 2011, the USFWS determined not to list the mountain plover as threatened, however the species status could be reviewed in the future. If a listing determination results, it could lead to new land use restrictions to protect nesting plovers in Wyoming and Montana. We have not determined its possible impact on our operations, although a listing could adversely impact our mining operations and costs.

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

21


Table of Contents

possible that our use of explosives in connection with blasting operations may subject us to the Department of Homeland Security's new chemical facility security regulatory program.

Other Environmental Laws

        We are required to comply with numerous other federal, state and local environmental laws and regulations in addition to those previously discussed. These additional laws include, for example, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act.

Available Information

        We file annual, quarterly and current reports, and amendments to those reports, proxy statements and other information with the Securities and Exchange Commission ("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 Inc., 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.

22


Table of Contents

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 adversely affected and you may lose all or a significant part of your investment.

Risks Related to Our Business and Industry

A substantial or extended decline in the prices we receive for our coal could reduce our revenues and profitability and decrease the value of our coal reserves.

        Our revenues, results of operations and the value of our coal reserves depend on the prices we receive for our coal. Prices for coal tend to be cyclical, and over the last several years have become more volatile. The prices we receive for our coal depend upon factors beyond our control, including:

    domestic and foreign supply and demand for coal, including Asian and other foreign demand for U.S. coal exports;

    domestic and foreign demand for electricity;

    domestic and foreign economic conditions;

    the quantity, quality and price of coal available from domestic and foreign competitors or the resale market;

    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;

    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 or utility industries, such as legislation that limits carbon dioxide or sulfur dioxide emissions or provides for increased funding, subsidies or other incentives for, or mandates the use of, alternative energy sources;

    domestic and foreign governmental regulations and taxes, including with respect to 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;

    market price fluctuations for sulfur dioxide emission allowances;

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

    the other risks described in this Item 1A.

        A substantial or extended decline in the prices we receive for our coal due to these or other factors could reduce our revenues and profitability and value of our coal reserves.

Competition with domestic and foreign coal producers and with producers of natural gas and other competing energy sources may negatively affect our sales volumes and our ability to sell coal at a favorable price.

        The coal industry is highly competitive. We compete directly with all domestic and many foreign coal producers, and indirectly with other energy producers throughout the U.S. and, for our export

23


Table of Contents

sales, internationally. In addition to the price of coal, coal quality, and transportation costs, demand for coal also has a significant impact on our ability to compete domestically and internationally for coal sales. Demand for coal depends upon a number of factors, including:

    general economic conditions and weather patterns, both of which are significant contributors to the demand for electricity;

    port and shipping capacity, including ocean freight rates;

    delivered prices for coal, including the relative costs of transportation from our mine site and competing mines;

    availability and cost of alternative fuel sources, such as natural gas;

    technological developments; and

    environmental and other governmental regulations, including EPA regulations.

        Demand for U.S. coal exports has fluctuated over the last decade because of these and other factors. A decline in domestic demand for coal, or a decline in foreign demand for U.S. coal, could cause significant downward pressure on coal prices. Furthermore, overcapacity and increased production in the future, similar to the activities that occurred during the mid 1970s and early 1980s, could result in additional production capacity throughout the industry, causing increased competition and lower coal prices, materially reducing our revenues and profitability.

        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 the price of natural gas, or sustained low natural gas prices, could cause demand for coal to decrease and adversely affect the price of our coal. For example, the average price of natural gas declined from $4.15 per thousand cubic feet as of December 2010 to $3.17 per thousand cubic feet as of December 2011, leading to, in some instances, fuel switching and decreased coal consumption by electricity-generating utilities. Sustained low natural gas prices may also cause utilities to phase out or close existing coal-fired power plants or reduce construction of any new coal-fired power plants, which could have a material adverse effect on demand and prices received for our coal.

        Legislation requiring the use and dispatch of 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. If alternative energy sources, such as hydroelectric, wind or solar, become more cost-competitive, demand for coal could decrease and cause a decrease in the price of coal.

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

        According to the EIA, the market share of coal used in electric generation is expected to decrease from 42% to 39% from 2012 to 2035 as a result of various factors, including low natural gas prices, regulatory and environmental pressures on coal-fired electricity generation and domestic and foreign economic conditions and associated electricity demand. A growing portion of our coal sales in recent years has been into export markets in Asia, and we are seeking to make additional export sales to Asia and potentially other international locations. Our ability to maintain 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. At present, there is limited terminal capacity for the export of PRB coal to foreign markets. 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

24


Table of Contents

factors. If we fail to maintain terminal capacity, or are denied access to existing or any future terminals for the export of our coal on commercially reasonable terms, or at all, our results from our export transactions will be materially adversely affected. International 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.

        In addition, from time to time we enter into "take-or-pay" contracts for rail and port capacity related to our export sales. These contracts require us to pay for a minimum quantity of coal to be transported on the railway or through the port regardless of whether we sell any coal. If we fail to acquire sufficient export sales to meet our minimum obligations under these take-or-pay contracts, we are still obligated to make payments to the railway or port, which could have a negative impact on our cash flows, profitability and results of operations.

Our business, financial condition and results of operations may be adversely affected by unfavorable global or U.S. economic and market conditions.

        In recent years, the global economic downturn, particularly with respect to the U.S. economy, and the global financial and credit market disruptions had a negative impact on us and the coal industry generally. 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, coal inventory by our customers increased during this time leading to our customers curtailing future orders and causing a decrease in coal prices. 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.

        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. Future economic downturns or further disruptions in the financial and credit markets could negatively impact our business, financial condition and results of operations.

Decreases in U.S. and global demand for electricity due to economic, weather or other conditions could negatively affect coal prices.

        Our coal customers primarily use our coal as fuel for electricity generation. Overall economic activity and the associated demands for power by industrial users can have significant effects on overall electricity demand and can be caused by a number of factors. An economic slowdown can significantly slow the growth of electricity demand and could result in reduced demand for coal. For example, declines in the rate of international economic growth in countries such as China, India or other developing countries could impact the demand for U.S. coal. Weather patterns can also greatly affect electricity demand. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increase 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. For example, in 2009, several regions in the U.S. experienced a cool summer, causing the coal inventory of our customers to grow and demand for coal to decrease. Decreases in coal demand for these or other reasons could cause downward pressure on coal prices and would negatively impact our results of operations.

25


Table of Contents

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

        We mine coal at surface mining operations located in Wyoming and Montana. Our coal mining operations are subject to a number of operating risks. These operating risks include, among others:

    poor mining conditions resulting from geological, hydrologic, ground or other conditions, which may cause instability of highwalls or spoil-piles or cause damage to nearby infrastructure such as roads, power lines, railways and gas pipelines;

    critical mining and plant equipment failures, unexpected maintenance problems or damage from fire, flooding or other events;

    adverse weather and natural disasters, such as heavy rains, flooding, droughts, dust 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;

    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; and

    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.

        Because we maintain very little produced coal inventory, disruptions in our operations due to these or other risks could negatively impact or even halt production and shipments, significantly increase the cost of mining and impact our ability to meet our contractual obligations to customers and others, which could have a material adverse effect on our results of operations. We maintain insurance policies that provide limited coverage for some of these risks, although there can be no assurance regarding the extent, if any, to which these risks would be covered by our insurance policies.

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

        Our profitability depends substantially on our ability to mine, in a timely and 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. We primarily acquire additional coal through the federal competitive leasing process, but we also enter into state and private coal leases as well as acquire coal from private third parties. If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted. Our ability to obtain additional coal reserves in the future could also be limited by a number of factors, any of which could impact our business and growth strategy, including:

    the availability of cash we generate from our operations;

    available financing and restrictions under our debt instruments;

    competition from other coal companies for properties;

    lack of suitable acquisition or LBA opportunities; or

26


Table of Contents

    delay in the federal leasing process caused by third-party legal challenges or the inability to acquire coal properties or federal coal leases on commercially reasonable terms.

        Any significant delay in acquiring reserves could negatively impact our production rate. We will need to acquire additional coal reserves that can be mined on an economically recoverable basis to maintain our production capacity and competitive position. We may be unable to mine future reserves as profitably as we do at our current operations. The price we receive for our coal also impacts how economically we can recover our existing coal. Our ability to develop economically recoverable reserves will be materially adversely impacted if prices for coal sold decrease significantly.

Because most of the coal in the vicinity of our mines is owned by the U.S. federal government, our future success and growth would be affected if we are unable to acquire or are significantly 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 federal competitive leasing process is our primary means of acquiring additional reserves. There is no requirement that the federal government must lease its coal. Furthermore, there is no requirement that the federal government must give preference to any LBA applicant which means our bids for federal coal leases may compete with other coal producers' bids. Over time, federal coal leases have become increasingly more competitive and expensive to obtain, and the review process to submit an LBA for bid continues to lengthen. We expect this trend to continue. The increasing size of potential LBA tracts may make it easier for new mining operators to enter the market on economic terms and may, therefore, increase competition for federal coal leases. Increased opposition from non-governmental organizations and other third parties may also lengthen, delay or complicate the LBA process. In order to win a lease in the LBA process and acquire additional coal, our bid for a coal tract must meet or exceed the fair market value of the coal based on the internal estimates of the BLM, which is not published. Any failure or delay in acquiring a coal lease through the LBA process, or the inability to do so on economic terms, could cause our production to decline, materially adversely affecting our business, cash flows and results of operations. For example, the West Antelope II leases we were awarded through the LBA process in 2011 are subject to pending legal challenges against the BLM and the Secretary of the Interior by environmental organizations, which could materially impact our ability to mine the coal subject to those leases or delay our access to mine the coal.

        The LBA process also requires us to acquire rights to mine from certain surface owners overlying the coal before the federal government will agree to lease the coal. Surface rights in the PRB 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 ("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 coal underlying their surface. 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 federal coal leases on land owned by the QSO. Our profitability could be materially adversely affected if the prices to acquire land owned by QSOs increase.

27


Table of Contents

If we are unable to acquire surface rights to access our coal, we may be unable to obtain a permit or otherwise be unable 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.

        After we acquire coal we are required to obtain a permit to mine the coal through the applicable state agencies before we are allowed to begin mining. 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. 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 the coal we have acquired or may find that we cannot mine the coal at a profit or at all. If we are denied a permit, this would create significant delays and restrictions in our mining operations and materially 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 adversely affect our results of operations. Failure to successfully negotiate access for surface rights overlying coal that we control in a timely manner may also result in significant accounting charges, which could have a material adverse impact on our results of operations.

Defects in title or the loss of a leasehold interest in, or superior or conflicting property rights impacting, reserves or surface rights could limit our ability to mine our coal reserves and adversely impact our operations and costs.

        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. 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.

        In addition, these leasehold interests may be subject to superior property rights of other third parties. The federal government leases many different mineral rights in addition to coal, such as coalbed methane, natural gas and crude oil rights. 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 and may affect our ability to operate as planned if our title is not superior or cost-effective arrangements cannot be timely negotiated. We are regularly in negotiations with third parties in an effort to address potentially conflicting mineral development. These negotiations may not be effective. In that event, our mine plans, future costs and production rates may be adversely impacted. Anticipated oil and gas development is expected to increase the frequency of these potential conflicts.

        Further, the vast majority of our coal interests are acquired by lease from state or federal governments. If any of our leases are terminated, for lack of diligent development or otherwise, we would be unable to mine the affected coal and our business and results of operations could be materially adversely affected.

28


Table of Contents

Acquisitions are a potentially important part of our long-term growth strategy and involve a number of risks, any of which could cause us not to realize the anticipated benefits.

        Acquisitions are a potentially important part of our long-term growth strategy, and we may pursue acquisition opportunities in the future in the U.S. and other jurisdictions. If we fail to accurately estimate the future results and value of an acquired business or are unable to successfully integrate the businesses or properties we acquire, our business, financial condition or results of operations could be negatively affected, and we may be unable to grow our business. 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 acquired coal 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 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;

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

    unanticipated liabilities associated with the acquired companies.

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

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

        As a mining company, we must obtain a number of permits and licenses from various federal, state and local agencies and regulatory bodies that impose strict regulations on environmental and operational matters in connection with our coal operations, including restricting the number of tons we may mine under our air quality permits. 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 make compliance more difficult or impractical, and may possibly preclude the continuance

29


Table of Contents

of ongoing operations, impact the development of future mining operations or restrict the amount of our production. 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 EIS prepared in connection with applicable regulatory processes. These groups may also participate in the permitting and licensing process, including bringing citizens' lawsuits to challenge the issuance of permits, the validity of an EIS or performance of mining activities. For example, the EIS and other regulatory matters associated with the West Antelope II LBAs are being legally challenged by several non-governmental organizations, which could create a delay or uncertainty in acquiring the permit or mining the coal underlying the coal lease. If this or any other permits or licenses are not issued or renewed in a timely fashion or at all, or if permits issued or renewed are conditioned in a manner that restricts our ability to efficiently and economically conduct our mining activities, we could suffer a material reduction in our production, an impairment of our mineral rights, and our cash flows or profitability could be materially adversely affected.

Existing and future legislation, treaties, regulatory requirements and public concerns relating to GHG emissions could negatively affect our customers and reduce the demand for coal as a fuel source, causing coal prices and sales of our coal to materially decline.

        There are three important sources of GHGs associated with the coal industry. The end use of our coal in electricity generation is a source of GHGs. Combustion of fuel for mining equipment used in coal production is another source of GHGs. In addition, coal mining can release methane, a GHG, directly into the atmosphere. These emissions from coal consumption and production are potentially subject to regulation as part of regulatory initiatives to address global climate change and global warming. Various international, federal, regional and state proposals are being considered to limit emissions of GHGs, including possible future U.S. treaty commitments, new federal or state legislation that may, among other things establish a cap-and-trade regime, and regulation under existing environmental laws by the EPA and other regulatory agencies. Future regulation of GHG emissions may require additional controls on, or the closure of, coal-fired power plants and industrial boilers or may restrict the construction of new coal-fired power plants. These regulatory initiatives may increase our costs and decrease demand for our product, and may lead to increased demand for domestic electricity fired by natural gas because gas-fired plants are cheaper to construct, and permits to construct these plants can be easier to obtain.

        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. Private litigation has also been brought against industry participants based on GHG-related concerns. The U.S. Supreme Court recently held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, but tort-type liabilities and other GHG-related claims against utilities and energy producers may be asserted. For example, residents and property owners along the Mississippi Gulf coast filed litigation against approximately 90 companies in energy, fossil fuels and chemical industries, including PRB and other domestic coal companies, alleging that the defendants caused the emission of GHGs that contributed to global warming, which in turn caused a rise in sea levels and added to the ferocity of Hurricane Katrina in 2005, which combined to destroy the plaintiffs' property. If this or other GHG-related litigation is successful, the coal industry and our company may be materially adversely impacted. See "Business—Environmental and Other Regulatory Matters—Global Climate Change."

30


Table of Contents

Extensive environmental laws, including existing and potential future legislation, treaties and 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, CSAPR, if implemented as drafted, initially requires 28 states in the Midwest and eastern seaboard of the U.S. to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. On December 30, 2011, the U.S Court of Appeals for the District of Columbia Circuit stayed the implementation of CSAPR pending resolution of judicial challenges to the rules and ordered the EPA to continue enforcing CAIR until the pending legal challenges have been resolved. CSAPR is one of a number of significant regulations that the EPA has issued or expects to issue that will impose more stringent requirements relating to air, water and waste controls on electric generating units. These rules include the EPA's pending new requirements for coal combustion residue ("CCR") management which may further regulate the handling of wastes from the combustion of coal. In addition, on December 16, 2011, the EPA signed a rule to reduce emissions of toxic air pollutants from power plants. Specifically, these mercury and air toxic standards ("MATS") for power plants will reduce emissions from new and existing coal- and oil-fired electric utility steam generating units. We continue to evaluate the possible scenarios associated with CSAPR, CCR and MATS and the effects they may have on our business and our results of operations, financial condition or cash flows.

        Considerable uncertainty is associated with 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. 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. See "Business—Environmental and Other Regulatory Matters—Clean Air Act."

Our mining operations are subject to extensive environmental, health, safety or other laws and regulations that could materially increase our costs or limit our ability to produce and sell coal.

        Our mining operations are subject to extensive federal, state and local environmental, health and safety, transportation, labor and other laws and regulations. Examples include those relating to:

    employee health and safety;

    emissions to air and discharges to water;

    plant and wildlife protection, including the potential classification of the sage-grouse and the mountain plover as endangered or threatened species;

    the reclamation and restoration of properties after mining or other activity has been completed;

    remediation of contaminated soil, surface and groundwater; and

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

31


Table of Contents

        Furthermore, we must compensate employees for work-related injuries through our workers' compensation insurance funds. The erosion through tort liability of the protections we are currently provided by workers' compensation laws could increase our liability for work-related injuries.

        The April 2010 explosion at Massey Energy Company's Upper Big Branch Mine has had significant impacts on the regulation of mine safety matters at the federal and state levels. For example, federal authorities have announced special inspections of coal mines to evaluate several safety concerns, including the accumulation of coal dust and the proper ventilation of gases such as methane. In addition, federal authorities have announced that they are considering changes to mine safety rules and regulations which could potentially result in additional or enhanced required safety equipment, more frequent mine inspections, stricter and more thorough enforcement practices and enhanced reporting requirements. Any new environmental, health and safety requirements may be replicated in the states in which we operate and could increase our operating costs or otherwise prevent, delay or reduce our planned production, any of which could adversely affect our financial condition, results of operations and cash flows.

        The costs, liabilities and requirements associated with complying with these requirements are often significant and time-consuming and may delay commencement or continuation of exploration or production. These factors could have a material adverse effect on our results of operations, cash flows and financial condition. New legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations may also require us to change operations significantly or incur increased costs. For example, on November 17, 2011, several environmental groups sued the EPA in Washington federal court to compel the EPA to include coal mines on the list of stationary sources governed by air pollution performance standards. Any imposition of air emission standards on coal mines or any other such changes could have a material adverse effect on our financial condition and results of 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 may result in significant costs to us to correct such violations, as well as civil or criminal penalties and limitations or shutdowns of our operations.

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

        Federal and state regulatory agencies have the authority following significant health and safety incidents, such as fatalities, to order a mine to be temporarily or permanently closed. If this were to occur, 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.

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

32


Table of Contents

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.

        We may incur material costs and liabilities resulting from claims for damage 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 adversely affected.

Significant increases in taxes we pay on the coal we produce, such as royalties or severance and production taxes, including as a result of governmental audits, could materially adversely affect our profitability.

        We pay federal, state and private royalties and federal, state and county severance and production taxes on the coal we sell. A substantial portion of our royalties and severance 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 29.2% and 30.5% of proceeds from the coal we sold for the years ended December 31, 2011 and 2010, respectively. The calculations used to determine royalty or severance and production tax payments are complex and subject to interpretation, making it difficult to estimate such payments. If royalties or severance and production tax rates were to significantly increase our results of operations could be materially adversely affected. For example, the Wyoming state severance tax is significantly less than the state severance tax in Montana. If Wyoming were to increase this tax or any other tax applicable to our Wyoming operations, our profitability could be reduced and our results of operations negatively affected. In addition, if we are required to make additional payments (including related interest and penalties) as a result of pending or future governmental audits, our results of operations would be negatively impacted.

Failure to maintain our surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and materially 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 costs, reclamation costs, and federal and state workers' compensation costs, including black lung. The primary methods we use to meet those obligations are to provide a third-party surety bond or a letter of credit. As of December 31, 2011, we had outstanding surety bonds with third parties of $568.1 million. Surety bonds are typically renewable on a yearly basis. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral, unfavorable terms or higher fees upon those renewals. Our failure to retain, or inability to acquire, surety bonds or letters of credit or to provide a suitable alternative could adversely affect our ability to mine or lease coal, which would materially adversely affect our business and results of operations. 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.

        Furthermore, while 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

33


Table of Contents

remaining payments, which could adversely impact our cash flows and the amount of availability under our credit facility, if such bonds could be obtained at all.

        In addition, if federal or state laws are amended to require certain forms of financial assurance other than surety bonds, such as letters of credit, obtaining them, if we could obtain them at all, could have a material negative impact on our liquidity and results of operations.

The availability and reliability of sufficient transportation capacity and increases in transportation costs could materially adversely affect the demand for our coal or impair our ability to supply coal to our domestic and export customers.

        Transportation costs represent a significant portion of the total cost of coal for our domestic and export customers. The cost and availability of transportation is a key factor in a customer's purchasing decision and impacts our coal sales and the price we receive for our coal. Coal could become a less competitive source of energy if the costs of transportation increase or the availability or capacity of rail lines or export terminals is insufficient. Transportation costs and availability could also make our coal less competitive than coal produced from other regions.

        Our ability to sell coal to our customers depends primarily upon third-party rail systems and export terminals. If our customers are unable to obtain 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. Export terminals are also subject to permit requirements and challenges from environmental organizations which may make it complicated or expensive to expand existing terminal capacity or open new export terminals in a timely and cost-effective manner. In addition, 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. Similarly, being denied access to an export terminal could significantly affect our export sales, materially decreasing our revenues. Our ability to open new mines or expand existing mines may also be affected by the access to, and availability and cost of rail, export terminal or other transportation systems available for servicing these mines.

        Typically, our coal customers contract for, and pay directly for, transportation of coal from the mine or port to the point of use. However, our export deals require us to enter into transportation agreements pursuant to which we arrange for rail transport and port charges. Our ability to supply coal to our customers and our customers' ability to take our coal may be impacted by the disruption of these transportation services because of weather-related problems; mechanical difficulties; maintenance shut-downs; environmental, political and regulatory issues; 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; accidents; terrorism or domestic catastrophe or other events. For example, in the spring and summer of 2011, the Midwest region experienced severe flooding which disrupted rail service to mines in the PRB and affected the ability of those customers who were impacted by the flooding to take coal deliveries. Any similar disruption in the future could negatively impact our results of operations.

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

        Our business plan and strategy are dependent upon our acquisitions of additional reserves, which require substantial capital expenditures. We also require capital for, among other purposes:

    acquisition of surface rights;

    equipment and the development of our mining operations;

34


Table of Contents

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

        SMCRA and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining. We accrue for the costs of current mine disturbance and final mine closure. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our experience. Estimates of reclamation liability at the Decker mine are provided to us by the Decker mine. The amounts recorded are dependent upon a number of variables, including the estimated future asset retirement costs, estimated proven reserves, assumptions involving profit margins of third-party contractors, inflation rates, discount rates and assumed credit-adjusted, risk-free rates. Furthermore, these obligations are unfunded. If our accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be materially adversely affected.

We do not operate the Decker mine and our results of operations could be adversely affected if the other 50% owner fails to effectively operate the mine or fails to perform its obligations. In addition, our credit arrangements may limit our ability to contribute cash to the Decker mine.

        We hold a 50% non-operating interest in the Decker mine in Montana through a joint venture agreement with the other 50% owner. The other 50% mine owner has responsibility for the day-to-day operations of the Decker mine. 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 other 50% mine owner fails to operate the Decker mine effectively, our results of operations could be adversely affected.

        We share the profits, losses, operating expenses, reclamation obligations and liabilities and assets associated with the Decker mine equally with the other 50% owner and may be required to contribute cash or other property and equipment and 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 Decker mine may be adjusted proportionally. CPE Resources's current debt instruments and future credit arrangements may limit our ability to make contributions to the Decker joint venture.

35


Table of Contents

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 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 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. For example, we previously experienced a severe tire shortage in 2005 that lasted several years. This tire shortage increased the direct cost of tires and caused us to change our operating practices to increase tire life. 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.

        Furthermore, operating expenses at our mining locations are sensitive to changes in certain variable costs, particularly diesel fuel prices, which is our largest variable cost after personnel costs. Our profitability depends on our ability to adequately control our costs, particularly with respect to diesel fuel. Historically, we have not entered into hedge or other arrangements to offset the market price volatility of diesel fuel prices. Any increase in the price we pay for diesel fuel will have a negative impact on our results of operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Cost of Product Sold" in Item 7 and "Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risks" in Item 7A.

Changes in the fair value of derivative instruments that are not accounted for as a hedge could cause volatility in our earnings.

        From time to time, we may enter into certain derivative financial instruments to help manage our exposure to future coal prices, particularly export coal prices. Derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Changes in fair value are recognized either in earnings or equity, depending on whether the transaction qualifies for cash flow hedge accounting, and if so, how effective the derivatives are at offsetting price movements in the underlying exposure. To the extent these derivative financial instruments do not qualify for hedge accounting or we choose not to designate them for hedge accounting, we are required to record changes in the fair value of these derivative financial instruments in our Consolidated Statement of Operations, resulting in increased volatility in our income in future periods. In addition, to the extent that we hedge our exposure to future coal prices, we may be prevented from realizing the benefits of price increases.

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

        We base our estimates of reserves on engineering, economic and geological data assembled and analyzed by our internal geologists and engineers, which are reviewed by an independent consultant every two years. 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

36


Table of Contents

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:

    coal characteristics such as Btu and sulfur content;

    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;

    future coal prices;

    equipment and productivity;

    operating costs, including for critical supplies such as fuel, tires and explosives;

    capital expenditures and development and reclamation costs;

    the percentage of coal ultimately recoverable;

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

    timing for the development of the reserves.

        Any changes to the above factors and assumptions could cause our estimates of the quantities and qualities of economically recoverable coal to vary significantly. Changes to the above factors and assumptions could also materially impact how we classify our reserves based on risk of recovery and our estimates of future net cash flows expected from these properties. 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 proven and probable reserves estimates 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, which may not reflect favorable then-existing prices for coal or may affect our profitability if we cannot adequately control the costs of production for coal underlying such contracts.

        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. For the year ended December 31, 2011 approximately 81% of our revenues were derived from coal sales that were made under long-term coal sales agreements. The prices for coal sold under these agreements are typically fixed for an agreed amount of time. Pricing in some of these contracts is subject to certain adjustments in later years or under certain circumstances, and may be below the current market price for similar type coal at any given time, depending on the time frame of the contract.

        As a consequence of the substantial volume of our forward sales, our ability to capitalize on near term rises in coal prices is limited. We have less coal available to sell under short-term contracts or on the spot market and we similarly have fewer tons to commit under long-term contracts at higher prices. Our ability to realize higher prices is also restricted if customers elect to purchase additional volumes of coal, which is allowable under some contracts, at contract prices that are lower than spot prices.

        Furthermore, to the extent our costs increase but pricing under our long-term coal sales contracts remains fixed, we may be unable to pass such increasing costs on to our customers. If we are unable to control our costs, our profitability may be negatively impacted, adversely affecting our results of operations.

37


Table of Contents

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 adversely affect our business and results of operations.

        In past years, we have experienced customers being less willing to enter into long-term coal sales contracts as they continue to adjust to increased price volatility, increased fungibility of coal products, frequently changing regulations and the increasing deregulation of their industry. In addition, the prices for coal in the spot market 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.

        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 and profitability.

We are exposed to counterparty risk with our customers, trading partners, financial institutions, and other parties with whom we conduct business.

        We face an increased risk that we do not receive payment for coal sold and delivered if the creditworthiness of any of our counterparties deteriorates or if any of our counterparties become subject to bankruptcy proceedings. The creditworthiness of these counterparties depends on any number of factors, including the economic volatility and tightening of credit markets, and deregulation of the U.S. utilities markets, allowing utilities to sell their power plants to their non-regulated affiliates or third parties that may have credit ratings that are below investment grade. Competition with other coal suppliers could cause us to extend credit to customers and on terms that could increase the risk of payment default.

        We have contracts to supply coal to energy trading and brokering companies, under which they purchase the coal for their own account or resell to domestic and foreign end users. If the creditworthiness of these energy trading and brokering companies declines, this would increase the risk that we may not be able to collect payment for all coal sold and delivered to or on behalf of those companies. Furthermore, if any of these companies seek to renegotiate or cancel sales of coal because of fluctuations in spot prices for coal, issues with their end users accepting the coal or other factors, we may be unable to sell previously anticipated volumes of coal at favorable prices or at all. We also enter into derivative financial instruments with a number of financial institutions. If one or more of these institutions were to default on its future obligation to us, our cash flows and results of operations would be negatively impacted.

        In certain circumstances we may be entitled to demand credit enhancements or withhold shipments of coal from these parties if we determine they are not creditworthy. However, these protections may be insufficient to cover our risks or could cause us to resell the coal on the spot market at unfavorable prices or not at all.

        We have significant cash balances, which we may invest from time to time in marketable securities issued by various counterparties including the U.S. government and U.S. government sponsored entities, municipal entities, financial institutions and other corporations. If any of these counterparties fail, we could lose the principal invested with such counterparties, which would materially adversely impact our business, liquidity, and results of operations.

38


Table of Contents

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.

        Price adjustment, "price reopener" and other similar provisions in our long-term supply contracts may reduce the protection from short-term coal price volatility traditionally provided by these contracts. Most of our domestic sales and some of our international contracts contain provisions that allow for the base price of our coal 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. Some of our domestic 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. Our international contracts typically contain a fixed price for the first year of the contract with future years' prices to be negotiated at a specific point in time. If the parties fail to satisfactorily negotiate a price, the contract could be terminated. Any adjustment or renegotiations leading to a significantly lower contract price, or a termination of the contract, could result in decreased revenues.

        Our domestic 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. 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. Our domestic coal sales agreements also typically allow our customers to suspend performance in the event that the railroad fails to provide its services due to circumstances that would constitute a force majeure. In addition, our international contracts generally contain a clause that requires us to pay the demurrage fee charged by the vessel for delays in shipping the coal on behalf of our foreign customers.

        Most of our coal sales agreements also 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. 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.

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 and our failure to retain or attract qualified executives could have an adverse effect on our ability to operate our business.

        Efficient coal mining using modern techniques and equipment also 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 and typically compete for such positions with other industries, including oil and gas. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially 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

39


Table of Contents

laborers. If 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 adversely affected.

Our work force could become unionized in the future, which could negatively impact 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 negatively impact 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% non-operating 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 adversely affect its results and the value of our investment in the Decker joint venture.

Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war may materially 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 negatively impact our business. Furthermore, any such acts which directly affect our customers and their business may have negative consequences to our own operations. 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.

We face the risk of systems failures as well as security risks, including "hacking."

        The computer systems and network infrastructure we and others use could be vulnerable to unforeseen problems. These problems may arise in both our internally developed systems and the systems of our third-party service providers. Our operations are dependent upon our ability to protect computer equipment against damage from fire, power loss or telecommunication failure. Any damage or failure that causes an interruption in our operations could adversely affect our business. In addition, our computer systems and network infrastructure present security risks, and could be susceptible to hacking.

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, 2011, we had $600 million of senior notes outstanding and approximately $294.9 million of other long-term obligations incurred in connection with land acquisitions and federal

40


Table of Contents

coal lease payments. In addition, at December 31, 2011, $10.5 million of capacity under our $500 million revolving credit facility was being used for letters of credit securing our reclamation obligations reducing the capacity under the revolving credit facility to $489.5 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;

    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.

        We may incur substantially more debt in the future. If our indebtedness is further increased, the related risks that we now face, including those described above, could increase. Moreover, these risks also apply to certain of CPE Resources's domestic restricted subsidiaries that are guarantors of CPE Resources's indebtedness and may apply to CPE Inc. directly if CPE Inc. becomes a guarantor of CPE Resources's 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, as well as required payments under the Tax Receivable Agreement (See "Risk Factors—Other Risks Related to Our Corporate Structure and Common Stock"). Our ability to pay our debt depends upon our operating performance. 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 we may be required to issue equity. We may not be able to, at any given time, refinance our debt or sell assets and we may not be able to, at any given time, issue equity, in either case on acceptable terms or at all.

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 adversely affect our financial condition.

        Our 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 require compliance with various financial covenants. Because CPE Resources (which entered into the debt instruments) is our only direct operating subsidiary, complying with these restrictions and covenants may prevent us from taking actions that we believe would help us to grow our business. These restrictions could limit our

41


Table of Contents

ability to plan for or react to market conditions or meet extraordinary capital needs or otherwise restrict corporate activities.

        A failure to comply with any of these restrictions or covenants could have serious consequences to our financial condition or 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. Furthermore, 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. Under these circumstances, we might not have sufficient funds or other resources to satisfy all of our obligations. 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.

        Upon the occurrence of certain transactions constituting a "change in control" as defined in the indenture, holders of the senior notes have the right to 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. Furthermore, a "change in control" as defined in our credit facility is considered an event of default. These provisions could make it more difficult or more expensive for a third party to acquire us even where the acquisition could be beneficial to our stockholders.

Other Risks Related to Our Corporate Structure and Common Stock

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

        In connection with the IPO and the acquisition of our membership units of CPE Resources, we entered into the Tax Receivable Agreement with RTEA that requires us to pay to RTEA 85% of the amount of cash tax savings, if any, that we realize as a result of the increases in tax basis that we obtained in connection with the initial acquisition of our interest in CPE Resources, our subsequent acquisition of RTEA's remaining units in CPE Resources, as well as payments made by us under the Tax Receivable Agreement. Due to the size of the increases in the tax basis of our share of CPE Resources's tangible and intangible assets, as well as the increase in our basis in the equity of CPE Resources's subsidiaries and assets held by those subsidiaries, we expect to make substantial payments to RTEA under the Tax Receivable Agreement. As a result of our 2010 acquisition of RTEA's remaining units in CPE Resources, we received a further step-up in our tax basis and, accordingly, our obligations under the Tax Receivable Agreement to pay RTEA 85% of any benefits we receive as a result of such further step-up significantly increased. Our 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 ownership of an interest in CPE Resources or our available cash resources. Based on the tax basis of our assets as of December 31, 2011 and CPE Resources's operating plan, the future payments under the Tax Receivable Agreement are estimated to be approximately $170.6 million in the aggregate and are estimated to be payable over the next 32 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 coal assets beyond our existing coal reserve base, and as a result, we realize the full tax benefit of such increased tax basis (or an increased portion thereof).

42


Table of Contents

        Certain changes in control require us to make payments to RTEA, which could exceed our actual cash savings and could require us to provide credit support.    If we undergo a change in control other than a change in control caused by RTEA and we do not otherwise elect to terminate the Tax Receivable Agreement as discussed below, payments to RTEA under the Tax Receivable Agreement will continue on a yearly basis but will be based on an agreed upon set of assumptions. In this case, our assumed cash tax savings, and consequently our payments due under the Tax Receivable Agreement, could exceed our actual cash tax savings each year by material amounts. If we undergo such a change in control and our credit rating is impaired, we will be required to obtain credit support with regard to all remaining payments under the agreement. The change in 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 in control transaction with us.

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

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

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

Our previous separation from Rio Tinto could subject us and our stockholders to any number of risks and uncertainties.

        Prior to the IPO in November 2009, we were an indirectly held, wholly-owned subsidiary of Rio Tinto. As a result, the CPE Inc. directors at that time owed a fiduciary duty solely to Rio Tinto in its capacity as the sole owner of CPE Inc. and did not owe a fiduciary duty to our post-IPO stockholders. Upon the effectiveness of the IPO in November 2009, Rio Tinto's ownership of CPE Inc. was terminated and, as of that date, those directors no longer owe a fiduciary duty to Rio Tinto.

        Our 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 also includes 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

43


Table of Contents

a separate, stand-alone public company, our cost structure is different and 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.

        Furthermore, we entered into various agreements with Rio Tinto and its affiliates in connection with the IPO and separation from Rio Tinto. CPE Resources agreed to indemnify Rio Tinto for certain losses pursuant to these agreements. Because these agreements were entered into while we were part of Rio Tinto, some of the terms of these agreements are likely less favorable to us than similar agreements negotiated between unaffiliated third parties. Third parties may also seek to hold us responsible for liabilities of Rio Tinto that we did not assume in connection with the IPO and for which Rio Tinto agreed to indemnify us, including liabilities related to the Jacobs Ranch and Colowyo mines, as well as the uranium mining venture that we do not own. If those liabilities are significant and we are ultimately held liable for them, we may not be able to recover the full amount of our losses from Rio Tinto. Refer to the applicable exhibits listed in Item 15 of this Form 10-K for the complete terms and conditions of the principal outstanding agreements with Rio Tinto entered into in connection with our 2009 IPO.

If we are unable to maintain effective internal controls, our operating results and financial condition could be harmed.

        In 2009, as a new public company, we identified previously disclosed material weaknesses in our internal control over financial reporting. Such material weaknesses were remediated; however, we continue to be subject to a number of requirements as a public company, 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 the listing standards of New York Stock Exchange. These requirements have placed significant demands on our systems and resources. The Exchange Act requires, among other things, that we file annual, quarterly and current reports with respect to our business and financial condition. The Sarbanes-Oxley Act requires, among other things that we maintain effective disclosure controls and procedures and internal control over financial reporting, and also requires that our internal control over financial reporting be assessed by management and, for CPE Inc., attested to by our auditors as of December 31 of each year. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal control over financial reporting, significant resources and management oversight are required. As a result, our management'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. In addition, if we experience a material weakness, investors could lose confidence in our financial reporting, particularly if such weakness results in a restatement of our financial results, and our stock price could decline.

CPE Inc. is a holding company with no direct operations of its own and depends on distributions from CPE Resources to meet its ongoing obligations.

        CPE Inc. is a holding company with no direct operations of its own and has no independent ability to generate revenue. Consequently, its ability to obtain operating funds depends upon distributions from CPE Resources and payments under the management services agreement. Pursuant to its management services agreement, CPE Resources makes payments to CPE Inc. in the form of a management fee and cost reimbursements to fund CPE Inc.'s day-to-day operating expenses, such as payroll for its officers. However, if CPE Resources cannot make the payments pursuant to the management services agreement, CPE Inc. may be unable to cover these expenses.

        The distribution of cash flows by CPE Resources to CPE Inc. is subject to statutory restrictions under the Delaware Limited Liability Company Act and contractual restrictions under CPE Resources's debt instruments that may limit the ability of CPE Resources to make distributions. In addition, any distributions and payments of fees or costs are subject to CPE Resources's financial condition.

44


Table of Contents

        As the sole member of CPE Resources, CPE Inc. incurs income taxes on any net taxable income of CPE Resources. The debt instruments allow CPE Resources to distribute cash in amounts sufficient for CPE Inc. to pay its tax liabilities payable to any governmental entity, and, in the ordinary course of business, CPE Inc.'s obligations under the Tax Receivable Agreement, if any. To the extent CPE Inc. needs funds for any other purpose, and CPE Resources is unable to provide such funds for any reason, it could have a material adverse effect on our business, financial condition, results of operations or prospects.

Our stock price could be volatile and could decline for a variety of reasons, resulting in a substantial loss on your investment and negatively impacting our ability to raise equity capital in the future.

        Significant price fluctuations in CPE Inc.'s common stock could result from a variety of factors, including, among other things, actual or anticipated fluctuations in our operating results or financial condition, new laws or regulations or new interpretations of existing laws or regulations impacting our business or our customers' businesses, sales of CPE Inc.'s common stock by our stockholders or by us, a downgrade or cessation in coverage from one or more of our analysts, broad market fluctuations and general economic conditions and any other factors described in this "Risk Factors" section of this Form 10-K.

        A decline in the trading price of CPE Inc.'s common stock due to any future sales of stock or the issuance or exercise of equity-based awards under our Long Term Incentive Plan or sales to cover taxes owed upon vesting of awards, or due to other factors might impede our ability to raise capital through the issuance of additional shares of CPE Inc.'s common stock or other equity securities and may cause you to lose part or all of your investment in our shares of common stock.

Anti-takeover provisions in our charter documents and other aspects of our structure may discourage, delay or prevent a change in control of our company and may adversely affect the trading price of CPE Inc.'s common stock.

        Certain provisions in CPE Inc.'s amended and restated certificate of incorporation and amended and restated bylaws and other aspects of our structure may discourage, delay or prevent a change in our management or a change in control over us that stockholders may consider favorable. Among other things, CPE Inc.'s amended and restated certificate of incorporation and amended and restated bylaws:

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

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

    do not provide for cumulative voting;

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

    limit the calling of special meetings of stockholders;

    provide that stockholders may not act by written consent;

    provide that our directors may be removed only for cause;

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

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

45


Table of Contents

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, 2011, we controlled approximately 1.37 billion tons of proven and probable coal reserves. All of our proven and probable reserves are classified as thermal 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, 2011:

Mine
  Proven
Preserves
  Probable
Reserves
  Total Proven
 & Probable
Reserves
  Assigned
Reserves
  Reserves
Owned
  Reserves
Leased
 
 
  (nearest million, in tons)
  (%)
  (nearest million, in tons)
 

Antelope

    519     164     683     100         683  

Cordero Rojo

    274     96     370     100     61     309  

Spring Creek

    286     25     311     100         311  

Decker(1)

    3         3     100         3  
                             

Total

    1,082     285     1,367           61     1,306  
                             

(1)
Based on our 50% non-operating interest.

        The following table provides the "quality" (average sulfur content and average Btu per pound) of our coal reserves as of December 31, 2011:

Mine
  Total Proven & Probable
Reserves
  Average Btu per
lb(1)
  Average Sulfur
Content
  Average Sulfur
Content
 
 
  (nearest million, in tons)
   
  %
  (lbs SO2/mmBtu)
 

Antelope

    683     8,875     0.23     0.52  

Cordero Rojo

    370     8,425     0.29     0.69  

Spring Creek

    311     9,350     0.33     0.71  

Decker(2)

    3     9,450     0.41     0.87  
                         

Total

    1,367                    
                         

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

(2)
Based on our 50% non-operating interest.

        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 located at our Cordero Rojo and Spring Creek mines and were 160 million tons and 29 million tons, respectively.

        Our reserve and non-reserve coal deposit estimates as of December 31, 2011 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.

46


Table of Contents

Our current policy is to have our reserve calculations reviewed by an independent consultant every two years, which review was last performed for the year ended 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.

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 2011 we acquired 383 million tons of reserves in two federal coal leases for our Antelope mine. Similarly, in 2008 and 2009 we acquired an additional 209 million tons of reserves in two federal coal leases 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 a new federal coal lease, 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 against the BLM and the Secretary of the Interior by environmental groups with respect to the LBA process in the PRB, including 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 the LBM leasing process. 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. For example, 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.

47


Table of Contents

        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 awarded 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. 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 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. For example, 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 create some uncertainty with respect to the timing of LBA bids and lease acquisitions 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 ten years of the lease award with a required coal extraction of 1% of the total coal under the lease by the end of that 10-year period. At the end of the 10-year development period, the lessee is required to maintain continuous operations, as defined in the

48


Table of Contents

applicable leasing regulations. In certain cases, a lessee may combine contiguous leases into an LMU. This allows the production of coal from any of the leases within the LMU to be used to meet the continuous operation requirements for the entire LMU. 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 certain owners of the surface lands overlying the coal. Certain federal regulations provide a specific class of surface owners, QSOs, with the ability to prohibit the BLM from leasing its coal. For example, in connection with a pending LBA tract that we nominated for our Cordero Rojo mine, the BLM 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 federal coal lease or permitting processes or ultimately prevent the acquisition of the federal coal lease 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 a federal coal lease. We own substantially all of the land over our reserves. We may not own or control the land over our non-reserve coal deposits, which would be required before these non-reserve coal deposits could be classified as reserves and mined.

        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 two annual leases expiring on June 30, 2012 and May 31, 2012, and we lease approximately 28,100 square feet of office space in Broomfield, Colorado under a lease that

49


Table of Contents

expires in February 2021. As of December 31, 2011, all of our long-lived assets were located in the U.S. See Note 15 of Notes to Consolidated Financial Statements in Item 8.

Item 3.    Legal Proceedings.

Caballo Coal Company Litigation—Spring Creek

        On September 16, 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. Settlement negotiations occurred for which an estimated range of immaterial results has been established in management's judgment. Settlement discussions are currently pending, and the parties have reached an understanding in principle to resolve this litigation with no material impact in management's judgment. Any final settlement remains subject to negotiation and execution of a definitive settlement agreement. If the pending settlement negotiations are not successful and the parties fail to enter a definitive settlement agreement and if the case is 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 leases we acquired for the West Antelope II LBAs are subject to pending legal challenges filed against the BLM and the Secretary of the Interior by environmental organizations.

Item 4.    Mine Safety Disclosures

        The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Form 10-K.

50


Table of Contents


PART II

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

        CPE Inc.'s common stock, $0.01 par value, has traded on the New York Stock Exchange under the symbol "CLD" since November 20, 2009. Prior to November 20, 2009, there was no public market for CPE Inc.'s common stock.

        The following table sets forth the high and low closing sales prices of CPE Inc.'s common stock, as reported by the NYSE, for each of the periods listed.

 
  High   Low  

Fiscal 2011

             

First Quarter 2011

  $ 24.18   $ 19.84  

Second Quarter 2011

  $ 21.88   $ 19.07  

Third Quarter 2011

  $ 23.28   $ 16.95  

Fourth Quarter 2011

  $ 24.02   $ 16.29  

Fiscal 2010

             

First Quarter 2010

  $ 16.84   $ 13.51  

Second Quarter 2010

  $ 17.15   $ 13.26  

Third Quarter 2010

  $ 18.37   $ 13.20  

Fourth Quarter 2010

  $ 23.23   $ 17.05  

Fiscal 2009

             

(commencing November 20, 2009)

  $ 15.04   $ 12.69  

        As of the close of business on January 31, 2012, we had 1,351 holders of record of CPE Inc.'s common stock.

Dividend Policy

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

Stock Performance Graph

        The following performance graph compares the cumulative total return on CPE Inc.'s common stock with the cumulative total return of the following indices: (i) the Standard & Poor's ("S&P") MidCap 400 stock index and (ii) the Custom Composite Index comprised of Alpha Natural Resources, Inc., Arch Coal, Inc., CONSOL Energy, Inc., and Peabody Energy Corp. The graph assumes that you invested $100 in CPE Inc.'s common stock and in each index at the closing price on November 20, 2009, that all dividends were reinvested and that you continued to hold your investment through December 31, 2011. In January 2011, Alpha Natural Resources, Inc. and Massey Energy Company announced they signed a definitive agreement under which Alpha Natural Resources would acquire all outstanding shares of Massey Energy Company common stock. That transaction was completed in mid-2011.

51


Table of Contents

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

GRAPHIC

Company/Market/ Peer Group
  Nov-09   Dec-09   Mar-10   Jun-10   Sep-10   Dec-10   Mar-11   Jun-11   Sep-11   Dec-11  

CPE Inc. 

  $ 100.00   $ 98.11   $ 112.13   $ 89.35   $ 122.97   $ 156.53   $ 145.48   $ 143.53   $ 114.21   $ 130.18  

S&P MidCap 400 Index

  $ 100.00   $ 105.90   $ 115.52   $ 104.46   $ 118.16   $ 134.11   $ 146.66   $ 145.58   $ 116.65   $ 131.77  

Custom Composite

  $ 100.00   $ 103.29   $ 102.51   $ 82.59   $ 100.25   $ 134.04   $ 145.13   $ 119.65   $ 69.58   $ 72.75  

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

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, 2011 and 2010 and for each of the three years in the period ended December 31, 2011 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, 2009 from our audited consolidated financial statements not included in this report. We have derived the historical consolidated balance sheet data as of December 31, 2008 and 2007 and the historical consolidated statement of operations data for the years

52


Table of Contents

ended December 31, 2008 and 2007 from the audited consolidated financial statements of RTEA not included in this report.

        Our 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 also includes 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; accordingly, our historical consolidated financial information is not necessarily 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.


Selected Consolidated Financial and Other Data

 
  Year Ended December 31,  
CPE Inc.
  2011   2010   2009   2008   2007  
 
  (in millions, except per share amounts)
 

Statement of Operations Data

                               

Revenues

  $ 1,553.7   $ 1,370.8   $ 1,398.2   $ 1,239.7   $ 1,053.2  

Operating income(1)

    250.5     211.9     255.0     124.9     102.7  

Income from continuing operations

    189.8     117.2     182.5     88.3     53.8  

Income (loss) from discontinued operations(2)

            211.1     (25.2 )   (21.5 )

Net income

    189.8     117.2     393.6     63.1     32.3  

Amounts attributable to controlling interest(3)

                               

Income from continuing operations

    189.8     33.7     170.6     88.3     53.8  

Income (loss) from discontinued operations(2)

            211.1     (25.2 )   (21.5 )

Net income

    189.8     33.7     381.7     63.1     32.3  

Earnings per share attributable to controlling interest—basic(3)(4)(8)

                               

Income from continuing operations

  $ 3.16   $ 1.06   $ 3.01   $ 1.47   $ 0.90  

Income (loss) from discontinued operations(2)

  $   $   $ 3.73   $ (0.42 ) $ (0.36 )

Net income

  $ 3.16   $ 1.06   $ 6.74   $ 1.05   $ 0.54  

Earnings per share attributable to controlling interest—diluted(3)(4)(8)

                               

Income from continuing operations

  $ 3.13   $ 1.06   $ 2.97   $ 1.47   $ 0.90  

Income (loss) from discontinued operations(2)

  $   $   $ 3.52   $ (0.42 ) $ (0.36 )

Net income

  $ 3.13   $ 1.06   $ 6.49   $ 1.05   $ 0.54  

53


Table of Contents


 
  December 31,  
 
  2011   2010   2009   2008   2007  
 
  (in millions)
 

Balance Sheet Data

                               

Cash and cash equivalents

  $ 404.2   $ 340.1   $ 268.3   $ 15.9   $ 23.6  

Investments in marketable securities

    75.2                  

Property, plant and equipment, net

    1,350.1     1,008.3     987.1     927.9     719.7  

Assets of continuing operations(2)

    2,319.3     1,915.1     1,677.6     1,198.0     1,059.4  

Total assets

    2,319.3     1,915.1     1,677.6     1,785.2     1,781.2  

Long-term debt

    596.1     595.7     595.3         500.6  

Federal coal leases obligations

    288.3     118.3     169.1     206.3     67.6  

Liabilities of continuing operations(2)

    1,568.9     1,383.9     1,232.1     672.8     1,176.2  

Total liabilities

    1,568.9     1,383.9     1,232.1     800.0     1,446.2  

Controlling interest equity(3)

    750.4     531.2     252.9     985.2     335.0  

Noncontrolling interest equity(3)

            192.6          

 

 
  Year Ended December 31,  
 
  2011   2010   2009   2008   2007  
 
  (in millions)
 

Other Data

                               

Adjusted EBITDA(7)

  $ 351.7   $ 322.7   $ 320.6   $ 207.2   $ 159.8  

Adjusted EPS(7)

  $ 2.47   $ 1.74   $ 2.48   $ 1.06   $ 0.46  

Asian export tons

    4.7     3.3     1.6     0.7     0.1  

Tons sold—company owned and operated mines(5)

    95.6     93.7     90.9     93.7     90.7  

Tons sold—Decker mine(6)

    1.5     1.5     2.3     3.3     3.5  

Tons purchased and resold

    1.6     1.7     10.1     8.1     8.1  

Total tons sold

    98.7     96.9     103.3     105.1     102.3  

Ratio of earnings to fixed charges—see Exhibit 12.1

    3.0     2.7     11.9     5.0     2.6  

(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 pretax 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 controlling interest 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 controlling interest reflects our interest in CPE Resources and its subsidiaries. Noncontrolling interest equity at December 31, 2009 reflects the interest in CPE Resources held by RTEA and an affiliate of RTEA. As of December 31, 2010, as a result of the Secondary Offering completed in December 2010, CPE Resources is a wholly-owned subsidiary of CPE Inc.

(4)
Earnings per share for periods prior to the IPO assumes 60,000,000 outstanding shares, which is the number of shares of common stock that our predecessor, RTEA, would have been required to have outstanding in prior periods based on the capital structure of CPE Inc., which required a

54


Table of Contents

    one-to-one ratio between the number of shares of common stock outstanding and the number of common membership units in CPE Resources held by CPE Inc. See Note 19 of Notes to Consolidated Financial Statements in Item 8.

(5)
Inclusive of Asian export tons.

(6)
Based on our 50% non-operating interest.

(7)
EBITDA, Adjusted EBITDA and Adjusted EPS are intended to provide additional information only and do not have any standard meaning prescribed by generally accepted accounting principles in the U.S. ("U.S. GAAP"). A quantitative reconciliation of Adjusted EBITDA to income from continuing operations, or net income, as applicable, and Adjusted EPS to EPS (as defined below) is found in the tables below.

    EBITDA represents income from continuing operations, or net income, as applicable, 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 items are the income statement amounts for: (1) the Tax Receivable Agreement including tax impacts of the IPO and Secondary Offering, (2) marked-to-market adjustments for derivative financial instruments, and (3) a significant broker contract that expired in the first quarter of 2010.

    Adjusted EPS represents diluted earnings (loss) per share from continuing operations attributable to controlling interest or diluted earnings (loss) per share attributable to controlling interest from continuing operations, as applicable ("EPS"), adjusted to exclude the estimated per share impact of the same specifically identified items used to calculate Adjusted EBITDA as described above, adjusted at the statutory rate of 36%.

    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 is also used as part of our incentive compensation program for our executive officers and others.

    We believe Adjusted EBITDA and Adjusted EPS are 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. Similarly, we believe Adjusted EPS provides an appropriate measure to use in assessing our performance across periods given that this measure provides an adjustment for certain specifically identified significant items that are not considered to directly reflect our core operations, the magnitude of which may vary drastically from period to period and, thereby, have a disproportionate effect on the earnings per share reported for a given period.

    Our management recognizes that using Adjusted EBITDA and Adjusted EPS as performance measures has inherent limitations as compared to income from continuing operations, net income, EPS or other U.S. GAAP financial measures, as these non-GAAP measures exclude certain items,

55


Table of Contents

    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 stockholders. 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 we are organized as a corporation, the payment of taxes is a necessary element of our operations. Adjusted EBITDA and Adjusted EPS exclude the tax impacts of the IPO and Secondary Offering; however, this represents our current estimate of payments we will be required to make to Rio Tinto under our Tax Receivable Agreement and changes to the realizability of our deferred tax assets based on changes in our estimated future taxable income. Adjusted EBITDA and Adjusted EPS exclude marked-to-market adjustments on our derivative financial instruments; however, gains and/or losses will be realized when the derivative financial instruments are settled. Finally, Adjusted EBITDA and Adjusted EPS exclude 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 and Adjusted EPS should not be considered in isolation and do not purport to be alternatives to income from continuing operations, net income, EPS 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 or net income in each period, so as to allow for the comparison of the 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 or net income to evaluate the business assists management and investors in (a) assessing our relative performance against our competitors and (b) ultimately monitoring our capacity to generate returns for stockholders.

    Because not all companies use identical calculations, our presentations of Adjusted EBITDA and Adjusted EPS may not be comparable to other similarly titled measures of other companies. Moreover, our presentation of Adjusted EBITDA is different than EBITDA as defined in our debt financing agreements.

56


Table of Contents

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

 
  Year Ended December 31,  
CPE Inc.
  2011   2010   2009   2008   2007  
 
  (in millions)
 

Net income

  $ 189.8   $ 117.2   $   * $   * $   *

Income from continuing operations

      *     *   182.5     88.3     53.8  
                       

Interest income

    (0.6 )   (0.6 )   (0.3 )   (2.9 )   (7.3 )

Interest expense

    33.9     46.9     6.0     20.4     40.9  

Income tax expense

    11.4     32.0     68.2     25.3     18.1  

Depreciation and depletion

    87.1     100.0     97.9     89.0     80.1  

Amortization

        3.2     28.7     46.0     34.5  

Accretion

    12.5     12.5     12.6     12.7     12.2  
                       

EBITDA

    334.1     311.3     395.6     278.9     232.3  
                       

Tax agreement expense(1)

    19.9     19.7              

Marked-to-market adjustments

    (2.3 )                

Expired significant broker contract

        (8.2 )   (75.0 )   (71.6 )   (72.5 )
                       

Adjusted EBITDA

  $ 351.7   $ 322.7   $ 320.6   $ 207.2   $ 159.8  
                       

(1)
Changes to related deferred taxes are included in income tax expense.

*
For 2009 and prior periods, CPE Inc. reported discontinued operations. Accordingly, for such periods, net income from continuing operations is the comparable U.S. GAAP financial measure for Adjusted EBITDA.

    A reconciliation of diluted earnings (loss) per common share attributable to controlling interest from continuing operations to Adjusted EPS for the periods presented is as follows:

 
  Year Ended December 31,  
 
  2011   2010(1)   2009   2008   2007  

Diluted earnings per common share attributable to controlling interest

  $ 3.13   $ 1.06   $   * $   * $   *

Diluted earnings per common share attributable to controlling interest from continuing operations

      *     * $ 2.97   $ 1.47   $ 0.90  
                       

Tax agreement expense including tax impacts of IPO and Secondary Offering

    (0.63 )   0.78              

Marked-to-market adjustments

    (0.02 )                

Expired significant broker contract

        (0.10 )   (0.49 )   (0.41 )   (0.44 )
                       

Adjusted EPS

  $ 2.47   $ 1.74   $ 2.48   $ 1.06   $ 0.46  
                       

Weighted-average shares outstanding (in millions)

    60.6     31.9     60.0     60.0     60.0  

(1)
In conjunction with preparing our 2011 consolidated financial statements, we identified a clerical error in the computation of the 2010 weighted-average shares outstanding, which resulted in an understatement of earnings per share and Adjusted EPS for the three months and twelve months ended December 31, 2010. The previously reported earnings per share balances for the three months and twelve months ended December 31, 2010 of

57


Table of Contents

    $0.28 and $0.98, respectively, have been corrected to $0.36 and $1.06, respectively. The previously reported Adjusted EPS balances for the three months and twelve months ended December 31, 2010 of $0.29 and $1.62, respectively, have been corrected to $0.36 and $1.74, respectively. This clerical error overstated the weighted-average shares outstanding balances, both basic and diluted, for each of these periods due to the inclusion of the 60,000,000 post-Secondary Offering shares outstanding from November 15, 2010 as opposed to the correct date of December 15, 2010. The previously reported weighted-average share outstanding balances for the three months and twelve months ended December 31, 2010 of 45.3 million shares and 34.3 million shares, respectively, have been corrected to 35.7 million shares and 31.9 million shares, respectively. We have assessed the impact of these adjustments and determined that the error is immaterial to our 2010 consolidated financial statements and does not affect our 2011 consolidated financial statements.

*
For 2009 and prior periods, CPE Inc. reported discontinued operations. Accordingly, for such periods, diluted earnings (loss) per share attributable to controlling interest from continuing operations is the comparable U.S. GAAP financial measure for Adjusted EPS.

(8)
2010 amounts have been corrected as disclosed within Note 19 of Notes to Consolidated Financial Statements in Item 8.

        Due to the tabular presentation of rounded amounts, certain tables reflect insignificant rounding differences.

58


Table of Contents

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 one of the largest producers of coal in the U.S. and in the Powder River Basin ("PRB"), based on 2011 coal sales. We operate some of the safest mines in the coal industry. According to Mine Safety and Health Administration ("MSHA") data, in 2011, we had one of the lowest employee all injury incident rates among the largest U.S. coal producing companies. We operate solely in the PRB, the lowest cost region of the major coal producing regions in the U.S., and operate two of the four largest coal mines in the U.S. Our operations include three wholly-owned surface coal mines, two of which, the Antelope mine and the Cordero Rojo mine, are in Wyoming and one of which, the Spring Creek 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 thermal coal with low sulfur content and sell our coal primarily to domestic and foreign electric utilities.

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

        Prior to the initial public offering ("IPO") and the related structuring transactions, Cloud Peak Energy Resources LLC ("CPE Resources") was a wholly-owned subsidiary of Rio Tinto Energy America ("RTEA"), which is our predecessor for financial reporting purposes. On November 19, 2009, Cloud Peak Energy Inc. ("CPE Inc.") acquired from RTEA 51% of the common membership units in CPE Resources in exchange for a promissory note which was repaid with proceeds from the IPO, and became the sole managing member of CPE Resources. On December 15, 2010, CPE Inc. priced the Secondary Offering. In connection with the Secondary Offering, we exchanged shares of common stock for the remaining common membership units of CPE Resources held by Rio Tinto, resulting in a divestiture of 100% of Rio Tinto's holdings in CPE Resources making it a wholly-owned subsidiary of CPE Inc. For periods between November 19, 2009 and December 15, 2010, Rio Tinto's ownership interest in CPE Resources was reported as a noncontrolling interest in the consolidated financial statements of CPE Inc. See Note 2 of Notes to Consolidated Financial Statements in Item 8.

Discontinued Operations

        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 ("RTA"). The results of operations of the Jacobs Ranch mine 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.

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, the other 50% mine owner 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.

59


Table of Contents

Core Business Operations

        As of December 31, 2011, we controlled approximately 1.37 billion tons of proven and probable coal reserves. During the second quarter of 2011, we were the successful bidder on certain mining rights in the West Antelope II North ("WAII North") and West Antelope II South ("WAII South") Coal Tracts in the PRB. The tracts have favorable geologic conditions, have increased our year-end 2011 proven and probable reserves by approximately 383 million tons, and are contiguous with our Antelope mine.

        With the acquisition of the federal coal leases, we also gained access to approximately 81 million tons of coal in an adjacent State of Wyoming coal lease that we controlled but were not previously included in our coal reserve estimates, resulting in a combined total increase of 464 million tons.

        Our key business drivers include the following:

    the volume of coal sold 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, and depletion of coal leases;

    the costs for logistic services and rail and port charges for coal sales on a delivered basis; and

    capital expenditures to acquire property, plant and equipment.

        The volume of coal that we sell in any given year is driven by the amount of global and domestic demand for coal-generated electric power. Demand for coal-generated electric power may be affected by many factors including weather patterns, natural gas prices, coal-fired generating capacity and utilization, environmental and legal challenges, political and regulatory factors, energy policies, international and domestic economic conditions, and other factors discussed in this Item 7 and in Item 1A "Risk Factors."

        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. Significant increases in demand can allow our coal to compete in new markets. We typically enter into multi-year contracts with our customers which helps mitigate the risks associated with any short-term imbalance in supply and demand. In addition, international demand has increased, enabling us to increase exports of coal during the past few years. During 2011, we entered into derivative financial instruments that are scheduled to settle in 2012 and 2013 to hedge a portion of our export coal sales.

        We typically seek to enter each year with expected production effectively fully sold. This strategy helps us deliver our expected tonnages and run our mines at predictable production rates, which helps us control operating costs.

        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 in our mining operations, although we may do so in the future. As is common in the PRB, coal seams at our existing mines naturally deepen, resulting in additional overburden to be removed at additional cost.

        For some of our coal sales, including our sales to Asian customers, we arrange and pay for logistic services, rail and/or port charges. Our costs for transportation are affected by volume and negotiated freight rates.

60


Table of Contents

        We incur significant capital expenditures to update or expand our mining equipment, surface land holdings and coal reserves. In line with the worldwide mining industry, generally the cost of capital equipment and lead times are increasing. In addition, should the costs of acquiring future federal coal leases and associated surface rights increase, our depletion costs would also increase.

        On August 8, 2011, the U.S. Environmental Protection Agency ("EPA") published in the Federal Register the Cross-State Air Pollution Rule ("CSAPR") which replaces the Clean Air Interstate Rule ("CAIR"). CSAPR was expected to take effect on January 1, 2012 and was intended to reduce pollutants from upwind states by requiring 28 states to reduce power plant emissions of sulfur dioxide ("SO2") and nitrogen oxide ("NOx"). On December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit put the implementation of CSAPR on hold and ordered the EPA to continue enforcing CAIR until the merits of the rule can be judicially reviewed.

        Power plants' options for reducing emissions of these pollutants include switching to a lower sulfur coal or installing emission control technologies, or a combination of both. Since the PRB has the lowest sulfur content of any of the large U.S. coal producing regions, any increase in demand for lower sulfur coal could lead to higher demand for coal from the PRB particularly for "ultra-low" sulfur coal such as that produced by our Antelope mine. However, for regulated states to meet their requirements under the CSAPR, a number of coal-fired electric generating units will likely need to be retired, rather than be retrofitted with the necessary emission control technologies, thereby reducing demand for thermal coal. Given the current stay of CSAPR implementation, we are unable to predict the overall impact of this legislation.

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

Summary

        The following table summarizes key results (in millions):

 
  Year Ended
December 31,
  Change  
 
  2011   2010   Amount   Percent  

Total revenue

  $ 1,553.7   $ 1,370.8   $ 182.9     13.3  

Net income

    189.8     117.2     72.6     61.9  

Adjusted EBITDA(1)

    351.7     322.7     29.0     9.0  

Adjusted EPS(1)

  $ 2.47   $ 1.74   $ 0.73     42.0  

Asian export tons

    4.7     3.3     1.4     42.4  

Total tons sold

    98.7     96.9     1.8     1.9  

(1)
Non-GAAP measure; please see definition in Item 6 and reconciliation below.

61


Table of Contents

Adjusted EBITDA and Adjusted EPS (CPE Inc. only)

        The following tables present a reconciliation of net income from continuing operations to Adjusted EBITDA and diluted earnings per common share from continuing operations to Adjusted EPS (in millions, except per share amounts):

 
  Year Ended
December 31,
 
 
  2011   2010  

Net income

  $ 189.8   $ 117.2  
           

Interest income

    (0.6 )   (0.6 )

Interest expense

    33.9     46.9  

Income tax expense

    11.4     32.0  

Depreciation and depletion

    87.1     100.0  

Amortization

        3.2  

Accretion

    12.5     12.5  
           

EBITDA

    334.1     311.3  
           

Tax agreement expense(1)

    19.9     19.7  

Marked-to-market adjustments

    (2.3 )    

Expired significant broker contract

        (8.2 )
           

Adjusted EBITDA

  $ 351.7   $ 322.7  
           

(1)
Changes to related deferred taxes are included in income tax expense.

 
  Year Ended
December 31,
 
 
  2011   2010(1)  

Diluted earnings per common share from continuing operations

  $ 3.13   $ 1.06  
           

Tax agreement expense including tax impacts of IPO and Secondary Offering

    (0.63 )   0.78  

Marked-to-market adjustments

    (0.02 )    

Expired significant broker contract

        (0.10 )
           

Adjusted EPS

  $ 2.47   $ 1.74  
           

Weighted-average shares outstanding (in millions)

    60.6     31.9  

(1)
Amounts have been corrected as disclosed within Footnote 7 of Item 6. Selected Financial Data.

Results of Operations

        "Owned and operated mines" refers to our three surface coal mines and excludes our 50% non-operating interest in the Decker mine. We include our share of results from operations at the Decker mine along with broker coal sales and billings for transportation and delivery services as "Other operations."

62


Table of Contents

Revenues

        The following table presents revenues (in millions except per ton amounts):

 
  Year Ended
December 31,
  Change  
 
  2011   2010   Amount   Percent  

Owned and operated mines

                         

Revenue

  $ 1,236.1   $ 1,154.7   $ 81.4     7.0  

Realized price per ton sold

  $ 12.92   $ 12.32   $ 0.60     4.9  

Tons sold

    95.6     93.7     1.9     2.0  

Other operations

                         

Revenue

  $ 317.6   $ 216.1   $ 101.5     47.0  

        The increase in revenue from our owned and operated mines was the result of an increase in the realized price per ton of coal sold and an increase in coal sold in 2011 compared to 2010, reflecting the strong demand for our coal and the ability of our operations to overcome the rail transportation disruptions which were the result of the severe flooding experienced throughout the Midwestern United States during the spring and summer of 2011.

        Revenues from other operations increased primarily as a result of a higher volume of coal sold on a delivered basis, including export sales with delivered pricing terms that included logistic services and rail and port charges. We arranged and paid for the logistic services and rail and port charges and charged our customers for providing this service.

Cost of Product Sold

        The following table presents cost of product sold (in millions except per ton amounts):

 
  Year Ended
December 31,
  Change  
 
  2011   2010   Amount   Percent  

Owned and operated mines

                         

Cost of product sold

  $ 872.6   $ 803.3   $ 69.3     8.6  

Average cost per ton sold

    9.12     8.57     0.55     6.4  

Other operations

                         

Cost of product sold

  $ 278.5   $ 175.6   $ 102.9     58.6  

        The increase in the average cost per ton of coal sold is primarily the result of increases in costs related to the price of diesel fuel and lubricants as well as maintenance and repairs.

        Cost of product sold from other operations increased primarily due to increases in volumes and freight rates on our coal sold on a delivered basis, including Asian export sales.

Operating Income

        The following table presents operating income (in millions):

 
  Year Ended
December 31,
  Change  
 
  2011   2010   Amount   Percent  

Operating income

  $ 250.5   $ 211.9   $ 38.6     18.2  

        In addition to those factors previously discussed, we realized reductions in selling, general and administrative costs primarily due to lower incentive compensation and the elimination of amounts paid

63


Table of Contents

to Rio Tinto under the transition services agreement, which concluded during 2010. Depreciation and depletion expense decreased $15.7 million due to the successful federal coal lease awards during 2011 which increased our Antelope mine's life by approximately 12 years. This reduced the discounted value of the future liability of the asset retirement obligation ("ARO") and the resulting non-cash credit reduced depreciation and depletion expense as the change exceeded the carrying amount of the related asset retirement cost.

Other Expense

        The following table presents other expense (in millions):

 
  Year Ended
December 31,
  Change  
 
  2011   2010   Amount   Percent  

Other expense

  $ 51.0   $ 65.9   $ 14.9     22.6  

        Other expense was reduced by a $20.4 million increase in the amount of interest expense capitalized partially offset by $7.9 million of additional imputed interest during the year ended December 31, 2011. The increase in capitalized and imputed interest was the result of additional interest on the WAII North and WAII South Coal Tracts, which were acquired in the second quarter of 2011. In addition, we recognized $2.3 million in marked-to-market adjustments on our derivative financial instruments in 2011.

Income Tax Provision

        The following table presents income tax provision (in millions):

 
  Year Ended
December 31,
  Change  
 
  2011   2010   Amount   Percent  

Income expense (CPE Inc.)

  $ 11.4   $ 32.0   $ (20.6 )   (64.4 )

Effective tax rate (CPE Inc.)

    5.7 %   21.9 %   (16.2 )   (74.0 )

Income tax expense (benefit) (CPE Resources)

 
$

20.0
 
$

(0.8

)

$

20.8
   
*

Effective tax rate (CPE Resources)

    9.1 %   (0.5 )%   9.6       *

*
Change from prior period is not a relevant percentage.

CPE Inc.

        CPE Inc.'s statutory income tax rate, including state income taxes, is 36%. The difference from that rate for the year ended December 31, 2011, is due primarily to changes in our valuation allowance resulting from the third quarter annual calculation of our estimate of future taxable income.

CPE Resources

        CPE Resources's statutory income tax rate, including state income taxes, is 36%. The difference from that rate for the year ended December 31, 2011 is due primarily to changes in our valuation allowance resulting from the third quarter annual calculation of our estimate of future taxable income. The effective tax rate for 2010 was also impacted by CPE Resources's change in status from an entity generally not subject to income taxes prior to the Secondary Offering to an entity that must now recognize taxes on a stand-alone, separate return basis.

64


Table of Contents

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

Summary

        The following table summarizes key results (in millions):

 
  Year Ended
December 31,
  Change  
 
  2010   2009   Amount   Percent  

Total revenue

  $ 1,370.8   $ 1,398.2   $ (27.4 )   (2.0 )

Net income

    117.2     182.5     (65.3 )   (35.8 )

Adjusted EBITDA(1)

    322.7     320.6     2.1     0.7  

Adjusted EPS(1)

  $ 1.74   $ 2.48   $ (0.74 )   (29.8 )

Asian export tons

    3.3     1.6     1.7     106.3  

Total tons sold

    96.9     103.3     (6.4 )   (6.2 )

(1)
Non-GAAP measure; please see definition in Item 6 and reconciliation below.

Adjusted EBITDA and Adjusted EPS (CPE Inc. only)

        The following tables present a reconciliation of net income from continuing operations to Adjusted EBITDA and diluted earnings per common share from continuing operations to Adjusted EPS (in millions, except per share amounts):

 
  Year Ended
December 31,
 
 
  2010   2009  

Net income

  $ 117.2   $   *

Income from continuing operations

      *   182.5  
           

Interest income

    (0.6 )   (0.3 )

Interest expense

    46.9     6.0  

Income tax expense

    32.0     68.2  

Depreciation and depletion

    100.0     97.9  

Amortization

    3.2     28.7  

Accretion

    12.5     12.6  
           

EBITDA

    311.3     395.6  
           

Tax agreement expense(1)

    19.7      

Expired significant broker contract

    (8.2 )   (75.0 )
           

Adjusted EBITDA

  $ 322.7   $ 320.6  
           

(1)
Changes to related deferred taxes are included in income tax expense.

*
For 2009 and prior periods, CPE Inc. reported discontinued operations. Accordingly, for such periods, net income from continuing operations is the comparable U.S. GAAP financial measure for Adjusted EBITDA.

65


Table of Contents

 
  Year Ended
December 31,
 
 
  2010(1)   2009  

Diluted earnings per common share from continuing operations

  $ 1.06   $   *

Diluted earnings per common share attributable to controlling interest from continuing operations

      *   2.97  
           

Tax agreement expense including tax impacts of IPO and Secondary Offering

    0.78      

Expired significant broker contract

    (0.10 )   (0.49 )
           

Adjusted EPS

  $ 1.74   $ 2.48  
           

Weighted-average shares outstanding (in millions)

    31.9     60.0  

(1)
Amounts have been corrected as disclosed within Footnote 7 of Item 6. Selected Financial Data.

*
For 2009 and prior periods, CPE Inc. reported discontinued operations. Accordingly, for such periods, diluted earnings (loss) per share attributable to controlling interest from continuing operations is the comparable U.S. GAAP financial measure for Adjusted EPS.

Results of Operations

        "Owned and operated mines" refers to our three surface coal mines and excludes our 50% non-operating interest in the Decker mine. We include our share of results from operations at the Decker mine along with broker coal sales and billings for transportation and delivery services as "Other operations."

Revenues

        The following table presents revenues (in millions except per ton amounts):

 
  Year Ended
December 31,
  Change  
 
  2010   2009   Amount   Percent  

Owned and operated mines

                         

Revenue

  $ 1,154.7   $ 1,072.1   $ 82.6     7.7  

Realized price per ton sold

  $ 12.32   $ 11.79   $ 0.53     4.5  

Tons sold

    93.7     90.9     2.8     3.1  

Other operations

                         

Revenue

  $ 216.1   $ 326.1   $ (110.0 )   (33.7 )

        The increase in revenue from our owned and operated mines reflected an increase in the realized price per ton of coal sold in 2010 compared to 2009, reflecting the strong demand for PRB coal due to prevailing economic and industry conditions at the time we entered into the related coal supply contracts, and an increase in coal shipped in 2010 compared to 2009.

        Our share of revenues from coal produced at the Decker mine decreased reflecting a decline in shipments partially offset by a higher average price per ton. Broker coal sales decreased following the expiration in the first quarter of 2010 of a significant contract. Revenues from transportation and delivery services increased, as a result of a higher volume of coal sold on a delivered basis, including export sales with delivered pricing terms that include logistic services and rail and port charges, where we arranged and paid for the freight costs and charged our customers for providing this service.

66


Table of Contents

Cost of Product Sold

        The following table presents cost of product sold (in millions except per ton amounts):

 
  Year Ended
December 31,
  Change  
 
  2010   2009   Amount   Percent  

Owned and operated mines

                         

Cost of product sold

  $ 803.3   $ 722.1   $ 81.2     11.2  

Average cost per ton sold

  $ 8.57   $ 7.94     0.63     7.9  

Other operations

                         

Cost of product sold

  $ 175.6   $ 211.4   $ (35.8 )   (16.9 )

        The increase in the average cost per ton of coal sold is primarily the result of a 9.2% per ton increase in royalties and production taxes, which reflects the higher average sales prices realized on our 2010 coal shipments as well as updates to estimates for non-income based taxes. Excluding royalties and production taxes, the cost per ton of coal sold increased from $4.53 to $4.83. The increase in the cost per ton of coal sold is primarily the result of increases in costs related to the price of diesel fuel and lubricants and a higher strip ratio in 2010 compared to 2009 as our mines move into deeper mining areas.

        The cost of coal sold by the Decker mine decreased $3.0 million in 2010, reflecting lower production volumes partially offset by higher unit production costs. In addition, the cost of purchased coal decreased $86.7 million, primarily as a result of decreases of $64.7 million related to a significant broker sales contract that expired in 2010 and $20.0 million for other broker sales of purchased coal. The decreases in coal purchased related to our significant broker sales contract and other broker transactions are consistent with the related decreases in broker sales revenues in 2010. These decreases are partially offset by an increase in international exports in 2010, which resulted in an increase in freight and handling costs.

Operating Income

        The following table presents operating income (in millions):

 
  Year Ended
December 31,
  Change  
 
  2010   2009   Amount   Percent  

Operating income

  $ 211.9   $ 255.0   $ (43.1 )   (16.9 )

        Operating income was affected by a decrease in amortization expense of $25.5 million, which is attributable to the expiration of the significant broker contract in the first quarter of 2010, as well as a decrease in selling, general, and administrative costs primarily due to costs incurred in 2009 associated with the IPO that were not incurred in 2010, offset by the increased costs to operate as a stand-alone public entity and execute the Secondary Offering.

67


Table of Contents

Other Expense

        The following table presents other expense (in millions):

 
  Year Ended
December 31,
  Change  
 
  2010   2009   Amount   Percent  

Other expense

  $ 65.9   $ 5.7   $ 60.2       *

*
Change from prior period is not a relevant percentage

        Total other expense increased due to an increase in interest expense on our $600 million of senior notes, which were outstanding for the full year in 2010 compared to approximately one month in 2009. Additionally, during the three months ended September 31, 2010, we completed our annual update of our most recent operating plans and the resulting projected estimated future taxable income. This resulted in an increase in the estimated liability due to Rio Tinto under the Tax Receivable Agreement, resulting in a $19.7 million charge to non-operating income. See Note 10 of Notes to Consolidated Financial Statements in Item 8.

Income Tax Provision

        The following table presents income tax provision (in millions):

 
  Year Ended
December 31,
  Change  
 
  2010   2009   Amount   Percent  

Income tax expense (CPE Inc.)

  $ 32.0   $ 68.2   $ (36.2 )   (53.1 )

Effective tax rate (CPE Inc.)

    21.9 %   27.4 %   (5.5 )   (20.1 )

Income tax expense (benefit) (CPE Resources)

 
$

(0.8

)

$

64.0
 
$

(64.8

)
 
*

Effective tax rate (CPE Resources)

    (0.5 )%   25.7 %   (26.2 )     *

*
Change from prior period is not a relevant percentage

CPE Inc.

        The effective income tax rate decreased to 21.9% for the year ended December 31, 2010 from 27.4% for the year ended December 31, 2009. The decrease is primarily attributable to RTEA's former non-controlling interest for which we did not accrue taxes, offset by the effect of the revaluation of our deferred tax assets as a result of the update to the Tax Receivable Agreement liability. The adjustment to the effective tax rate for the post-Secondary Offering period in 2010 to account for pretax income attributable to the controlling interest increased our effective tax rate by approximately 0.3%. See Note 10 of Notes to Consolidated Financial Statements in Item 8.

CPE Resources

        The effective income tax rate decreased to (0.5)% for the year ended December 31, 2010 from 25.7% for the year ended December 31, 2009. The decrease is primarily attributable to the change in tax status of CPE Resources. For most of 2009 (through the date of the IPO), our income tax provision was calculated on a stand-alone, separate return basis while for most of 2010 (through the date of the Secondary Offering), we were organized as a limited liability company and generally were not subject to income taxes. Income taxes are only applicable to the post-Secondary Offering period in 2010. See Note 10 of Notes to Consolidated Financial Statements in Item 8.

68


Table of Contents

Discontinued Operations

        The following table presents discontinued operations (in millions):

 
  Year Ended
December 31,
  Change  
 
  2010   2009   Amount   Percent  

Discontinued operations

  $   $ 211.1   $ (211.1 )     *

*
Change from prior period is not a relevant percentage

        The change in discontinued operations was primarily attributable to the related transactions being completed in the prior year, with no impact to 2010.

Income Attributable to Noncontrolling Interest

        The following table presents income attributable to noncontrolling interest (in millions):

Noncontrolling interest January 1, 2009 through November 19, 2009

  $  

Noncontrolling interest November 19, 2009 through December 31, 2009

    11.8  
       

December 31, 2009 income attributable to noncontrolling interest

  $ 11.8  
       

Noncontrolling interest January 1, 2010 through December 15, 2010

  $ 83.5  

Noncontrolling interest December 15, 2010 through December 31, 2010

     
       

December 31, 2010 income attributable to noncontrolling interest

  $ 83.5  
       

        Income attributable to noncontrolling interest of $83.5 million for the year ended December 31, 2010 represents Rio Tinto's interest in CPE Resources's net income for the period from January 1, 2010 through December 15, 2010. The portion of net income that is attributable to the noncontrolling interest is not equal to 48.3% of consolidated equity or of consolidated net income due to the effects of income taxes and related agreements that pertain solely to CPE Inc. as well as the timing of the Secondary Offering. Specifically, the $19.7 million expense related to the change in the tax agreement liability and related adjustments of $5.4 million to the net value of deferred tax assets are not attributable to the noncontrolling interest. There was no noncontrolling interest prior to the IPO on November 19, 2009 or after the Secondary Offering on December 15, 2010.

Liquidity and Capital Resources

 
  December 31,  
 
  2011   2010   2009  
 
  (in millions)
 

Cash and cash equivalents

  $ 404.2   $ 340.1   $ 268.3  

Investments in marketable securities

    75.2          
               

Total

  $ 479.4   $ 340.1   $ 268.3  
               

        In addition to our cash and cash equivalents, our primary sources of liquidity are cash from our operations, investments in marketable securities and borrowing capacity under CPE Resources's $500 million revolving credit facility. Cash from operations depends on a number of factors beyond our control, such as the market price for our coal, the quantity of coal required by our customers, coal-fired electricity demand, regulatory changes and energy policies impacting our business, our costs of operating including the market price we pay for diesel fuel and other input costs, as well as costs of

69


Table of Contents

logistics including rail and port charges, and other risks and uncertainties, including those discussed in Item 1A "Risk Factors."

        Investments in marketable securities include highly-liquid securities which are generally investment grade or better securities and are held as trading securities by CPE Resources. Our investment policy has the objective of minimizing the potential risk of principal loss and is intended to limit our credit exposure to any single issuer. Individual securities have various maturity dates; however, it is our expectation that we could sell any individual security in the secondary market allowing for improved liquidity.

        On June 3, 2011, CPE Resources entered into an Amended and Restated Credit Agreement (the "Amended Credit Agreement") with Morgan Stanley Senior Funding, Inc., as administrative agent, and a syndicate of lenders. The Amended Credit Agreement establishes a commitment to provide us with a $500 million senior secured revolving credit facility, which can be used to borrow funds or issue letters of credit. Subject to the satisfaction of certain conditions, we may elect to increase the size of the revolving credit facility and/or request the addition of one or more new tranches of term loans in a combined amount of up to $200 million. The credit facility matures on June 3, 2016. The Amended Credit Agreement imposes limitations on the ability of CPE Resources and its subsidiaries to make distributions and/or extend loans to CPE Inc.

        The indenture governing the senior notes also imposes limitations on the ability of CPE Resources and its subsidiaries to make distributions, and to extend loans and advances, to CPE Inc. Such limitations, taken as a whole, are less restrictive than those contained in the Amended Credit Agreement.

        The limitations in both the Amended Credit Agreement and the indenture have not had, nor are they expected to have, a negative impact upon our ability to fund cash obligations.

        The borrowing capacity under the Amended Credit Agreement is reduced by the amount of letters of credit issued. As of December 31, 2011, our borrowing capacity under the Amended Credit Agreement was $489.5 million. Our ability to borrow under our revolving credit facility is subject to the terms and conditions of the facility, including our compliance with financial and non-financial covenants.

        We believe these sources will be sufficient to fund our primary uses of cash for the next twelve months, which include our costs of coal production, coal lease installment payments for existing and new LBAs and other coal tracts, capital expenditures, interest on our debt, and payments to Rio Tinto under our Tax Receivable Agreement.

        During the three months ended June 30, 2011, we were the successful bidder on certain mining rights in the WAII North and WAII South Coal Tracts. Accordingly, we made payments of $59.5 million and $9.9 million, respectively, representing the first of five annual installment payments for each bid award amount. The remaining payments are due annually on the anniversary of the effective dates of the corresponding coal leases, and we expect to make payments of $129.2 million in 2012 related to committed coal leases. We will continue to explore opportunities to increase our reserve base by acquiring additional coal and surface rights. If we are successful in future bids for coal rights, our cash flows could be significantly impacted as we would be required to make associated payments.

        Our anticipated capital expenditures (excluding capitalized interest and federal lease payments), which we expect will be between $70 million and $90 million in 2012, include our estimates of expenditures necessary to keep our current fleets updated to maintain our mining productivity and competitive position and the addition of new equipment as necessary.

        CPE Resources is required to make semi-annual interest payments on its senior notes, which commenced on June 15, 2010. In connection with the IPO, CPE Inc. entered into a Tax Receivable

70


Table of Contents

Agreement with Rio Tinto and recognized a liability for the undiscounted amounts that CPE Inc. estimated will be paid to Rio Tinto under this agreement. The amounts to be paid will be determined based on a calculation of future income tax savings that CPE Inc. actually realizes as a result of the tax basis increase that resulted from the IPO and Secondary Offering transactions. Generally, CPE Inc. retains 15% of the realized tax savings generated from the tax basis step-up and Rio Tinto is entitled to the remaining 85% which is remitted to Rio Tinto on an annual basis. Based on our estimates as of December 31, 2011, we expect to make payments of $19.1 million in 2012, payments averaging approximately $19 million each year during 2013 to 2016 and additional payments in subsequent years.

        If we do not have sufficient resources from ongoing operations to satisfy our obligations or the timing of payments on our obligations does not coincide with cash inflows from operations, we may need to use our cash on hand and marketable securities or borrow under our line of credit. If the obligation is in excess of these amounts, we may need to seek additional borrowing sources or take other actions. Depending upon existing circumstances at the time, we may not be able to obtain additional funding on acceptable terms or at all. In addition, our existing debt instruments contain restrictive covenants, which may prohibit us from borrowing under our revolving credit facility or pursuing certain alternatives to obtain additional funding.

Overview of Cash Transactions

        We started 2011 with $340.1 million of unrestricted cash and cash equivalents and investments in marketable securities. After making interest and coal lease payments, capital expenditures and generating cash from our operating activities, we ended the year with unrestricted cash and cash equivalents and investments in marketable securities of $479.5 million. We started 2011 with $182.1 million of restricted cash. During the year ended December 31, 2011, we were able to negotiate lower collateral requirements with almost all of our surety bond providers thereby releasing $111.0 million in funds. We ended the year with $71.2 million of restricted cash.

Cash Flows

    CPE Inc.

 
  Year Ended December 31,  
 
  2011   2010   2009  
 
  (in millions)
 

Beginning balance—cash and cash equivalents

  $ 340.1   $ 268.3   $ 15.9  

Net cash provided by operating activities

    296.8     324.8     456.6  

Net cash used in investing activities(1)

    (175.7 )   (192.0 )   (417.1 )

Net cash used in financing activities

    (57.0 )   (61.0 )   (582.2 )

Net cash provided by discontinued operations

            795.1  
               

Ending balance—cash and cash equivalents

  $ 404.2   $ 340.1   $ 268.3  
               

Beginning balance—marketable securities

             

Ending balance—marketable securities(1)

    75.2          

71


Table of Contents

    CPE Resources

 
  Year Ended December 31,  
 
  2011   2010   2009  
 
  (in millions)
 

Beginning balance—cash and cash equivalents

  $ 340.1   $ 268.3   $ 15.9  

Net cash provided by operating activities

    296.9     335.7     456.6  

Net cash used in investing activities(1)

    (175.7 )   (192.0 )   (417.1 )

Net cash used in financing activities

    (57.1 )   (71.9 )   (582.2 )

Net cash provided by discontinued operations

            795.1  
               

Ending balance—cash and cash equivalents

  $ 404.2   $ 340.1   $ 268.3  
               

Beginning balance—marketable securities

             

Ending balance—marketable securities(1)

    75.2          

(1)
Included in net cash used in investing activities is the purchase of marketable securities which are highly-liquid securities that are generally investment grade or better and are held as trading securities. Individual securities have various maturity dates; however, it is our expectation that we could sell any individual security in the secondary market allowing for improved liquidity.

        The decrease in cash provided by operating activities from 2010 to 2011 was due to a decrease in working capital changes, primarily due to an increase in accounts receivable and payments on the tax agreement liability partially offset by an increase in net income as adjusted for noncash items. The increase in accounts receivable was driven largely by higher revenues in December 2011 as compared to December 2010.

        The decrease in cash provided by operating activities from 2009 to 2010 was due to a decrease in net income and a decrease in changes in working capital which was primarily caused by a reduction in the receivable from related parties as a result of changes in our relationship with Rio Tinto through the IPO structuring transactions.

        The decrease in cash used in investing activities from 2010 to 2011 was primarily related to our surety bond obligations. Net restricted cash deposits of $101.9 million occurred in the year ended December 31, 2010 compared to restricted cash releases of $111.0 million in the year ended December 31, 2011 following a negotiated reduction of collateral required. This decrease in cash used in investing activities was partially offset by increased purchases of property, plant and equipment, initial payments on federal coal lease obligations, and investments made in marketable securities. Purchases during the year ended December 31, 2011 for property, plant and equipment included payments for haul trucks received in 2010, payments for surface land associated with federal and privately held mineral rights, and cash interest capitalized.

        The decrease in cash used in investing activities from continuing operations from 2009 to 2010 was primarily the result of a $217.5 million decrease in cash advances to affiliates as a result of the cessation of the cash management program we were under with Rio Tinto prior to the IPO structuring transactions and a $28.1 million decrease in the cash paid for property, plant and equipment, including capitalized interest. Purchases during the year ended December 31, 2010 for property, plant, and equipment included the acquisition of the lease by modification at the Spring Creek mine and the purchase of approximately 19 million tons of privately held coal. These decreases were partially offset by a $21.7 million increase in restricted cash to collateralize surety bond obligations.

        The decrease in cash used in financing activities from 2010 to 2011 primarily was due to distributions to Rio Tinto totaling $10.2 million made in 2010 compared to none in 2011 partially offset

72


Table of Contents

by a small increase in the principal portion of payments on federal coal leases and the payment of debt issuance costs of $2.2 million in the current year related to our Amended Credit Agreement.

        Cash used in financing activities from continuing operations during 2009 was comprised of approximately $1.52 billion in distributions to Rio Tinto offset by approximately $1.0 billion in net proceeds from the senior notes offering and the IPO, all of which occurred in 2009. In addition to these amounts paid in 2009, the decrease in cash used in financing activities from 2009 to 2010 was due to lower principal payments on federal coal leases during 2010 and the $26.6 million payment for debt issuance costs during 2009.

Senior Notes

        We refer to the $300 million senior notes due December 15, 2017 (the "2017 Notes") and the $300 million senior notes due December 15, 2019 (the "2019 Notes") collectively as the "senior notes." The 2017 Notes and 2019 Notes bear interest at fixed annual rates of 8.25% and 8.50%, respectively. There is no mandatory redemption or sinking fund payments for the senior notes and interest payments are due semi-annually on June 15 and December 15, beginning on June 15, 2010. Subject to certain limitations, we may redeem the 2017 Notes by paying specified redemption prices in excess of their principal amount prior to December 15, 2015, or by paying their principal amount thereafter. Similarly, we may redeem the 2019 Notes by paying specified redemption prices in excess of their principal amount prior to December 15, 2017, or by paying their principal amount thereafter.

        In connection with the IPO structuring transactions, we distributed $309.7 million of the net proceeds from the offering of the senior notes to RTEA during the fourth quarter of 2009. The remaining net proceeds from the senior notes offering were designated for general corporate purposes.

        The senior notes are jointly and severally guaranteed by all of our existing and future restricted subsidiaries that guarantee our debt under our credit facility. See "—Senior Secured Revolving Credit Facility" below. Substantially all of our consolidated subsidiaries, excluding Decker Coal Company, are considered to be restricted subsidiaries and guarantee the senior notes.

        The indenture governing the senior notes, among other things, limits our ability and the ability of our restricted subsidiaries to incur additional indebtedness and issue preferred equity; pay dividends or distributions; repurchase equity or repay subordinated indebtedness; make investments or certain other restricted payments; create liens; sell assets; enter into agreements that restrict dividends, distributions or other payments from restricted subsidiaries; enter into transactions with affiliates; and consolidate, merge or transfer all or substantially all of their assets and the assets of their restricted subsidiaries on a combined basis.

        Upon the occurrence of certain transactions constituting a "change in control" as defined in the indenture, holders of our notes could require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase.

Senior Secured Revolving Credit Facility

        On June 3, 2011, CPE Resources entered into the Amended Credit Agreement. The Amended Credit Agreement establishes a commitment to provide us with a $500 million senior secured revolving credit facility, which can be used to borrow funds or issue letters of credit. Subject to the satisfaction of certain conditions, we may elect to increase the size of the revolving credit facility and/or request the addition of one or more new tranches of term loans in a combined amount of up to $200 million. Our obligations under the credit facility are secured by substantially all of CPE Resources's assets and substantially all of the assets of certain of CPE Resources's subsidiaries, subject to certain permitted liens and customary exceptions for similar coal financings. Our obligations under the credit facility are also supported by a guarantee by CPE Resources's domestic restricted subsidiaries. The credit facility

73


Table of Contents

matures on June 3, 2016. As of December 31, 2011, letters of credit totaling $10.5 million and no cash borrowings were outstanding under the credit facility. The letters of credit are used as collateral to secure our obligations to reclaim lands used for mining. See Note 15 of Notes to Consolidated Financial Statements in Item 8.

        The Amended Credit Agreement replaced our previous $400 million revolving credit facility agreement dated November 25, 2009. There were no borrowings outstanding under the previous credit facility at the time of replacement or at December 31, 2010. At the time of refinancing, we recorded a charge of $1.0 million to write off certain deferred financing costs as certain banks of the syndicate changed and recorded $2.2 million of new deferred financing costs. The aggregate deferred financing costs are being amortized on a straight-line basis to interest expense over the five-year term of the Amended Credit Agreement.

        Loans under the credit facility bear interest at the London Interbank Offered Rate ("LIBOR") plus an applicable margin of between 1.75% and 2.50%, depending on CPE Resources's leverage ratio. We will pay the lenders a commitment fee between 0.25% and 0.50% per year, depending on CPE Resources's leverage ratio, on the unused amount of the credit facility. Letters of credit issued under the credit facility, unless drawn upon, will incur a per annum fee from the date at which they are issued between 1.75% and 2.50% (2.50% at December 31, 2011) depending on CPE Resources's leverage ratio. Letters of credit that are drawn upon are converted to loans. In addition, in connection with the issuance of a letter of credit, we are required to pay the issuing bank a fronting fee of 0.25% per annum.

        The Amended Credit Agreement contains financial covenants based on EBITDA (which is defined in the Amended Credit Agreement, and is not the same as EBITDA or Adjusted EBITDA otherwise presented) requiring us to maintain defined minimum levels of interest coverage and providing for a limitation on our leverage ratio. Specifically, the Amended Credit Agreement requires us to maintain (a) a ratio of EBITDA to consolidated net cash interest expense equal to or greater than (i) 2.50 to 1 through June 30, 2013 and (ii) 2.75 to 1 from July 1, 2013 to maturity, and (b) a ratio of funded debt to EBITDA equal to or less than (i) 3.75 to 1 through June 30, 2013 and (ii) 3.50 to 1 from July 1, 2013 to maturity. Our federal coal lease obligations are not considered debt under our covenant calculations.

        The Amended Credit Agreement also requires us to comply with non-financial covenants that restrict certain corporate activities. These covenants include restrictions on our ability to incur additional debt and pay dividends, among other restrictive covenants. The Amended Credit Agreement also contains customary events of default with customary grace periods and thresholds. Our ability to access the available funds under the credit facility may be prohibited in the event that we do not comply with the covenant requirements or if we default on our obligations under the Amended Credit Agreement. At December 31, 2011, we were in compliance with the covenants contained in our Amended Credit Agreement.

        Under the Amended Credit Agreement, the subsidiaries of CPE Inc. are permitted to make distributions to CPE Inc. to enable it to pay federal, state and local income and certain other taxes it incurs that are attributable to the business and operations of its subsidiaries and to enable CPE Inc. to pay amounts it owes to Rio Tinto under the Tax Receivable Agreement. In addition, as long as no default under the Amended Credit Agreement exists, the subsidiaries of CPE Inc. also may make annual distributions to CPE Inc. to fund dividends or repurchases of CPE Inc.'s stock and additional distributions in accordance with certain distribution limits in the Amended Credit Agreement. Finally, the subsidiaries of CPE Inc. may make loans to CPE Inc. subject to certain limitations in the Amended Credit Agreement.

74


Table of Contents

Federal Coal Lease Obligations

        Our federal coal lease obligations consist of amounts payable to the BLM under leases, each of which require five equal annual payments. The remaining aggregate annual payments under our existing federal coal leases were as follows as of December 31, 2011 (in millions):

 
  2012   2013   2014   2015  

North Maysdorf (Cordero Rojo mine)

  $ 9.6   $ 9.6   $   $  

South Maysdorf (Cordero Rojo mine)

    50.2              

WAII North (Antelope mine)

    59.5     59.5     59.5     59.5  

WAII South (Antelope mine)

    9.9     9.9     9.9     9.9  
                   

Total

  $ 129.2   $ 79.0   $ 69.4   $ 69.4  
                   

        We recognize imputed interest on federal coal leases based on an estimate of the credit-adjusted, risk-free rates reflecting our estimated credit rating at the inception of the lease. The carrying value reported on our balance sheet of our federal coal lease obligations was $288.3 million as of December 31, 2011. Additional amounts may be incurred should we bid and win additional coal leases in the future.

Off-Balance Sheet Arrangements

        In the normal course of business, we are party to a number of arrangements that secure our performance under certain legal obligations. These arrangements include letters of credit and surety bonds. We use these arrangements primarily to comply with federal and state laws that require us to secure the performance of certain long-term obligations, such as mine closure or reclamation costs, coal lease obligations, state workers' compensation, and federal black lung liabilities. These arrangements are typically renewable annually. Liabilities related to these arrangements are not reflected in our consolidated balance sheets.

        As of December 31, 2011, we used surety bonds and letters of credit to secure outstanding obligations as follows (in millions):

 
  Surety
Bonds
  Letters of
Credit
  Total  

Reclamation obligations(1)

  $ 536.8   $ 10.5   $ 547.3  

Lease obligations(2)

    30.8         30.8  

Other obligations(3)

    0.5         0.5  
               

Total off-balance sheet obligations

  $ 568.1   $ 10.5   $ 578.6  
               

Collateralized by:

                   

Restricted cash(1)(4)

  $ 71.2   $   $ 71.2  
               

(1)
Reclamation obligations include amounts to secure performance related to our outstanding obligations to reclaim areas disturbed by our mining activities and are a requirement under our state mining permits. The $71.2 million of restricted cash collateralizes our 50% share of surety bonds that secure Decker's reclamation obligations.

(2)
Lease obligations include amounts generally required as a condition to state or federal coal leases; the amounts vary and are mandated by the governing agency.

(3)
Other obligations include amounts required for exploration permits, water well construction and monitoring, exporting, and other miscellaneous items as mandated by applicable governing agencies.

75


Table of Contents

(4)
We are required to collateralize some of our surety bonds with cash or letters of credit. We can substitute collateral at our discretion.

        Our outstanding surety bonds in respect of our reclamation, lease and other obligations were $568.1 million at December 31, 2011 (including our obligations with respect to the Decker mine) and are required by law. State statutes regulate and determine the calculation of the amounts of the bonds that we are required to hold. We do not believe that these state-mandated estimates are a true reflection of what our actual reclamation costs will be. Reclamation bond amounts represent an estimate of the near-term reclamation liability that assumes reclamation activities will be performed by a third party during the next one to five years. Because this evaluation is near-term, it is recalculated on a frequent basis, often annually. The basis for calculating bond requirements is substantially different than the requirements that apply to the determination of our ARO liability on our consolidated balance sheet, which is determined in accordance with U.S. GAAP. The state calculates our specific bond requirements considering assumed costs that the state would incur if they were required to complete the reclamation on our behalf. Additionally, where a multi-year bond, such as a three to five-year bond, is put into place, the state regulatory authority requires that the reclamation liability be calculated for the highest cost scenario over that period.

        The carrying amount of our reclamation obligations, as determined in accordance with U.S. GAAP, which are reported in our consolidated financial statements as ARO liabilities, was $192.7 million at December 31, 2011, $6.9 million of which is classified as a current liability. We estimate our ARO liabilities based on disturbed acreage to date and the estimated cost of a third party to perform the work. The estimated ARO liabilities are also based on engineering studies and our engineering expertise related to the reclamation requirements. We also assume that reclamation will be completed after the end of the mine life based on our current reclamation area profiles, which may be a different land disturbance assumption than the state requires, as we generally perform reclamation concurrently with our mining activities. Finally, the carrying amount of our ARO liabilities reflects discounting of estimated reclamation costs using credit-adjusted, risk-free rates. For a discussion of the risks relating to our reclamation obligations, see Item 1A "Risk Factors—Risks Related to Our Business and Industry—If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated."

        Because we are required by state and federal law to have these bonds or letters of credit 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 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 and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of any credit facility then in place. See Note 15 of Notes to Consolidated Financial Statements in Item 8.

76


Table of Contents

Contractual Obligations

        As of December 31, 2011, we had the following contractual obligations (in millions):

 
  Total   2012   2013 - 2014   2015 - 2016   2017 and
Thereafter
 

Senior notes(1)

  $ 600.0   $   $   $   $ 600.0  

Coal lease obligations(2)

    294.9     103.8     123.8     64.0     3.3  

Interest related to long-term obligations(3)

    415.8     77.5     127.0     106.0     105.3  

Operating and capital lease obligations

    5.1     0.9     1.4     0.9     1.9  

Coal purchase obligations(4)

    5.7     5.7              

Transportation and supplies(5)

    164.8     16.2     49.7     27.2     71.7  

Capital expenditure obligations(4)

    32.3     8.6             23.7  
                       

Total

  $ 1,518.6   $ 212.7   $ 301.9   $ 198.1   $ 805.9  
                       

(1)
CPE Resources issued $600 million aggregate principal amount of senior notes in two tranches due 2017 and 2019. CPE Resources also has entered into a $500 million Amended Credit Agreement, none of which had been drawn as of December 31, 2011. See Note 11 of Notes to Consolidated Financial Statements in Item 8.

(2)
Coal lease obligations include our discounted payment obligations under federal coal leases, private coal leases and land purchase notes. See Note 12 of Notes to Consolidated Financial Statements in Item 8.

(3)
As of December 31, 2011, we had outstanding commitments for interest related to our senior notes, private coal lease and land purchase notes, and imputed interest for our federal coal lease obligations. See Notes 11 and 12 of Notes to Consolidated Financial Statements in Item 8.

(4)
As of December 31, 2011, we had outstanding commitments for coal purchases and capital expenditures which are not included on our consolidated balance sheet. See Note 15 of Notes to Consolidated Financial Statements in Item 8.

(5)
As of December 31, 2011, we had outstanding commitments for transportation of $135.1 and commitments for the purchase of supplies to be used in our mining operations of $29.6. See Note 15 of Notes to Consolidated Financial Statements in Item 8.

        This table does not include our estimated AROs. As discussed in "Critical Accounting Policies and Estimates—Asset Retirement Obligations" below, the current and noncurrent carrying amount of our AROs involves a number of estimates, including the amount and timing of the payments to satisfy these obligations. The timing of payments is based on numerous factors, including projected mine closing dates. Based on our assumptions, the carrying amount of our AROs (excluding concurrent reclamation and amounts due in the current period) as determined in accordance with U.S. GAAP is $192.7 million as of December 31, 2011. See Note 13 of Notes to Consolidated Financial Statements in Item 8.

        This table does not include our contractual obligations related to an agreement we entered into in April 2008 to purchase land adjacent to our Antelope mine, whereby the seller may require us to pay a purchase price of up to $23.7 million, which will close between April 2013 and April 2018.

        This table does not include payments that we expect to make under the Tax Receivable Agreement. We have recognized a $170.6 million liability for our estimated payments to RTEA under the Tax Receivable Agreement, of which $19.1 million and $151.5 million is classified as current and noncurrent, respectively, as of December 31, 2011. The estimated liability is based on forecasts of future taxable income over the anticipated life of our mining operations and reclamation activities,

77


Table of Contents

assuming no additional coal reserves are acquired. The assumptions used in our forecasts are subject to substantial uncertainty about our future business operations and the actual payments that we are required to make under the Tax Receivable Agreement could differ materially from our estimates. Based on our estimates as of December 31, 2011, we expect to make payments of $19.1 million in 2012, payments averaging approximately $19 million each year during 2013 to 2016 and additional payments in subsequent years. See Item 1A "Risk Factors—Other Risks Related to Our Corporate Structure and Common Stock—We are required to pay RTEA for most of the tax benefits we may claim as a result of the tax basis step-up we received in connection with the IPO, related IPO structuring transactions and Secondary Offering. In certain cases, payments to RTEA may be accelerated or exceed our actual cash tax savings. These provisions may deter a change in control of our company."

Critical Accounting Policies and Estimates

        The preparation of consolidated financial statements and related disclosures in accordance with accounting principles generally accepted in the U.S. requires us to make judgments, estimates, and assumptions that affect the reported amounts of assets, liabilities, and revenues and expenses, as well as the disclosure of contingent assets and liabilities. We base our judgments, estimates, and assumptions on historical information and other known factors that we deem relevant. Estimates are inherently subjective, as significant management judgment is required regarding the assumptions utilized to calculate accounting estimates in our consolidated financial statements, including the notes thereto. Actual results could differ materially from the amounts reported based on variability in factors affecting these consolidated financial statements. Our significant accounting policies are described in Note 3 of Notes to Consolidated Financial Statements in Item 8. This section describes those accounting policies and estimates that we believe are critical to understanding our consolidated financial statements.

Revenue Recognition

        We recognize revenue from a sale when persuasive evidence of an arrangement exists, the price is determinable, the product has been delivered, title has transferred to the customer and collection of the sales price is reasonably assured. Some coal supply agreements provide for price adjustments based on variations in quality characteristics of the coal shipped. In certain cases, a customer's analysis of the coal quality is binding and the results of the analysis are received on a delayed basis. In these cases, we estimate the amount of the quality adjustment and adjust the estimate to actual when the information is provided by the customer. Historically, such adjustments have not been material.

Asset Retirement Obligations

        Our AROs arise from the Surface Mining Control and Reclamation Act ("SMCRA") and similar state statutes. These regulations require that we, upon closure of a mine, restore the mine property in accordance with an approved reclamation plan issued in conjunction with our mining permit. Our AROs are recorded initially using estimates of future third-party costs.

        To determine our AROs, we calculate on a mine-by-mine basis the present value of estimated future reclamation cash flows based upon each mine's permit requirements, estimates of the current disturbed acreage subject to reclamation, which is based upon approved mining plans, estimates of future reclamation costs, and assumptions regarding the mine's productivity, which are based on engineering estimates that include estimates of volumes of earth and topsoil to be moved, the purchase and use of particular pieces of large mining equipment to move the earth, and the operating costs for those pieces of equipment. These cash flow estimates are discounted at credit-adjusted, risk-free rates to arrive at a present value of estimated future reclamation costs. Upon initial recognition of the liability, a corresponding amount is capitalized as part of the carrying value of the related long-lived asset.

78


Table of Contents

        The amount recorded as an ARO for a mine may change as a result of mining permit changes granted by mining regulators, changes in the timing of mining activities and the mine's productivity from original estimates and changes in the estimated costs or the timing of reclamation activities. We periodically update estimates of cash expenditures to meet each mine's reclamation requirements and we adjust the ARO in accordance with U.S. GAAP, which generally requires a measurement of the present value of any change in estimated reclamation costs using credit-adjusted, risk-free rates. If a reduction of the asset retirement obligation exceeds the carrying amount of the related asset retirement cost, the adjustment is recorded as a reduction of depletion expense. Annually, we analyze AROs on a mine-by-mine basis and, if necessary, adjust the balance to take into account any changes in estimates. In addition, on an interim basis, we may update the liability based on significant changes to the life of mine.

Federal Coal Leases

        Upon the award date of federal coal leases pursuant to which payments are required to be paid in equal annual installments, we recognize an asset for the related mineral rights in property, plant, and equipment and a corresponding liability for our future payment obligations in liabilities. The amount recognized as an asset is the sum of the initial installment due at the effective date of the lease and the amount recognized in liabilities, which reflects the present value of the remaining installments. We determine the present value of the remaining installments using an estimate of the credit-adjusted, risk-free rates that reflects our credit rating. Interest is recognized over the term of the lease based on the imputed interest rate that was used to determine the initial liabilities amount on the effective date. Such interest may be capitalized while activities are in progress to prepare the acquired coal reserves for mining. The mineral rights asset recorded at the effective date is eventually recognized in depreciation and depletion expense using the units-of-production method over the period the related coal reserves are mined.

Income Taxes and Tax Agreement Liability

        Periodically, we evaluate the realizability of our deferred tax assets and adjust the related valuation allowance to reflect our updated estimate of the tax benefits that are more likely than not to be realized. Our evaluation is based on our consideration of CPE Resources's historical operations, the effects of the structuring and financing transactions completed in connection with the IPO and Secondary Offering, updated forecasts of taxable income over the remaining lives of our mines, the availability of tax planning strategies and other factors. If future taxable income differs from our estimates or if expected tax planning strategies are not available as anticipated, adjustments to the valuation allowance may be needed.

        We have recognized a tax agreement liability reflecting our estimate of the undiscounted amounts that we expect to pay to RTEA under this agreement. Periodically, we adjust the liability based on an updated estimate of the amounts that we expect to pay, using assumptions consistent with those used in our concurrent estimate of the deferred tax asset valuation allowance. These periodic adjustments to the tax agreement liability are reflected in our consolidated pretax income, and may also result in corresponding adjustments to our income tax expense and deferred income tax accounts. Increases in our estimates of future taxable income through, for example, acquisitions of additional coal leases increase the likelihood of our future profitability, and therefore, are likely to increase our tax agreement liability and related deferred tax asset in the future. Although our periodic adjustments to the deferred tax asset valuation allowance and tax agreement liability are based on consistent assumptions, the calculations required to determine these estimates differ in certain respects and the related adjustments will not have offsetting or proportionate effects on our earnings. In addition, our estimates reflect assumptions about future events that are inherently uncertain. Accordingly, our

79


Table of Contents

periodic adjustments to the deferred tax asset valuation allowance and the tax agreement liability may have material and unpredictable effects on our consolidated financial statements.

Seasonality

        Our business has historically experienced only limited variability in results due to the effect of seasons. Demand for coal-fired power can increase due to unusually hot or cold weather, as power consumers use more air conditioning or heating. Conversely, mild weather can result in softer demand for our coal. Adverse weather conditions, such as blizzards or floods, can impact our ability to mine and ship our coal, and our customers' ability to take delivery of coal.

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, 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 such as mandating use by utilities of renewable fuel sources, 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—Global Climate Change" and Item 1A "Risk Factors" for additional discussion regarding how climate change and other environmental regulatory matters impact our business.

Newly Adopted Accounting Standards and Recently Issued Accounting Pronouncements

        See Note 3 of Notes to Consolidated Financial Statements in Item 8 for a discussion of newly adopted accounting standards and recently issued accounting pronouncements.

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

        We define market risk as the risk of economic loss as a consequence of the adverse movement of market rates and prices. We believe our principal market risks are commodity price risk, interest rate risk and credit risk.

Commodity Price Risk

        Market risk includes the potential for changes in the market value of our coal portfolio. Due to the lack of quoted market prices and the long-term nature of our forward sales position, we have not quantified the market risk related to our coal supply agreements. Historically, we have principally managed the commodity price risk for our coal contract portfolio through the use of long-term coal supply agreements of varying terms and durations. As of December 31, 2011, we had contracted to sell approximately 94 million tons during 2012, of which 88 million tons are under fixed-price contracts. A $1 change to the average coal sales price per ton for these 6 million unpriced tons would result in an approximate $6 million change to the coal sales revenue. In addition, during 2011, we entered into certain derivative financial instruments to help manage our exposure to variability in future

80


Table of Contents

international coal prices. As of December 31, 2011, these derivative financial instruments consisted of contracts for approximately 215,000 and 322,000 tons which will settle in 2012 and 2013, respectively.

        We also face price risk involving other commodities used in our production process, primarily diesel fuel. Based on our projections of our usage of diesel fuel for the next 12 months, and assuming that the average cost of diesel fuel increases by 10%, we would incur additional fuel costs of approximately $10 million over the next twelve months. Historically, we have not hedged commodities such as diesel fuel. We may enter into hedging arrangements with respect to these commodities in the future.

Interest Rate Risk

        Our Amended Credit Agreement is subject to an adjustable interest rate. See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Senior Secured Revolving Credit Facility." We had no outstanding borrowings under our credit facility as of December 31, 2011. If we borrow funds under the revolving credit facility, we may be subject to increased sensitivity to interest rate movements. Any future debt arrangements that we enter into may also have adjustable interest rates that may increase our sensitivity to interest rate movements.

Credit Risk

        We are exposed to credit loss in the event of non-performance by our counterparties, which may include end-use customers, trading houses, brokers, and financial institutions that serve as counterparties to our derivative financial instruments and hold our investments. We attempt to manage this exposure by entering into agreements with counterparties that meet our credit standards and that are expected to fully satisfy their obligations under the contracts.

        When appropriate (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps include obtaining letters of credit and requiring prepayments for shipments.

81


Table of Contents

Item 8.    Financial Statements and Supplementary Data.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Cloud Peak Energy Inc.:

        In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, equity and cash flows present fairly, in all material respects, the financial position of Cloud Peak Energy Inc. and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our audits (which were integrated audits in 2011 and 2010). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Denver, Colorado
February 16, 2012

82


Table of Contents


Report of Independent Registered Public Accounting Firm

To the Member of Cloud Peak Energy Resources LLC:

        In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, members' equity and cash flows present fairly, in all material respects, the financial position of Cloud Peak Energy Resources LLC and its subsidiaries (the "Company") at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Denver, Colorado
February 16, 2012

83


Table of Contents


CLOUD PEAK ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

 
  Year Ended December 31,  
 
  2011   2010   2009  

Revenues

  $ 1,553,661   $ 1,370,761   $ 1,398,200  
               

Costs and expenses

                   

Cost of product sold (exclusive of depreciation, depletion, amortization and accretion, shown separately)

    1,151,117     978,914     933,489  

Depreciation and depletion

    87,127     100,023     97,869  

Amortization

        3,197     28,719  

Accretion

    12,469     12,499     12,587  

Selling, general and administrative expenses

    52,480     63,594     69,835  

Asset impairment charges

        659     698  
               

Total costs and expenses

    1,303,193     1,158,886     1,143,197  
               

Operating income

    250,468     211,875     255,003  
               

Other income (expense)

                   

Interest income

    592     565     320  

Interest expense

    (33,866 )   (46,938 )   (5,992 )

Tax agreement expense

    (19,854 )   (19,669 )    

Other, net

    2,105     157     9  
               

Total other expense

    (51,023 )   (65,885 )   (5,663 )
               

Income from continuing operations before income tax provision and earnings from unconsolidated affiliates

    199,445     145,990     249,340  

Income tax (expense) benefit

    (11,449 )   (31,982 )   (68,249 )

Earnings from unconsolidated affiliates, net of tax

    1,801     3,189     1,381  
               

Income from continuing operations

    189,797     117,197     182,472  

Income from discontinued operations, net of tax

            211,078  
               

Net income

    189,797     117,197     393,550  

Less: Net income attributable to noncontrolling interest

        83,460     11,849  
               

Net income attributable to controlling interest

  $ 189,797   $ 33,737   $ 381,701  
               

Amounts attributable to controlling interest common stockholders:

                   

Income from continuing operations

  $ 189,797   $ 33,737   $ 170,623  

Income from discontinued operations

            211,078  
               

Net income

  $ 189,797   $ 33,737   $ 381,701  
               

Earnings per common share attributable to controlling interest:

                   

Basic

                   

Income from continuing operations

  $ 3.16   $ 1.06   $ 3.01  

Income from discontinued operations

            3.73  
               

Net income

  $ 3.16   $ 1.06   $ 6.74  
               

Weighted-average shares outstanding—basic

    60,004     31,889     56,617  
               

Diluted

                   

Income from continuing operations

  $ 3.13   $ 1.06   $ 2.97  

Income from discontinued operations

            3.52  
               

Net income

  $ 3.13   $ 1.06   $ 6.49  
               

Weighted-average shares outstanding—diluted

    60,637     31,889     60,000  
               

   

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

84


Table of Contents


CLOUD PEAK ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(in thousands)

 
  December 31,  
 
  2011   2010  

ASSETS

             

Current assets

             

Cash and cash equivalents

  $ 404,240   $ 340,101  

Restricted cash

    71,245     182,072  

Investments in marketable securities

    75,228      

Accounts receivable, net

    95,247     65,173  

Due from related parties

    471     434  

Inventories

    71,648     64,970  

Deferred income taxes

    37,528     21,552  

Other assets

    15,294     17,449  
           

Total current assets

    770,901     691,751  

Noncurrent assets

             

Property, plant and equipment, net

    1,350,135     1,008,337  

Goodwill

    35,634     35,634  

Deferred income taxes

    132,828     140,985  

Other assets

    29,821     38,400  
           

Total assets

  $ 2,319,319   $ 1,915,107  
           

LIABILITIES AND EQUITY

             

Current liabilities

             

Accounts payable

  $ 71,427   $ 81,975  

Royalties and production taxes

    136,072     127,038  

Accrued expenses

    65,928     51,197  

Current portion of tax agreement liability

    19,113     18,226  

Current portion of federal coal lease obligations

    102,198     54,630  

Other liabilities

    4,971     4,880  
           

Total current liabilities

    399,709     337,946  

Noncurrent liabilities

             

Tax agreement liability, net of current portion

    151,523     171,885  

Senior notes

    596,077     595,684  

Federal coal lease obligations, net of current portion

    186,119     63,659  

Asset retirement obligations, net of current portion

    192,707     182,170  

Other liabilities

    42,795     32,564  
           

Total liabilities

    1,568,930     1,383,908  
           

Commitments and Contingencies (Note 15)

             

Equity

             

Common stock ($0.01 par value; 200,000 shares authorized; 60,923 and 60,878 shares issued and outstanding at December 31, 2011 and December 31, 2010, respectively)

    609     609  

Additional paid-in capital

    536,301     502,952  

Retained earnings

    232,093     42,296  

Accumulated other comprehensive loss

    (18,614 )   (14,658 )
           

Total equity

    750,389     531,199  
           

Total liabilities and equity

  $ 2,319,319   $ 1,915,107  
           

   

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

85


Table of Contents


CLOUD PEAK ENERGY INC.

CONSOLIDATED STATEMENTS OF EQUITY

(in thousands)

 
  Common Stock    
   
  Accumulated
Other
Comprehensive
Income (Loss)
   
   
   
 
 
  Additional
Paid-In
Capital
  Retained
Earnings
(Deficit)
  Former
Parent's
Equity
  Non-
controlling
Interest
   
 
 
  Shares   Amount   Total  

Balances at December 31, 2008

      $   $   $ (116 ) $ (4,508 ) $ 989,790   $   $ 985,166  

Net income

                    8,575         373,126     11,849     393,550  

Decker pension adjustments, net of tax

                        707         1,032     1,739  

Retiree medical plan initiation and adjustment, net of tax

                        (5,299 )       (7,741 )   (13,040 )
                                         

Total comprehensive income

                    8,575     (4,592 )   373,126     5,140     382,249  

Stock compensation

                785             1,180         1,965  

Cash distribution to former parent

                            (8,477 )       (8,477 )

Costs incurred by affiliates

                            8,542         8,542  

Distribution of Jacobs Ranch mine sale proceeds

                            (764,122 )       (764,122 )

IPO structuring transactions

                46,430         1,327     (3,815 )       43,942  

IPO and distribution of proceeds

    30,600     306     433,449             (433,755 )        

Proceeds in excess of carrying amounts

                (38,694 )           38,694          

Restricted stock issuance

    849     8     (8 )                    

Distribution of senior notes proceeds

                            (309,704 )       (309,704 )

RTEA deconsolidation

                        (2,624 )   108,541         105,917  

Noncontrolling interest

                (190,879 )       3,446         187,433      
                                   

Balances at December 31, 2009

    31,449     314     251,083     8,459     (6,951 )       192,573     445,478  

Net income

                    33,737             83,460     117,197  

Postemployment benefit adjustment, net of tax

                        (1,625 )       654     (971 )
                                         

Total comprehensive income

                    33,737     (1,625 )       84,114     116,226  

Adjustment to beginning balance, Tax Receivable Agreement

                2,414                     2,414  

Stock compensation

                7,234                     7,234  

Restricted stock issuance

    29     1     (1 )                    

Distributions to Rio Tinto

                                (10,203 )   (10,203 )

Change in ownership allocation

                    100             (100 )    

Effects of Secondary Offering

    29,400     294     242,222         (6,082 )       (266,384 )   (29,950 )
                                   

Balances at December 31, 2010

    60,878     609     502,952     42,296     (14,658 )           531,199  

Net income

                    189,797                 189,797  

Postemployment benefit adjustment, net of tax

                        (3,956 )           (3,956 )