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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549

FORM 10-K

(Mark One)ý

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the year ended December 31, 2010oro

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period
from                                     to


Commission File Number: 001-34547

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

Delaware(State or other jurisdiction of
incorporation or organization)

26-3088162(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)
(Former name, former address and former fiscal year, if changed since last report)

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

Title of Each Class

Name of Each Exchange on Which RegisteredCommon 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 Yes o    No ý

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

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

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

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

Accelerated filer ý

Non-accelerated filer o (Do not check if a smaller reporting company)

Smaller reporting company o


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

As of June 30, 2010, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the voting
stock held by non-affiliates of the registrant was approximately $418 million based on the closing price of the registrant's common stock as reported that day on the New York Stock
Exchange of $13.26 per share. In determining this figure, the registrant 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 each of the registrant's classes of common stock, as of January 31, 2011: common stock, par value $0.01 per share 60,877,517 shares
outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions
of the registrant's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the registrant's 2011 annual meeting of stockholders (the "Proxy
Statement") are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.



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TABLE OF CONTENTS



PAGEPART IITEM 1

BUSINESS


7ITEM 1A

RISK FACTORS


32ITEM 1B

UNRESOLVED STAFF COMMENTS


60ITEM 2

PROPERTIES


60ITEM 3

LEGAL PROCEEDINGS


64ITEM 4

RESERVED


65PART IIITEM 5

MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS


66ITEM 6

SELECTED FINANCIAL DATA


67ITEM 7

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


72ITEM 7A

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


94ITEM 8

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


96ITEM 9

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE


144ITEM 9A

CONTROLS AND PROCEDURES


144ITEM 9B

OTHER INFORMATION


145PART IIIITEM 10

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE


148ITEM 11

EXECUTIVE COMPENSATION


148ITEM 12

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


148ITEM 13

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE


148ITEM 14

PRINCIPAL ACCOUNTING FEES AND SERVICES


148PART IVITEM 15

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES


149


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CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

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



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GLOSSARY FOR SELECTED MINING TERMS

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

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

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

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

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

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

BNSF.Burlington Northern Santa Fe Railroad.

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

CAIR.Clean Air Interstate Rule.

Carbon dioxide,orCO2.    A gaseous chemical compound that is
generated as a by-product of the combustion of fossil fuels, including coal, or the burning of vegetable matter, among other process.

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

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

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

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

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

EIA.Energy Information Administration.

EIS.Environmental impact statement.

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Force majeure.An event not anticipated as of the date of the applicable contract, which is not within the reasonable control of the
party affected
by such event, which partially or entirely prevents such party's ability to perform its contractual obligations. During the duration of such force majeure but for no longer period, the obligations of
the party affected by the event may be excused to the extent required.

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

GW.Gigawatts.

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

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

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

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

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

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

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

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

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

MSHA.Mine Safety and Health Administration.

NAAQ.National Ambient Air Quality.

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

Non-reserve coal deposits.Non-reserve coal deposits are coal bearing bodies that have been sufficiently sampled and analyzed
in trenches, outcrops, drilling and underground workings to assume continuity between sample points, and therefore warrant further exploration work. However, this coal

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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, although lower than that for proven reserves, is high enough to
assume continuity between points of observation.

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

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

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

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

Riverine habitat.A habitat occurring along a river.

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

SMCRA.Surface Mining Control and Reclamation Act of 1977.

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

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

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

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

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

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

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

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

Union PacificorUP.    Union Pacific Railroad.

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



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PART I

Item 1.Business.

Overview

Cloud Peak Energy Inc. is the third largest producer of coal in the U.S. and in the Powder River Basin, or PRB, based on our
2010 coal production of 95.3 million tons. We had revenues from our continuing operations of $1.4 billion in 2010. We operate some of the safest mines in the industry. According to Mine
Safety and Health Administration, or MSHA, data, in 2010 we had one of the lowest employee all injury incident rate among the ten largest U.S. coal producing companies. We operate solely in the PRB,
the lowest cost coal producing region of the major coal producing regions in the U.S., and operate two of the four largest coal mines in the region and in the U.S. Our operations include three
wholly-owned surface coal mines, two of which are in Wyoming and one of which is in Montana. We also own a 50% interest in a fourth surface coal mine in Montana. We produce sub-bituminous
steam coal with low sulfur content and sell our coal primarily to domestic electric utilities, supplying approximately 47 customers with over 108 domestic plants. We do not produce any metallurgical
coal. Steam coal is primarily consumed by electric utilities and industrial consumers as fuel for electricity generation. In 2010, the coal we produced generated approximately 4% of the electricity
produced in the U.S. As of December 31, 2010, we controlled approximately 970 million tons of proven and probable reserves.

Cloud
Peak Energy 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 as of December 31, 2010 of 100% of the common membership units in CPE Resources as discussed more fully in "History"
below. Our only source of cash flow from operations will be distributions from CPE Resources pursuant to the CPE Resources limited liability company agreement. We also receive management fees pursuant
to a management services agreement between us and CPE Resources as reimbursement of certain administrative expenses.

History

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

On
December 15, 2010, Cloud Peak Energy Inc. priced a secondary offering of 29,400,000 shares of its common stock on behalf of Rio Tinto (the "Secondary Offering"). In
connection with the

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Secondary
Offering, we exchanged 29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the Secondary Offering, resulting in a divestiture
of 100% of Rio Tinto's holdings in CPE Resources. As a result of this transaction, CPE Resources is now a wholly-owned subsidiary of Cloud Peak Energy Inc.

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

GRAPHIC

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Coal Characteristics

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

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Heat Value

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

Sulfur Content

Federal and state environmental regulations, including regulations that limit the amount of sulfur dioxide that may be emitted as a
result of combustion, have affected and may continue to affect the demand for certain types of coal. The sulfur content of coal can vary from seam to seam and within a single seam. The chemical
composition and concentration of sulfur in coal affects the amount of sulfur dioxide produced in combustion. Coal-fired power plants can comply with sulfur dioxide emissions regulations by
burning coal with low sulfur content, blending coals with various sulfur contents, purchasing emission allowances on the open market and/or using sulfur-reduction technology. PRB coal typically has a
lower sulfur content than eastern U.S. coal and generally emits no greater than 0.8 pounds of sulfur dioxide per million Btus. All of our reserves are compliance coal under the Clean Air Act.

Higher
sulfur noncompliance coal can be burned in plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by up to 90%, and in
facilities that blend compliance and noncompliance coal. In 2009, out of utilities with a coal generating capacity of approximately 314 GW, utilities accounting for a capacity of over 168 GW had been
retrofitted with scrubbers. Furthermore, all new coal-fired generation plants built in the U.S. are expected to use some type of sulfur-reduction technology. The demand or price for lower
sulfur coal may decrease with widespread implementation of sulfur-reduction technology.

Other

Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from seam to seam. Ash
content is an important characteristic of coal because it impacts boiler performance and electric generating plants must handle and dispose of ash following combustion. The ash content of PRB coals is
generally low, representing approximately 5% to 10% by weight. The composition of the ash, including the proportion of sodium oxide, as well as the ash and fusion temperatures are important
characteristics of coal and help determine the suitability of the coal to end users. In limited cases, customer requirements at the Spring Creek mine have required, and may continue to require, the
addition of earthen materials to dilute the sodium oxide content of the post-combustion ash of the coal.

Moisture
content of coal varies by the type of coal and the region where it is mined. In general, high moisture content is associated with lower heat values and generally makes the coal
more expensive to transport. Moisture content in coal, on an as-sold basis, can range from approximately 2% to over 35% of the coal's weight. PRB coals have typical moisture content of 25%
to 35%.

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

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Coal Mining Methods

Surface Mining

All of our mines are surface mining operations utilizing both dragline and truck-and-shovel mining methods.
Surface mining is used when coal is found relatively close to the surface. Surface mining typically involves the removal of topsoil, and drilling and blasting the overburden (earth and rock covering
the coal) with explosives. The overburden is then removed with draglines, trucks, shovels and dozers. Trucks and shovels then remove the coal. The final step involves replacing the overburden and
topsoil after the coal has been excavated, reestablishing vegetation and plant life into the natural habitat and making other changes designed to provide local community benefits. We typically recover
92% or more of the economic coal seam for the mines we operate.

Coal Preparation and Blending

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

Mining Operations

We operate solely in the PRB. Two of the mines we operate are located in Wyoming and one is located in Montana. We also own a 50%
non-operating interest
in the Decker mine, which is located in Montana and operated by a third-party mine operator. We currently own the majority of the equipment utilized in our mining operations, excluding the Decker
mine. We employ preventative maintenance and rebuild programs and upgrade our equipment as part of our efforts to ensure that it is productive, well-maintained and
cost-competitive. Our maintenance programs also utilize procedures designed to enhance the efficiencies of our operations. The following table provides summary information regarding our
mines as of December 31, 2010.

Tons Sold
(in millions)2010 As Delivered AverageAnnual
Maximum
Production
Capacity(1)Mine

Btu
per lb

Ash
Content(2)

Sulfur Content

2010

2009

2008(million tons)



(%)

(%)

(lbs SO2/mmBtu)

(million tons)Antelope


42


8,858


5.4


0.26


0.59


35.9


34.0


35.8Cordero Rojo


65


8,389


5.4


0.31


0.74


38.5


39.3


40.0Spring Creek


24


9,262


5.2


0.32


0.69


19.3


17.6


17.9Decker(3)


16


9,482


4.5


0.42


0.89


1.5


2.3


3.3Other(4)


N/A


N/A


N/A


N/A


N/A


1.7


10.1


8.1Total

















96.9


103.3


105.1


(1)Based
on the respective mine's current air quality permit restrictions.(2)Post-combustion
ash from Spring Creek coal contains an average of approximately 8% sodium oxide. Earthen materials can be selectively blended
with the coal within the crushing facility to


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reduce
the post-combustion sodium level and enable the production of a range of products tailored for customers requiring lower sodium levels. (3)Tons
sold numbers reflect our 50% interest in the Decker mine.(4)The
tonnage shown for "Other" represents our purchases from third-party sources that we have resold, including coal we have purchased and resold from the
Jacobs Ranch mine, which our predecessor used to own. See "Customers and Coal ContractsBroker Sales and Third-Party Sources."


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

The
following map shows the locations of our mining operations:

GRAPHIC

Antelope Mine

The Antelope mine is located in the southern end of the PRB approximately 60 miles south of Gillette, Wyoming. The mine extracts steam
coal from the Anderson and Canyon Seams, with up to 44 and 36 feet, respectively, in thickness. We have nominated as an LBA, a large coal tract adjacent to our existing operation. The BLM will
determine if the tract will be leased, and if so, the final boundaries of, and the coal tonnage for, this tract. Acquisition of this tract would facilitate access to approximately 80 million
tons of non-reserve coal deposits that we control. We currently expect the BLM will schedule this LBA for bid sometime in 2011, subject to the outcome of legal challenges filed in 2010
against the BLM and the Secretary of the Interior by environmental organizations with respect to the EIS and other matters associated with the West Antelope II LBA. Other potential large areas of
unleased coal north and west of the mine are available for nomination by us or other mining operations or persons.

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Cordero Rojo Mine

The Cordero Rojo mine is located approximately 25 miles south of Gillette, Wyoming. The mine extracts steam coal from the Wyodak Seam,
which ranges from approximately 55 to 70 feet in thickness. We have nominated as an LBA a large coal tract adjacent to our existing operation, which we now believe the BLM will schedule for lease in
2011 or 2012. The BLM will determine if the tract will be leased, and if so, the final boundaries of, and the coal tonnage for, this tract. Significant areas of unleased coal are potentially available
for nomination by us or other mining operations or persons adjacent to our current operations.

Spring Creek Mine

The Spring Creek mine is located in Montana approximately 35 miles north of Sheridan, Wyoming. The mine extracts steam coal from the
Anderson-Dietz Seam, which averages approximately 80 feet in thickness. The location of the mine relative to the Great Lakes is attractive to our customers in the northeast because of lower
transportation costs. The location of the
Spring Creek mine also provides access to export terminals in the Pacific northwest, providing an advantage relative to other PRB mines. As a result, interest from foreign buyers in coal from our
Spring Creek mine continues, and, in 2010, we shipped approximately 3.3 million tons of Spring Creek coal through the Westshore terminal. In June 2010, we entered into a Modified Coal Lease
(the "Lease Modification") with the BLM. The Lease Modification modified Coal Lease MTM-069782 (the "Existing Lease") and added approximately 48 million tons of proven and probable
reserves to the Existing Lease.

Decker Mine

The Decker mine is located immediately to the southeast of our Spring Creek mine in Montana. We own a non-operating 50%
interest in the mine. The Decker mine is a union based operation; however, we do not employ any of the Decker mine employees. A third party operates the Decker mine for us and the other 50% owner and
markets the steam coal out of the Decker mine. There are two principal seams at West Decker, Dietz 1 and Dietz 2, with typical thicknesses of 51 and 16 feet, respectively, and three seams at East
Decker, Dietz 1 Upper, Dietz 1 Lower and Dietz 2, with typical thicknesses of 27, 17 and 16 feet, respectively. In April 2010, the Decker mine entered into a coal sales contract that will extend
production and mine life into 2013. The operator continues to seek commercial market opportunities for additional leased and permitted coal tonnage at the Decker mine.

Customers and Coal Contracts

We focus on building long-term relationships with customers through our reliable performance and commitment to customer
service. We supply coal to over 47 electric utilities and over 91% of our sales were to customers with an investment grade credit rating as of December 31, 2010. Furthermore, over 72% of our
2010 sales were to customers with whom we have had relationships for more than 10 years.

Sales and Marketing

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



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

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Customers

Our primary customers are domestic utility companies with over 108 plants primarily located in the mid-west and south
central U.S. Our coal supplies fueled approximately 4% of the electricity generated in the U.S. in 2010. During 2010, approximately 49% of our revenues were derived from our top ten customers. No
customer accounted for 10% or more of our revenues in 2010. The following map shows the percentage of our shipped tons of coal by state of destination during 2010 from coal produced at the three mines
we own and operate. We also exported approximately 4% of the tons produced at these mines in 2010.

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. Multiple year contracts usually have specific and possibly different volume and pricing arrangements for each year of the contract. As of
December 31, 2010, approximately 64% of our committed tons were associated with contracts that had three years or more remaining on their term. Most of our supply contracts include a fixed
price for the term of the agreement or a pre-determined escalation in price for each year. Some of our agreements that extend for a four- or five-year term or
longer may include a variable pricing system. These contracts allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales price. For
the year ended December 31, 2010, approximately 97% of our revenues were derived from long-term supply contracts with a term of one year or greater. While most of our sales
contracts are for terms of one to five years, some are as short as one to six months, and other contracts have terms longer than ten years.

Our
coal is primarily sold on a mine-specific basis to utility customers through a request-for-proposal process. The terms of our coal sales
agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer,

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including
base price adjustment features, price re-opener terms, coal quality requirements, quantity parameters, permitted sources of supply, impact of future regulatory changes, extension
options, force majeure, termination, assignment and other provisions.

Our
supply contracts typically contain provisions to adjust the base price due to new statutes, ordinances or regulations that affect our costs related to performance of the agreement.
Additionally, some of our contracts contain provisions that allow for the recovery of costs affected by modifications or changes in the interpretations or application of any applicable statute by
local, state or federal government authorities. These provisions only apply to the base price of coal contained in these supply contracts. In some circumstances, a significant adjustment in base price
can lead to termination of the contract.

Price
re-opener and index provisions, which can be either renegotiated or based on a fixed formula, are present in certain contracts covering future tonnage commitments.
These provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price
based on prevailing market price or, in some instances, require us to negotiate a new price, sometimes between a specified range of prices. In some agreements, if the parties do not agree on a new
price, either party has an option to terminate the contract. Under some of our contracts, we have
the right to match lower prices offered to our customers by other suppliers. In addition, some of our contracts contain clauses that may allow customers to terminate the contract in the event of
certain changes in environmental laws and regulations.

Quality
and volumes for the coal are stipulated in coal sales agreements. In most cases, the annual pricing and volume obligations are fixed, although, in some cases, the volume
specified may vary depending on the quality of the coal. Some customers are allowed to vary the amount of coal taken under the contract. Most of our coal sales agreements contain provisions requiring
us to deliver coal within certain ranges for specific coal characteristics, such as heat content, sulfur, ash and ash fusion temperature. Failure to meet these specifications can result in economic
penalties, suspension or cancellation of shipments or termination of the contracts. Many of our contracts contain clauses that require us and our customers to maintain a certain level of
creditworthiness or provide appropriate credit enhancement upon request. The failure to do so can result in a suspension of shipments under the contract.

Our
coal sales agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers for the duration of specified events beyond
the control of the affected party, including events such as strikes, adverse mining conditions, mine closures or serious transportation problems that affect us or unanticipated plant outages that may
affect the buyer. Our contracts generally provide that in the event a force majeure circumstance exceeds a certain time period (e.g., 60-90 days), the unaffected party may
have the option to terminate the transaction or transactions under the agreement. Some contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer.

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

In
some of our contracts, we have a right of substitution, allowing us to provide coal from different mines, including third-party mines, as long as the replacement coal meets quality
specifications and will be sold at the same delivered cost.

Generally,
under the terms of our coal sales agreements, we agree to indemnify or reimburse our customers for damage to their or their rail carrier's equipment while on our property,
other than from

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their
own negligence, and for damage to our customer's equipment due to non-coal materials being included with our coal before leaving our property.

Broker Sales and Third-Party Sources

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

Our
subsidiary, Spring Creek Coal LLC, was a party to a broker sales contract under which it had agreed to sell purchased coal to a wholesale power generation company. In 1978,
our Spring Creek subsidiary entered into a long-term coal sales contract to underpin the establishment of the Spring Creek mine. When we acquired the Spring Creek mine in 1993, the
contract had been amended to allow the mine to meet its delivery requirements from long-term purchase contracts entered into with two separate mines (one of which was the Jacobs Ranch mine
which we subsequently acquired in 1998 and sold in 2009). Due to the nature of the broker sales contract and the market conditions at the time the respective agreements were all executed, our selling
price for the coal was higher than our purchasing price. Under this contract, we sold approximately 6.8 million tons per year. This broker sales contract contributed $13.7 million of
revenues in 2010. The contract expired following final deliveries under the contract in the first quarter of 2010. See Item 7 "Management's Discussion and Analysis of Financial Condition and
Results of OperationsOverview."

For
delivery during the year ended December 31, 2010, we purchased 1.7 million tons through brokers and third-party sources.

Transportation

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

Suppliers

Principal supplies used in our business include heavy mobile equipment, petroleum-based fuels, explosives, tires, steel and other raw
materials, as well as spare parts and other consumables used in the mining process. We use third-party suppliers for a portion of our equipment rebuilds and repairs, drilling services and
construction. We use sole source suppliers for certain parts of our business such as dragline shovel parts and services and tires. We believe adequate substitute suppliers are available. For further
discussion of our suppliers, see Item 1A "Risk FactorsRisks Related to Our Business and IndustryIncreases in the cost of supplies, or the inability to obtain a
sufficient quantity of those supplies, could increase our operating expenses, disrupt or delay our production and materially and adversely affect our profitability."

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

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Competition

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

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

Employees

As of December 31, 2010, we had 1,524 full-time employees. None of our employees are currently parties to collective
bargaining agreements. We hold a 50% interest in the Decker mine in Montana, which is a union-based operation operated by a third-party mine operator. However, we do not employ any of the Decker mine
employees. We believe that we have good relations with our employees. As of December 31, 2010, we had 250 external contractors, on a full-time equivalent basis.

Executive Officers of the Company

Set forth below is information concerning our current executive officers.

Name

Age

Position(s)Colin Marshall


46

President, Chief Executive Officer and DirectorMichael Barrett


42

Executive Vice President and Chief Financial OfficerGary Rivenes


40

Executive Vice President and Chief Operating OfficerCary Martin


58

Senior Vice President, Human ResourcesTodd Myers


47

Senior Vice President, Business DevelopmentJames Orchard


50

Senior Vice President, Marketing and Government AffairsBryan Pechersky


40

Senior Vice President and General CounselA. Nick Taylor


60

Senior Vice President, Technical ServicesHeath Hill


40

Vice President and Chief Accounting Officer


Colin Marshallhas served as our President, Chief Executive Officer and a director since July 2008. Previously, he served as the President
and Chief Executive Officer of Rio Tinto Energy America Inc. ("RTEA"), an indirect subsidiary of Rio Tinto plc and the former parent company of Cloud Peak Energy Resources LLC,
from June 2006 until November 2009. From March 2004 to May 2006, Mr. Marshall served as General Manager of Rio Tinto's Pilbara Iron's west Pilbara iron ore operations in Tom Price, West
Australia, from June 2001 to March 2004, he served as General Manager of RTEA's Cordero Rojo mine in Wyoming and from August 2000 to June 2001, he served as Operations Manager of RTEA's Cordero Rojo
mine. Mr. Marshall worked for Rio Tinto plc in London as an analyst in the Business Evaluation Department from 1992 to 1996. From 1996 to 2000, he was Finance Director of the Rio Tinto
Pacific Coal business unit based in Brisbane Australia. Mr. Marshall received his

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

Gary Riveneshas 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 Martinhas 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 Myershas 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.

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

Bryan Pecherskyhas served as our Senior Vice President and General Counsel since January 2010. Previously, Mr. Pechersky was
Senior Vice President, General Counsel and Secretary for Harte-Hanks, Inc., a worldwide, direct and targeted marketing company from March 2007 to January 2010. Prior to that, he also served as
Senior Vice President, Secretary and Senior Corporate Counsel for Blockbuster Inc., a global movie and game entertainment retailer from October 2005 to March 2007, and was Deputy General
Counsel and Secretary for Unocal Corporation, an international energy company acquired by Chevron Corporation in 2005, from March 2004 until October 2005. While in these capacities,
Mr. Pechersky's responsibilities included advising corporate clients regarding various legal, regulatory and compliance matters, transactions and other responsibilities that are common for a
general counsel and corporate secretary. Mr. Pechersky was in private practice for approximately seven years with the international law firm Vinson & Elkins LLP before joining
Unocal Corporation. Mr. Pechersky also served as a Law Clerk to the Hon. Loretta A. Preska, Chief Judge of the U.S.
District Court for the Southern District of New York in 1995 and 1996. Mr. Pechersky earned his bachelor's degree and Juris Doctorate from the University of Texas, Austin, Texas.

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

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,

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

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

Mining Permits and Approvals

Numerous governmental permits or approvals are required for mining operations. When we apply for these permits and approvals, we may be
required to prepare and present data to federal, state or local authorities pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment. For
example, in order to obtain a federal coal lease, an EIS must be prepared to assist the BLM in determining the potential environmental impact of lease issuance, including any direct and indirect
effects from the mining, transportation and burning of coal. Recently, particular attention has been focused on the impact of the production and usage of coal on global climate change, which resulted
in extensive comments from environmental groups on the EIS prepared in connection with the West Antelope II LBA, and subsequent legal challenges were filed in 2010 against the BLM and the Secretary of
the Interior with respect to this LBA, which we have nominated. This may result in further delays or an inability to obtain this lease. Future nominations or lease applications may also be subject to
delays or challenges, which may result in difficulties in obtaining other leases. The authorization, permitting and implementation requirements imposed by federal, state and local authorities may be
costly and time consuming and may limit or delay commencement or continuation of mining operations. In the states where we operate, the applicable laws and regulations also provide that a mining
permit or modification can be delayed, refused or revoked if officers, directors, shareholders with specified interests or certain other affiliated entities with specified interests in the applicant
or permittee have, or are affiliated with another entity that has, outstanding permit violations. Thus, past or ongoing violations of applicable laws and regulations by these interested persons and
entities could provide a basis to revoke our existing permits and to deny the issuance of additional permits.

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

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

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Surface Mining Control and Reclamation Act

SMCRA establishes mining, environmental protection, reclamation and closure standards for all aspects of surface coal mining. Mining
operators must obtain SMCRA permits and permit renewals from the OSM or from the applicable state agency if the state agency has obtained regulatory primacy. A state agency may achieve primacy if the
state regulatory agency develops a mining regulatory program that is no less stringent than the federal mining regulatory program under SMCRA. Both Wyoming and Montana, where our mines are located,
have achieved primacy to administer the SMCRA program.

SMCRA
permit provisions include a complex set of requirements, which include, among other things, coal prospecting, mine plan development, topsoil or growth medium removal and
replacement, selective handling of overburden materials, mine pit backfilling and grading, disposal of excess spoil, protection of the hydrologic balance, surface runoff and drainage control,
establishment of suitable post mining land uses and re-vegetation. We begin the process of preparing a mining permit application by collecting baseline data to adequately characterize the
pre-mining environmental conditions of the permit area. This work is typically conducted by third-party consultants with specialized expertise and typically includes surveys and/or
assessments of the following: cultural and historical resources; geology; soils; vegetation; aquatic organisms; wildlife; potential for threatened, endangered or other special status species; surface
and ground water hydrology; climatology; riverine
and riparian habitat and wetlands. The geologic data and information derived from the surveys and/or assessments are used to develop the mining and reclamation plans presented in the permit
application. The mining and reclamation plans address the provisions and performance standards of the state's equivalent SMCRA regulatory program, and are also used to support applications for other
authorizations and/or permits required to conduct coal mining activities. Also included in the SMCRA permit application is information used for documenting surface and mineral ownership, variance
requests, access roads, bonding information, mining methods, mining phases, other agreements that may relate to coal, other minerals, oil and gas rights, water rights, permitted areas and ownership
and control information required to determine compliance with OSM's Applicant Violator System, including the mining and compliance history of officers, directors and principal owners of the entity.

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

In
addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund, which was created by SMCRA, imposes a fee on all coal produced. The proceeds of the
fee are used to restore mines closed or abandoned prior to SMCRA's adoption in 1977. The current fee is $0.315 per ton of coal produced from surface mines. In 2010, we recorded $29.1 million of
expense related to these reclamation fees for our three owned and operated mines.

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Surety Bonds

State laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of
surety bonds or other approved forms of security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. Prior to the IPO, Rio Tinto served as guarantor
of our surety bonds, and our letters of credit were issued under Rio Tinto's pre-existing credit facilities. We have obtained new
surety bonds, letters of credit or other credit arrangements and have obtained the full release of Rio Tinto and its affiliates with respect to any existing surety bonds, letters of credit and other
guarantees or credit arrangements and such instruments have been accepted as replacements by the appropriate agencies.

As
of December 31, 2010, there were approximately $525.0 million in surety bonds outstanding to secure the performance of our reclamation obligations (including our
obligations with respect to the Decker mine). In addition, we have a letter of credit for $10.5 million that we use to secure our 50% share of additional reclamation obligations at the Decker
mine. At December 31, 2010, we had $182.1 million of restricted cash used as collateral for our surety bonds.

Mine Safety and Health

Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The
Federal Mine Safety and Health Act of 1977 (the "Mine Act"), significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining
operations. In addition to federal regulatory programs, all of the states in which we operate also have state programs for mine safety and health regulation and enforcement. Collectively, federal and
state safety and health regulation in the coal mining industry is among the most comprehensive and pervasive systems for protection of employee health and safety affecting any segment of U.S.
industry. The Mine Act is a strict liability statute that requires mandatory inspections of surface and underground coal mines and requires the issuance of enforcement action when it is believed that
a standard has been violated. A penalty is required to be imposed for each cited violation. Negligence and gravity assessments result in a cumulative enforcement scheme that may result in the issuance
of withdrawal orders. The Mine Act contains criminal liability provisions. For example, it imposes criminal liability for corporate operators who knowingly or willfully authorize, order or carry out
violations. The Mine Act also provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly authorize, order or carry out violations. In
addition, criminal liability may be imposed against any person for knowingly falsifying records required to be kept under the Mine Act and standards. Recent underground mine accidents have resulted
in, and may continue to result in, state and federal legislatures and regulatory authorities increasing scrutiny of mine safety matters and passing more stringent laws governing mining. For example,
in 2006, Congress enacted the Mine Improvement and New Emergency Response Act, which imposed additional burdens on coal operators, including, among other matters, (i) obligations related to
(a) the development of new emergency response plans that address post-accident communications, tracking of miners, breathable air, lifelines, training and communication with local
emergency response personnel; (b) establishing additional requirements for mine rescue teams; and (c) promptly notifying federal authorities of incidents that pose a reasonable risk of
death and (ii) increased penalties for violations of the applicable federal laws and regulations. The penalty regulations promulgated in 2007 as a result of this legislation included new
heightened penalty categories for certain types of violations and have resulted in imposition of penalty assessment amounts that doubled between fiscal year 2007 and 2008 in the coal industry and are
expected to continue to increase. In the wake of the 2006 legislation, enforcement scrutiny also increased, including more inspection hours at mine sites, increased numbers of inspections and
increased issuance of the number and the severity of enforcement actions. Various states also have enacted their own new laws and regulations addressing many of these

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same
subjects. Our compliance with these or any new mine health and safety regulations could increase our mining costs.

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

Under
the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must pay federal black lung benefits to
claimants who are current and former employees and also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to
January 1, 1970. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to
exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the U.S. In 2010, we recorded $42.6 million of expense related to this excise tax for our three owned
and operated mines.

Clean Air Act

The federal Clean Air Act and comparable state laws that regulate air emissions affect coal mining operations both directly and
indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emission control requirements relating to air pollutants, including particulate
matter, which may include controlling fugitive dust. The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen
oxides, mercury and other compounds emitted by coal-fired power plants. In recent years, Congress has considered legislation that would require increased reductions in emissions of sulfur
dioxide, nitrogen oxide and mercury. In addition to the greenhouse gas issues discussed below, the air emissions programs that may affect our operations, directly or indirectly, include, but are not
limited to, the following:





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Global Climate Change

One by-product of burning coal is carbon dioxide, which is considered a greenhouse gas and is a major source of public
concern, recent regulatory initiatives and litigation with respect to global climate change and global warming. In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate
Change (the "Kyoto Protocol"), which establishes a binding set of emission targets for greenhouse gases, became binding on all those countries that had ratified it. To date, the U.S. has refused to
ratify the Kyoto Protocol, which expires in 2012. Emission targets under the Kyoto Protocol vary from country to country. If the U.S. were to ratify the Kyoto Protocol, the U.S. would be required to
reduce greenhouse gas emissions to 93% of 1990 levels from 2008 to 2012. International discussions are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in
2012, with an initial goal of reaching a consensus on a replacement treaty at the milestone meeting in Copenhagen, Denmark in December 2009. The Copenhagen meeting did not result in a new treaty, but
did result in an "agreement in principle," which would entail the U.S. reducing CO2 emissions on a

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voluntary
basis by at least 17% by 2020, and greater percentages in succeeding years. Any replacement treaty or other international arrangement requiring additional reductions in greenhouse gas
emissions could have a negative global impact on the demand for coal.

Future
regulation of greenhouse gas emissions in the U.S. could occur pursuant to future U.S. treaty commitments, new domestic legislation that may impose a carbon emissions tax or
establish a cap-and-trade program or regulation by the EPA. Passage of comprehensive global climate change and energy legislation could impact the demand for coal. Any
reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely
affecting our business and results of operations.

Even
in the absence of new federal legislation, greenhouse gas emissions may be subject to regulation by the EPA pursuant to the Clean Air Act. In response to the 2007 U.S. Supreme Court
rulingMassachusetts v. EPA, the EPA has taken several steps towards promulgating and implementing regulations regarding the emission of greenhouse
gases. On December 7, 2009, the EPA issued a final finding that the presence of carbon dioxide and certain other greenhouse gases in the atmosphere endangers public health and welfare. This
finding was a prerequisite to EPA regulation of greenhouse gas emissions from motor vehicles under the Clean Air Act. As a result of this finding, EPA has promulgated further regulations subjecting
greenhouse gas emissions from stationary sources that exceed certain emission thresholds (these emission thresholds would cover power plants as well as other large industrial sources) will also become
subject to various requirements, including certain air permitting requirements, under the Clean Air Act beginning on January 2, 2011. These requirements would include the mandatory use of best
available control technology for greenhouse gas emissions whenever the construction or modification of a facility would increase greenhouse gas emissions by 75,000 tons per year or more as well as
other burdensome and time-consuming permitting requirements. As a result of these regulations, our customers may reduce the amount of coal they purchase from us. Moreover, in September
2009, the EPA promulgated a rule requiring certain emitters of greenhouse gases, including coal-fired power plants, to monitor and report their greenhouse gas emissions to the EPA.

Many
states and regions have adopted greenhouse gas initiatives and certain governmental bodies, including the State of California, have or are considering the imposition of fees or
taxes based on the emission of greenhouse gases by certain facilities. Ten northeastern states (Connecticut, Delaware, Maine, Massachusetts, Maryland, New Hampshire, New Jersey, New York, Rhode Island
and Vermont) have formed the Regional Greenhouse Gas Initiative ("RGGI"), the only operating cap-and-trade system in the United States. RGGI is aimed at reducing carbon dioxide
emissions from power plants in the participating states. The RGGI program calls for signatory states to stabilize carbon dioxide emissions at 2005 levels from 2009 to 2015, followed by a 2.5%
reduction each year from 2015 through 2018. Since its inception, several additional northeastern states and Canadian provinces have joined as observers. RGGI has begun holding quarterly carbon dioxide
allowance auctions for its initial three-year compliance period from January 1, 2009, to December 31, 2011 to allow utilities to buy allowances to cover their carbon dioxide
emissions.

Global
climate change initiatives are also being considered or enacted in some western states. In September 2006, California enacted the Global Warming Solutions Act of 2006, which
establishes a statewide greenhouse gas emissions cap of 1990 levels by 2020 and sets a framework for further reductions after 2020. In September 2006, California also adopted greenhouse gas
legislation that prohibits long-term baseload generators from having a greenhouse gas emissions rate greater than that of combined cycle natural gas generator. In February 2007, the
governors of Arizona, California, New Mexico, Oregon and Washington launched the Western Climate Initiative in an effort to develop a regional strategy for addressing global climate change. The goal
of the Western Climate Initiative is to identify, evaluate and implement collective and cooperative methods of reducing greenhouse gases in the region to 15% below 2005 levels by 2020. Since its
initial launching, a number of additional western

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states
and provinces have joined the initiative, or have agreed to participate as observers, including Montana, which has joined the initiative and Wyoming, which has signed on as an observer. The
Western Climate Initiative envisions an economy-wide cap-and-trade program that would include fossil fuels (such as coal) production and processing. Thus, our coal
mines could incur additional direct costs if new laws are passed in Montana and Wyoming in accordance with the Western Climate Initiative.

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

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

Additionally,
two U.S. federal appeals courts (5th and 2nd Circuits) have reinstated lawsuits permitting individuals, state attorneys general
and others to pursue claims against major utility, coal, oil and chemical companies on the basis that those companies have created a public nuisance due to their emissions of carbon dioxide, including
increasing the adverse effects of Hurricane Katrina. One of these appeals court decisions was subsequently vacated, without being decided on the merits, when a request to rehear the case en banc was
granted but the court rehearing the case failed to establish a quorum. The 2nd Circuit case is now pending before the U.S. Supreme Court.

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

Even
in the absence of comprehensive federal or state legislation on greenhouse gas emissions, global climate change and greenhouse gas emissions have increasingly become issues that
must be addressed in connection with the preparation of EISs necessary to obtain additional federal coal leases. For example, we received extensive comments from several environmental groups
pertaining to the extent of global climate change discussion that should be included within the EIS document for the

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federal
coal lease application for the West Antelope II LBA, which we have nominated. This LBA is also the subject of pending legal challenges filed in 2010 against the BLM and the Secretary of the
Interior by environmental organizations. It is possible that in the future we may be unable to obtain future coal leases on a timely basis, or at all, which could have an adverse impact on our
business.

Clean Water Act

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

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





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Resource Conservation and Recovery Act

The EPA determined that coal combustion wastes do not warrant regulation as hazardous wastes under the Resource Conservation and
Recovery Act ("RCRA") in May 2000. Most state hazardous waste laws also regulate coal combustion wastes as non-hazardous wastes. The EPA also concluded that beneficial uses of coal
combustion wastes, other than for mine-filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that
national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface
impoundments or landfills or used as mine-fill. There have been several legislative proposals that would require the EPA to further regulate the storage of coal combustion waste. Any
significant changes in the management of coal combustion waste could increase our customers' operating costs and potentially reduce their ability to purchase coal. In addition, in June 2010 the EPA
released two competing proposals for the regulation of coal combustion byproducts. One would regulate the byproducts as hazardous or special waste and the other would classify the byproducts as non
hazardous waste. A further revised draft is expected to be published late in 2011. If coal combustion wastes were classified as a special or hazardous waste, regulations may impose restrictions on ash
disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers' operating costs and potentially
reduce their ability to purchase coal. In addition, contamination caused by the past disposal of coal combustion waste, including coal ash, can lead to material liability to our customers under RCRA
or other federal or state laws and potentially reduce the demand for coal.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and similar state laws affect coal mining
operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances into the environment. Under CERCLA and similar state laws, joint and several
liability may be imposed on hazardous substance generators, site owners, transporters, lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA
currently excludes most wastes generated by coal mining and processing operations from the primary hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for
the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could trigger the liability provisions of CERCLA or
similar state laws. Thus, we may be subject to liability under CERCLA and similar state laws for coal mines that we currently own, lease or operate or that we or our predecessors have previously
owned, leased or operated, and sites to which we or our predecessors sent hazardous substances. We may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination
and natural resource damages at sites where we control surface rights.

Endangered Species Act

The federal Endangered Species Act (the "ESA") and counterpart state legislation protect species threatened with possible extinction.
The U.S. Fish and Wildlife Service (the "USFWS") works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected

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from
mining-related impacts. A number of species indigenous to the areas in which we operate are protected under the ESA, and compliance with ESA requirements could have the effect of prohibiting or
delaying us from obtaining mining permits. These requirements may also include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the
affected species or their habitats. For example, our Spring Creek coal mine applied for lease modification under the BLM leasing regulations, and the area we were proposing to include was declared
critical greater sage-grouse habitat by the Montana Fish, Wildlife and Parks Department. This requires a certain degree of mitigation of the impacts on the habitat in order for us to
obtain approval of this lease modification. Similarly, in Wyoming, the Buffalo Field Office of the BLM is engaged in revising its Resource Management Plan ("RMP") to include additional sage grouse
protective measures in its RMP. Once adopted, this plan may impose limitations on future development and/or further mitigation measures within sage grouse habitat on lands administered by the Buffalo
Field Office, including the PRB. Should more stringent protective measures be applied, or if the USFWS lists the sage grouse as threatened or endangered, this could result in increased operating
costs, heightened difficulty in obtaining future mining permits, or the need to implement additional mitigation measures. The USFWS published the result of its 12-month status review on
March 5, 2010, determining that a listing is warranted but precluded by higher priority listing actions. This finding imposes no legal obligation to protect the bird. Three environmental groups
have filed a lawsuit against USFWS challenging its failure to provide ESA protection to the sage grouse. On June 29, 2010, the USFWS issued a notice reinstating the proposed rule for relating
to the listing of the mountain plover as threatened under the ESA and requesting public comment. If finalized by May 2011, the threatened species listing could lead to new land use restrictions to
protect nesting plovers in Wyoming and Montana. We have not determined its impact on our operations, if any.

Use of Explosives

Our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we
incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to regulatory requirements. For
example, pursuant to a rule issued by the Department of Homeland Security in 2007, facilities in possession of chemicals of interest (including ammonium nitrate at certain threshold levels) are
required to complete a screening review in
order to help determine whether there is a high level of security risk, such that a security vulnerability assessment and a site security plan will be required. It is possible that our use of
explosives in connection with blasting operations may subject us to the Department of Homeland Security's new chemical facility security regulatory program.

Other Environmental Laws

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

Available Information

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

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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.

Item 1A.Risk Factors.

You should carefully consider the risk factors described below and other information contained in this Form 10-K. If
any of the following risk factors, as well as other risks and uncertainties that are not currently known to us or that we currently believe are not material, actually occur, our business, financial
condition and results of operations could be materially and adversely affected.

Risks Related to Our Business and Industry

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

Our revenues, results of operations and the value of our coal reserves are dependent in large measure upon the prices we receive for
our coal. Because coal is a commodity, the prices we receive are set by the marketplace. Prices for coal generally tend to be cyclical, and over the last several years have become more volatile. The
contract prices we may receive in the future for coal depend upon numerous factors, including:



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

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

We compete with numerous other coal producers in various regions of the U.S. for domestic sales. International demand for U.S. coal
also affects competition within our industry. The demand for U.S. coal exports depends upon a number of factors, including the overall demand for electricity in foreign markets; currency exchange
rates; ocean freight rates; weather disruption; port and shipping capacity; the demand for foreign-produced steel, both in foreign markets and in the U.S. market; general economic conditions in
foreign countries; technological developments; and environmental and other governmental regulations. Foreign demand for U.S. coal has increased and decreased over the last decade because of these
factors. Decline in foreign demand for U.S. coal could cause competition among coal producers for sales in the U.S. to intensify, potentially resulting in significant additional downward pressure on
domestic coal prices, including in the PRB.

In
addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas and crude oil. A decline in price for natural gas could cause
demand for coal to decrease and adversely affect the price of our coal. For example, the average price for natural gas declined from $4.44 per thousand cubic feet as of December 2009 to $4.15 per
thousand cubic feet as of December 2010, leading to, in some instances, decreased coal consumption by electricity-generating utilities. If alternative energy sources, such as hydroelectric, wind or
solar, become more cost-competitive on an overall basis, demand for coal could decrease and the price of coal could be materially and adversely affected, including in the PRB. Further,
legislation requiring the use and dispatch of these alternative energy sources and fuels or legislation providing financing or incentives to encourage continuing technological advances and deployment
in this area could further enable alternative energy sources to become more competitive with coal.

Global or U.S. economic and market conditions may have a material adverse affect on our business, financial condition and results of operations.

The recent global economic downturn, particularly with respect to the U.S. economy, coupled with the global financial and credit market
disruptions, had an adverse impact on the coal industry generally including our company. For example, the demand for electricity in our target markets decreased during 2009, which led to a decrease in
coal consumption by customers. As a result, stockpiles of coal by our customers increased during this time leading to our customers curtailing future orders. In 2009, we also experienced a greater
than normal number of customers seeking to reduce the amount of tons taken under existing contracts through contractual remedies, such as force majeure provisions. We cannot predict the timing of such
economic disruptions or their long-term impact on domestic and international economies or the magnitude and pace of any recovery. Any actions we may take in response to such economic
conditions may be insufficient. A return to the global recession or a recession in the U.S. economy, or further disruptions in the financial and credit markets could have a material adverse effect on
our business, financial condition and results of operations. Furthermore, because we typically seek to enter into long-term arrangements for the sale of a substantial portion of our coal,
the average sales price we receive for our coal may lag behind any general economic recovery in the U.S.

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

Mining companies must obtain a number of permits and licenses that impose strict regulations on various environmental and operational
matters in connection with coal mining. These include permits and licenses issued by various federal, state and local agencies and regulatory bodies. The permitting rules, and the interpretations of
these rules, are complex, change frequently and are often subject to discretionary interpretations by the regulators, all of which may make compliance more difficult or impractical, and may possibly
preclude the continuance of ongoing operations or the development of future mining operations. The public, including non-governmental organizations, anti-mining groups and
individuals, have certain statutory rights to comment upon and submit objections to requested permits and environmental impact statements (each an "EIS") prepared in connection with applicable
regulatory processes, and otherwise engage in the permitting and licensing process, including bringing citizens' lawsuits to challenge the issuance of permits, the validity of EIS or performance of
mining activities. For example, the EIS and other regulatory matters associated with the West Antelope II LBA are being legally challenged by several non-governmental organizations, which
could create a delay or uncertainty in acquiring the coal lease. If this or any other permits, licenses or leases are not issued or renewed in a timely fashion or at all, or if permits or leases
issued or renewed are conditioned in a manner that restricts our ability to efficiently and economically conduct our mining activities, we could suffer a material reduction in our production, and our
cash flow or profitability could be materially and adversely affected.

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

The U.S. federal government owns most of the coal in the vicinity of our mines. Accordingly, the LBA process is the most significant
means of acquiring additional reserves. There is no requirement that the federal government lease coal subject to an LBA, lease its coal at all or give preference to any LBA applicant, and our bids
may compete with other coal producers' bids in the PRB. In the current coal pricing environment, LBAs are becoming increasingly more competitive and expensive to obtain, and the review process to
submit an LBA for bid continues to lengthen. We expect that this trend may continue. The increasing size of potential LBA tracts may make it easier for new mining operators to enter the market on
economical terms and may, therefore, increase competition for LBAs. Increased opposition from non-governmental organizations and other third parties may also lengthen, delay or complicate
the LBA process. For example, the West Antelope II LBA is subject to pending legal challenges filed in 2010 against the BLM and the Secretary of the Interior by environmental organizations. In order
to win a lease in the LBA process and acquire additional coal, our bid for a coal tract must meet or exceed the fair market value of the coal based on the internal estimates of the BLM, which they do
not publish. We have maintained a history of timely payments related to our LBAs. If we are unable to maintain our "good payer" status, we would be required to seek bonding for any remaining payments.

The
LBA process also requires us to acquire rights to mine from surface owners overlying the coal, and these rights are becoming increasingly more difficult and costly to acquire.
Certain federal regulations provide a specific class of surface owners, also known as qualified surface owners (each, a "QSO"), with the ability to prohibit the BLM from leasing its coal. For example,
in connection with a pending LBA that we nominated for our Cordero Rojo mine, the BLM has indicated that certain surface owners satisfy the regulatory definition of QSO. If a QSO owns the land
overlying a coal tract, federal laws prohibit us from leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO. This right of QSOs allows
them to exercise significant influence over negotiations to acquire surface rights and can delay the LBA process or ultimately

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prevent
the acquisition of an LBA. If we are unable to successfully negotiate access rights with QSOs at a price and on terms acceptable to us, we may be unable to acquire LBAs for coal on land owned
by the QSO. If the prices to acquire land owned by QSOs increase, it could materially and adversely affect our profitability.

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

During the mid-1970s and early 1980s, increased demand for coal attracted new investors to the coal industry in the PRB,
spurred the development of new mines and resulted in additional production capacity throughout the industry, all of which led to increased competition and lower coal prices. Increases in coal prices
during recent periods encouraged the development of expanded capacity by coal producers. Some of these planned capacity increases and existing production plans were delayed or reduced due to coal
price reductions since mid-2008 and the concurrent global economic downturn. However, these capacity increases may be restarted. Any overcapacity and increased production in the future
could materially reduce coal prices and, therefore, materially reduce our revenues and profitability.

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

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



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These
changes, conditions and events may materially increase our cost of mining and delay or halt production at particular mines either permanently or for varying lengths of time, which
could have a material adverse effect on our results of operations.

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

Our coal customers primarily use our coal as fuel for domestic electricity generation. Overall economic activity and the associated
demands for power by industrial users can have significant effects on overall electricity demand. An economic slowdown can significantly slow the growth of electricity demand and could result in
contraction of demand for coal. Weather patterns can also greatly affect electricity demand. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increased generating
requirements from all sources. Mild temperatures, on the other hand, result in lower electrical demand, which allows generators to choose the sources of power generation when deciding which generation
sources to dispatch. Any downward pressure on coal prices, due to decreases in overall demand or otherwise, including changes in weather patterns, would materially and adversely affect our results of
operations.

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

In 2010, we sold approximately 96% of our coal to domestic electric power generators. Domestic electric power generation accounted for
approximately 93% of all U.S. coal consumption from October 2009 through September 2010, according to the U.S. Energy Information Administration (the "EIA"). The amount of coal consumed for U.S.
electric power generation is affected by, among other things:



Gas-fired
generation has the potential to displace coal-fired generation, particularly from older, less efficient coal-powered generators. We expect
that many of the new power plants needed to meet increasing demand for domestic electricity generation will be fired by natural gas, because gas-fired plants are cheaper to construct, and
permits to construct these plants are easier to obtain as natural gas is seen as having a lower environmental impact than coal-fired generators. In recent periods, governmental regulators
at the federal, state and local levels have shown increased interest in limiting greenhouse gas ("GHG") emissions. This has resulted in increased regulation of coal mining and of
coal-fired power plants and other end-users of coal, increasing the cost of burning coal compared to alternative energy sources. In addition, environmental activists concerned
with climate change issues have attempted to use the regulatory and judicial processes to block the construction of new coal-fired

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power
plants or capacity expansions to existing plants. Further, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our
coal. Many states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to
establish a similar uniform, national standard. Although none of these federal proposals have been enacted to date, the current Administration has indicated its support for a federal renewable energy
standard as part of energy and climate change legislative initiatives. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could
make these sources more competitive with coal. Any reduction in the amount of coal consumed by U.S. electric power generators could reduce the price of coal that we mine and sell, thereby reducing our
revenues and materially and adversely affecting our business and results of operations.

New and potential future regulatory requirements and public concerns relating to GHG emissions could affect our customers and could reduce the demand for coal as a fuel
source and cause coal prices and sales of our coal to materially decline.

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

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



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The permitting of new coal-fired power plants has also recently been contested, at times successfully, by state regulators and environmental
organizations due to concerns related to GHG emissions from the new plants. Additionally, at least one U.S. federal appeals court reinstated a lawsuit permitting individuals, state attorneys general
and others to pursue claims against industrial companies on the basis that they have created a public nuisance due to their emissions of carbon dioxide and its alleged effects on climate
(e.g. sea level and storm severity).

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

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

Our business plan and strategy are dependent upon our acquisitions of additional reserves, which require substantial capital
expenditures to acquire additional coal leases. We also require capital for, among other purposes, acquisition of surface rights, equipment and the development of our mining operations, capital
renovations, maintenance and expansions of plants and equipment and compliance with environmental laws and regulations. To the extent that cash on hand, cash generated internally and cash available
under our credit facility are not sufficient to fund capital requirements, we will require additional debt and/or equity financing. However, additional debt or equity financing may not be available to
us or, if available, may not be available on satisfactory terms. Additionally, our debt instruments may restrict our ability to obtain such financing. If we are unable to obtain additional capital, we
may not be able to maintain or increase our existing production rates and we could be forced to reduce or delay capital expenditures or change our business strategy, sell assets or restructure or
refinance our indebtedness, all of which could have a material adverse effect on our business or financial condition.

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

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

Our
ability to obtain additional coal reserves in the future could also be limited by the availability of cash we generate from our operations or available financing, restrictions under
our debt instruments, competition from other coal companies for properties, the lack of suitable acquisition or LBA opportunities, the delay in the federal leasing process caused by third-party legal
challenges or the inability to acquire coal properties or LBAs on commercially reasonable terms. In addition, we may not be able to mine future reserves as profitably as we do at our current
operations. Furthermore, the price we receive for our coal impacts the economic recoverability of our existing coal. Our ability to develop economically recoverable reserves will be materially
adversely impacted if prices for coal sold decrease significantly.

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

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

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

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

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

The operations of our customers are subject to extensive environmental regulation particularly with respect to air emissions. For
example, the federal Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the
air from electric power plants, which are the largest end-users of our coal. A series of more stringent requirements relating to particulate matter, ozone, haze, mercury, sulfur dioxide,
nitrogen oxide and other air pollutants recently has been adopted and/or is expected to be proposed or become effective in the near future. In addition, federal and state mandates and incentives
designed to encourage energy efficiency and the use of alternative energy sources have been proposed and implemented in recent years. Concerted conservation efforts that result in reduced electricity
consumption could cause coal prices and sales of our coal to materially decline.

Considerable
uncertainty is associated with these air emissions initiatives. New regulations are in the process of being developed, and many existing and potential regulatory initiatives
are subject to review by federal or state agencies or the courts. Stringent air emissions limitations are either in place or are likely to be imposed in the short to medium term, and these limitations
will likely require significant emissions control expenditures for many coal-fired power plants. As a result, these power plants may switch to other fuels that generate fewer of these
emissions or may install more effective pollution control equipment that reduces the need for low-sulfur coal, possibly reducing future demand for coal and resulting in a reduced need to
construct new coal-fired power plants. Any switching of fuel

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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.

Our
customers are also subject to other existing and potential environmental regulations, such as EPA's publication in June 2010 of proposed regulations for the management and disposal
of coal combustion by-products. While we are unable to determine the likely ultimate regulatory requirements, any significant changes in the management of coal combustion
by-products could require our customers to comply with more stringent storage and disposal requirements, which in turn could increase their costs and reduce the demand for our coal.

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

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



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

New
legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the
protection of the environment that would further regulate and tax the coal industry, may also require us to change

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operations
significantly or incur increased costs. Such changes could have a material adverse effect on our financial condition and results of operations.

Our management team has limited experience managing our business as a stand-alone public company, and if they are unable to manage our business as a stand-alone public
company, our business may be harmed.

We have historically operated as part of Rio Tinto. The majority of our management team has limited experience managing a business on a
stand-alone basis or as a public company. If we are unable to manage and operate our company as a stand-alone public company, our business and results of operations will be adversely affected.

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

As a public company, we incur significant legal, accounting and other expenses that we did not incur as a subsidiary of Rio Tinto. In
addition, we are subject to a number of additional requirements, including the reporting requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the Sarbanes-Oxley Act of
2002 (the "Sarbanes-Oxley Act") and the listing standards of New York Stock Exchange. These requirements have caused us to incur increased costs and placed increased 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 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 will be 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.

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

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

In
preparation for the filing of our 2009 Form 10-K, management performed an evaluation of the effectiveness of the design and operation of our disclosure controls and
procedures as of December 31, 2009, and concluded that the previously identified material weaknesses were not yet remediated.

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

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

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

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

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

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

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

We pay federal, state and private royalties and federal, state and county production taxes on the coal we produce. A substantial
portion of our royalties and production taxes are levied as a percentage of gross revenues with the remaining levied on a per ton basis. For example, we pay production royalties of 12.5% of gross
proceeds to the federal government. We incurred royalties and severance and production taxes which represented 30.5% and 29.1% of proceeds from the coal we produced for the years ended
December 31, 2010 and 2009, respectively. If royalties or severance and production tax rates were to significantly increase or if we are required to make additional payments as a result of
governmental audits, our results of operations could be materially and adversely affected.

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

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

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

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

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

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

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

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

Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. We base
our estimates of reserves on engineering, economic and geological data assembled and analyzed by our internal geologists and engineers. Our estimates of proven and probable coal reserves as to both
quantity and quality are updated annually to reflect the production of coal from the reserves, updated geological models and mining recovery data, the tonnage contained in new lease areas acquired and
estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, any one of which
may vary considerably from actual results. These factors and assumptions include:



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

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

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

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

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

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

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

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

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

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

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

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

Federal or state regulatory agencies have the authority under certain circumstances following significant health and safety incidents,
such as fatalities, to order a mine to be temporarily or permanently closed. If this occurred, we may be required to incur capital expenditures to re-open the mine. In the event that these
agencies order the closing of our mines, our coal sales contracts may permit us to issue force majeure notices, which suspend our obligations to deliver coal under these contracts. However, our
customers may challenge our issuances of force majeure notices. If these

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challenges
are successful, we may have to purchase coal from third-party sources, if it is available, to fulfill these obligations, incur capital expenditures to re-open the mines and/or
negotiate
settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery or terminate customers' contracts. Any of these actions could
have a material adverse effect on our business and results of operations.

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

Our customers' demand for our low-sulfur coal, and the prices that we can obtain for it, are affected by, among other
things, the price of sulfur dioxide emission allowances. The Clean Air Act places limits on the amounts of sulfur dioxide that can be emitted by an electric power plant, among other sources, in any
given year. If a plant exceeds its allowable limits, it must purchase allowances, which are tradable in the open market. Regulatory uncertainty following the action by the U.S. Court of Appeals for
the District of Columbia Circuit to vacate the Clean Air Interstate Rule ("CAIR") in July 2008, and its subsequent temporary reinstatement, which established a cap-and-trade
program for sulfur dioxide and nitrogen oxide emissions from power plants in certain states, caused a significant decrease in the price of sulfur dioxide allowances from 2008 to date, and delayed the
installation of technology to reduce emissions at some power plants. Low prices of these emissions allowances could make our low-sulfur coal less attractive to our customers for the
near-term. In July 2010, the EPA proposed the Clean Air Transport Rule ("CATR") as a replacement for CAIR. If promulgated, CATR would phase in requirements for sources of sulfur dioxide
and nitrogen oxide beginning in 2012; subject sources would include power plants. Under CATR, the EPA has proposed state-specific emissions and allocation budgets and intrastate
cap-and-trade mechanisms for allocations, with very limited to no interstate trading provisions in the EPA options under consideration. The effects which these intrastate and
interstate provisions will have on CATR allowance markets remain uncertain. For select states, the emissions budgets will be further reduced in 2014. Coincident with these proposed changes is the
finalization of revised National Ambient Air Quality Standards ("NAAQS") for nitrogen dioxide and sulfur dioxide that occurred in January 2010 and June 2010, respectively. More widespread installation
by electric utilities of technology that reduces sulfur emissions could be accelerated to meet the requirements of the revised NAAQS and/or requirements from the finalization of CATR and may make high
sulfur coal more competitive with our low-sulfur coal. This competition could materially and adversely affect our business and results of operations. Alternatively, compliance with the
revised NAAQS and/or the finalization of CATR could entail utilization of controls in combination with low-sulfur coal. In the CATR proposal, the EPA has projected that to meet the
proposed CATR requirements, utilities would need to install 11 GWs of new sulfur dioxide scrubbers in addition to those controls already planned or in place. The EPA recently published a notice of
data availability and stated that the new data might impact the agency's assessment of which states contribute to pollution problems in downwind states, which in turn might lead to pressure to expand
the number of states subject to the CATR. If additional states are obligated to comply with CATR, it may adversely affect the demand for our coal.

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

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

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

Transportation costs, particularly rail transportation costs, represent a significant portion of the total cost of coal for our
customers, and the cost of transportation is a key factor in a customer's purchasing decision. Increases in transportation costs or the lack of sufficient rail capacity or availability could make coal
a less competitive source of energy or could make the coal produced by us less competitive than coal produced from other regions, either of which could lead to reduced coal sales and/or reduced prices
we receive for the coal.

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

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

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

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

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

We have historically sold most of our coal under long-term coal sales agreements, which we generally define as contracts
with a term of one to five years. The remaining amount not subject to long-term coal sales agreements is sold as spot sales in term allotments of less than twelve months. For the year
ended December 31, 2010 approximately 97% of our revenues were derived from coal sales that were made under long-term coal sales agreements. The prices for coal sold under these
agreements are typically fixed for an agreed amount of time. Pricing in some of these contracts is subject to certain adjustments in later years or under certain circumstances, and may be below the
current market price for similar type coal at any given
time, depending on the time frame of the contract. As a consequence of the substantial volume of our forward sales, we have less coal available to sell under short-term contracts in order
to immediately capitalize on higher coal prices, if and when they arise. At times, spot market prices have fallen below the prices established in many of our long-term coal sales
agreements, and we have realized prices for our coal that are higher than the prices we would receive from sales in the spot market. However, to the extent spot market prices increase and become
higher than the prices established in our long-term coal sales agreements, our ability to realize those higher prices may be restricted when customers elect to purchase additional volumes
allowable under some contracts at contract prices that are lower than spot prices.

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

Although we currently sell the majority of our coal under long-term coal sales agreements, as electric utilities customers
continue to adjust to increased price volatility, increased fungibility of coal products, frequently changing regulations and the increasing deregulation of their industry, some customers are becoming
less willing to enter into long-term coal sales contracts. In addition, the prices for coal in the spot market have decreased at times and may be lower than the prices previously set under
many of our long-term coal sales agreements. As our contracts with customers expire or are otherwise renegotiated, our customers may be less willing to extend or enter into new
long-term coal sales agreements under their existing or similar pricing terms or our customers may decide to purchase fewer tons of coal than in the past.

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

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

All of our mines are surface mining operations. The Surface Mining Control and Reclamation Act ("SMCRA") and counterpart state laws and
regulations establish operational, reclamation and closure standards for all aspects of surface mining. We estimate our total reclamation and mine-closing liabilities based on permit
requirements, engineering studies and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers,
and by government regulators. At the Decker mine, the reclamation liability is estimated by the third-party operator. The estimated liability can change significantly if actual costs vary from our
original assumptions or if governmental regulations change significantly. U.S. GAAP requires that asset retirement obligations be recorded as a liability based on fair value,

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which
reflects the present value of the estimated future cash flows. In estimating future cash flows, we consider the estimated current cost of reclamation and apply inflation rates and a third-party
profit, as necessary. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on behalf of us. The resulting estimated reclamation and
mine closure obligations could change significantly if actual amounts or the timing of those expenses change significantly from our assumptions, which could have a material adverse effect on our
results of operation and financial condition.

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

The risk that we do not receive payment for coal sold and delivered increases if the continued creditworthiness of our customers
declines. Recent past economic volatility and tightening credit markets increased the risk that we may not be able to collect payments from our customers or be required to continue to deliver coal
even if a customer's creditworthiness deteriorates. A worsening of recent economic conditions or a prolonged global or U.S. recession could also impact the creditworthiness of our customers. If we
determine that a customer is not creditworthy, we can demand credit enhancements from the customer. If we are unsuccessful or feel the credit enhancement is insufficient, we may not be required to
deliver coal under the customer's coal sales contract. If we are able to withhold shipments, we may decide to sell a customer's coal on the spot market, which may be at prices lower than the
contracted price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could materially and adversely affect our financial position. In addition, our
customer base may change with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the
risk we bear for customer payment default. These new power plant owners may have credit ratings that are below investment grade, or may fall below investment grade after we enter into contracts with
them. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk of payment default.

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

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

Quality
and volumes for the coal are stipulated in coal sales agreements. In most cases, the annual pricing and volume obligations are fixed, although in some cases, the volume specified
may vary depending on the quality of the coal. In a relatively small number of contracts, customers are allowed to vary the amount of coal taken under the contract. Most of our coal sales agreements
contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics, such as heat content, sulfur, ash and ash fusion temperature. Failure to meet these
specifications can result in

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economic
penalties, including price adjustments, suspension, rejection or cancellation of deliveries or termination of the contracts.

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

Failure to maintain our surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and materially and adversely affect our
ability to mine or lease coal.

Federal and state laws require us to secure the performance of certain long-term obligations, such as mine closure or
reclamation costs and federal and state workers' compensation costs, including black lung. The amount of these security arrangements is substantial with $525.0 million of surety bonds and
$10.5 million of letters of credit issued as of December 31, 2010, to support reclamation and lease obligations. We may have difficulty procuring or maintaining our surety bonds. Our
bond issuers may demand terms less favorable to us, higher fees, or additional collateral in the form of letters of credit or cash collateral upon those renewals. Because we are required by state and
federal law to have these bonds in place before mining can commence or continue, our failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially
and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by
third-party surety bond issuers of their right to refuse to renew the surety bonds and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms
of any credit arrangements then in place.

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

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

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

We have focused on strategic acquisitions and subsequent expansions of large, low-cost, low-sulfur operations
in the PRB and replacement of, and additions to, our reserves through the acquisition of companies, mines and reserves. We may pursue acquisition opportunities in the future. If we are unable to
successfully integrate the businesses or properties we acquire, or reserves that we lease or otherwise

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acquire,
our business, financial condition or results of operations could be negatively affected. Acquisition transactions involve various risks, including:



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

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

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

We
share the profits, operating expenses, reclamation obligations and liabilities and assets associated with the Decker mine equally with the other 50% owner. Under the terms of the
joint venture agreement, we are required to contribute cash or other property and equipment as may be necessary to operate the business. While capital contributions to the Decker joint venture have
historically been made at the discretion of the management committee, under the terms of the joint venture agreement we may be required to contribute our proportional share of funds to carry on the

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business
of the joint venture or to cover liabilities. In the event that either 50% owner does not contribute its share of operating expenses, including reclamation expenses when due, or other
liabilities, the other owner is not required to assume their obligation. However, we may have joint and several liability as a matter of law for these expenses and other liabilities, including for
operational liabilities. Accordingly, our financial obligations with respect to the Decker mine are subject to the creditworthiness of the other 50% owner, which is outside of our control. In
addition, if we do not provide our proportional share or the other 50% owner does not provide its proportional share, our interest in the profits from the Decker mine will be adjusted proportionally.
CPE Resources' current debt instruments and future credit arrangements may limit our ability to make contributions to the Decker joint venture.

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

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

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

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

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

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

The vast majority of our coal interests are acquired by lease from state or federal governments. Under these leases, the BLM or the
applicable state regulatory agency can terminate the lease prior to the expiration of its term if the leased coal reserves are not diligently developed during the initial 10 years of the leases
or if certain other terms of the leases are not complied with, including the requirement to produce a minimum quantity of coal or pay a minimum advance production royalty, if applicable. If any of our
leases are terminated, we would be unable to mine the affected coal and our business and results of operations could be materially adversely affected.

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

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

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

Risks Related to Our Indebtedness

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

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



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If
our indebtedness is further increased, the related risks that we now face, including those described above, could intensify. Moreover, these risks also apply to certain of CPE
Resources' domestic restricted subsidiaries that are guarantors of CPE Resources' indebtedness and may apply to us directly if we become a guarantor of CPE Resources' debt in the future. In addition
to the principal repayments on outstanding debt, we have other demands on our cash resources, including significant maintenance and other capital expenditures, including LBAs, and operating expenses
and required payments under the Tax Receivable Agreement (See "Risk FactorsRisks Related to Our Corporate Structure and the IPO Structuring Transaction"). Our ability to pay our debt
depends upon the operating performance of our business. In particular, economic conditions could cause revenues to decline, and hamper our ability to repay indebtedness. If we do not have enough cash
to satisfy our debt service obligations, we may be required to refinance all or part of our debt, sell assets, limit certain capital expenditures, including LBAs, or reduce spending or 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.

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

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

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

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

The
breach of any of the covenants or restrictions, unless cured within the applicable grace period, would result in a default under the debt instruments that would permit the lenders to
declare all amounts outstanding to be due and payable, together with accrued and unpaid interest. In such an

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event,
we may not have sufficient assets to repay such indebtedness. As a result, any default could have serious consequences to our financial condition. An event of default or an acceleration under
one of our debt instruments could also cause a cross-default or cross-acceleration of another debt instrument or contractual obligation, which would adversely impact our liquidity.

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

Provisions in CPE Resources' debt instruments could discourage an acquisition of us by a third party.

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

Risks Related to Our Corporate Structure and Our IPO Structuring Transactions

We are required to pay RTEA for most of the tax benefits we may claim as a result of the tax basis step-up we received in connection with our IPO, 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 our 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 approximately 85% of the amount of cash tax savings, if any, that we realize as a result of the increases in tax basis that we obtained in connection with the
initial acquisition of our interest in CPE Resources, 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' tangible and intangible assets, as well as the increase in our basis in the equity of CPE Resources' subsidiaries and assets
held by those subsidiaries, we expect to make
substantial payments to RTEA under the Tax Receivable Agreement. As a result of our acquisition of RTEA's remaining units in CPE Resources we have 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 has 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 continued ownership of an interest in CPE Resources or our available cash resources. Based on the tax basis of our assets as of December 31, 2010 and
CPE Resources' operating plan, the future payments under the Tax Receivable Agreement are estimated to be approximately $190.1 million in the aggregate and are estimated to be payable over the
next 20 years. This estimate is based on assumptions related to our business that could change, and the actual payments could differ materially from this estimate. Payments would be greater if
we generate income significantly in excess of the amounts used in our operating plan, for example, because we acquire additional LBAs beyond our existing LBAs, and as a result, we realize the full tax
benefit of such increased tax basis (or an increased portion thereof).

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

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

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

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

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

The historical financial information for all periods prior to our IPO included in this Form 10-K was derived from
the consolidated financial statements of Rio Tinto and does not reflect what our financial position, results of operations, cash flows, costs or expenses would have been had we been a separate,
stand-alone public company during those periods presented. Rio Tinto did not account for us, and we were not operated, as a separate, stand-alone public company for the historical periods presented
prior to our IPO. The historical costs and expenses reflected in our consolidated financial statements for periods prior to our IPO also include allocations of certain general and administrative costs
and Rio Tinto's headquarters costs. These expenses are estimates and were based on what we and Rio Tinto considered to be reasonable allocations of the historical costs incurred by Rio Tinto to
provide these services required in support of our business.

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

Prior to the IPO, our directors and executive officers had potential conflicts of interest with us and your interests as shareholders.

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

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

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

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

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

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

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

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

The
distribution of cash flows by CPE Resources to us will be subject to statutory restrictions under the Delaware Limited Liability Company Act and contractual restrictions under CPE
Resources' debt instruments that may limit the ability of CPE Resources to make distributions. In addition, any distributions and payments of fees or costs will be based upon CPE Resources' financial
performance.

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

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

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

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

Risks Related to Ownership of Our Common Stock

Our common stock has only traded since November 20, 2009 and our stock price could be volatile and could decline for a variety of reasons, resulting in a substantial
loss on your investment.

Our common stock has only traded since November 20, 2009. The stock markets generally have experienced extreme volatility, often
unrelated to the operating performance of the individual companies whose securities are traded publicly. Broad market fluctuations and general economic conditions may materially adversely affect the
trading price of our common stock.

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Significant
price fluctuations in our common stock could result from a variety of other 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 applicable to our business, sales of our common stock by our shareholders and any other
factors described in this "Risk Factors" section of this Form 10-K.

If securities analysts cease coverage about our company and our industry, or if they issue unfavorable commentary about us or our industry or downgrade our common stock, the
price of our common stock could decline.

The trading market for our common stock depends in part on the research and reports that third-party securities analysts publish about
our company and our industry. One or more analysts could downgrade our stock or issue other negative commentary about our company or our industry. If one or more of these analysts cease coverage of
our company, we could lose visibility in the market. The occurrence of one or more of these factors could cause the trading price for our stock to decline.

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

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

Certain provisions in our 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, our amended and restated certificate
of incorporation and amended and restated bylaws:



In
addition, the LLC Agreement requires that we conduct all our business operations through CPE Resources.

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Item 1B.Unresolved Staff Comments.

None

Item 2.Properties.

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

Coal Reserves

As of December 31, 2010, we controlled approximately 970 million tons of proven and probable coal reserves. All of our
proven and probable reserves are classified as steam coal.

The
following table summarizes the tonnage of our coal reserves that is classified as proven or probable, and assigned, as well as our property interest, as of December 31, 2010:

Mine

Proven
Preserves

Probable
Reserves

Total Proven
& Probable
Reserves

Assigned
Reserves

Reserves
Owned

Reserves
Leased(nearest million,
in tons)

(%)

(nearest million,
in tons)Antelope


244


8


252


100


0


252Cordero Rojo


300


84


385


100


48


337Spring Creek


304


25


329


100


0


329Decker(1)


4


0


4


100


0


4Total(2)


852


118


970





48


922


(1)Based
on our 50% interest in the Decker mine.(2)Total
reflects rounding.


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

Mine

Total Proven &
Probable Reserves

Average Btu per
lb(1)

Average Sulfur
Content

Average Sulfur
Content(2)(nearest million, in tons)



(%)

(lbs SO2/mmBtu)Antelope


252


8,850


0.23


0.52Cordero Rojo


385


8,425


0.29


0.69Spring Creek


329


9,350


0.33


0.71Decker(3)


4


9,450


0.42


0.89Total(4)


970


(1)Average
Btu per pound includes weight of moisture in the coal on an as-sold basis.(2)All
our coal is considered to be compliance coal under the Clean Air Act.(3)Based
on our 50% interest in the Decker mine.(4)Total
reflects rounding.


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



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

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

Our
coal reserve estimates are based on data obtained from our drilling activities and other available geologic data. All of our reserves are assigned, associated with our active coal
properties, and incorporated in detailed mine plans. Estimates of our reserves are based on more than 7,500 drill holes. Our proven reserves have a typical drill hole spacing of 1,500 feet or less,
and our probable reserves have a typical drill hole spacing of 2,500 feet or less.

Along
with the geological data we assemble for our coal reserve estimates, our staff of geologists and engineers also analyzes the economic data such as cost of production, projected
sales price and other data concerning permitting and advances in mining technology. Various factors and assumptions are utilized in estimating coal reserves, including assumptions concerning future
coal prices and operating costs. These estimates are periodically updated to reflect past coal production and other geologic or mining data. Acquisitions or sales of coal properties will also change
these estimates. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam. We maintain reserve information in secure computerized
databases, as well as in hard copy.

Reserve Acquisition Process

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

We
acquire a significant portion of our coal through the LBA process, and as a result, substantially all of our coal is held under federal leases. Under this process, before a mining
company can obtain new federal coal, the company must nominate a coal tract for lease and then win the lease through a competitive bidding process. The LBA process can last anywhere from two to five
years from the time the coal tract is nominated to the time a final bid is accepted by the BLM. After the LBA is awarded, the company then conducts the necessary testing to determine what amount can
be classified as reserves and begins the process to permit the coal for mining, which generally takes another two to five years. Third-party legal challenges, such as legal challenges filed in 2010
against the BLM and the Secretary of the Interior by environmental groups with respect to the LBA process in the PRB and the West Antelope II LBA, may result in delays and other adverse impacts on the
LBA process.

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

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The
BLM also allows for small tracts of coal to be acquired through a leasing process known as a Lease by Modification, or LBM. An LBM is a non-competitive leasing process
and is used in circumstances where a lessee is seeking to modify an existing federal coal lease by adding less than 960 acres in a configuration that is deemed non-competitive to
other coal operators. In June 2010, we entered into a modified coal lease with the BLM through the LBM process to add approximately 48 million tons of proven and probable reserves to one of the
Spring Creek mine's existing federal coal leases.

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

After
the environmental analysis or EIS has been issued and a recommendation has been published that supports the lease sale of the LBA tract, the BLM schedules a public
competitive lease sale. The
BLM prepares an internal estimate of the fair market value of the coal that is based on its economic analysis and comparable sales analysis. Prior to the lease sale, companies interested in acquiring
the lease must send sealed bids to the BLM. The bid amounts for the lease are payable in five annual installments, with the first 20% installment due when the mining operator submits its initial bid
for an LBA. Before the lease is approved by the BLM, the company must first furnish to the BLM an initial rental payment for the first year of rent along with either a bond for the next 20% annual
installment payment for the bid amount, or an application for history of timely payment, in which case the BLM may waive the bond requirement if the company successfully meets all the qualifications
of a timely payor. The bids are opened at the lease sale. If the BLM decides to grant a lease, the lease is awarded to the company that submitted the highest total bid meeting or exceeding the BLM's
fair market value estimate, which is not published. The BLM, however, is not required to grant a lease even if it determines that a bid meeting or exceeding the fair market value of the coal has been
submitted. The winning bidder must also submit a report setting forth the nature and extent of its coal holdings to the U.S. Department of Justice for a 30-day antitrust review of the
lease. If the successful bidder was not the initial applicant, the BLM will refund the initial applicant certain fees it paid in connection with the application process, for example the fees
associated with the environmental analysis or EIS, and the winning bidder will bear those costs. Coal won through the LBA process and subject to federal leases are administered by the U.S. Department
of Interior under the Federal Coal Leasing Amendment Act of 1976. In addition, we occasionally add small coal tracts adjacent to our existing LBAs through an agreed upon lease modification with the
BLM. Once the BLM has issued a lease, the company must next complete the permitting process before it can mine the coal. See "Environmental and Other Regulatory MattersMining
Permits and Approvals."

The
federal coal leasing process is designed to be a public process, giving stakeholders and other interested parties opportunities to comment on the BLM's proposed and final actions and
allow third-party comments. Because of this, third parties, including non-governmental organizations, can challenge the BLM's actions, which may delay the leasing process. If these
challenges prove successful or are litigated for a prolonged period of time, a coal company's ability to bid on or acquire a new coal lease could be significantly delayed, or could cause the BLM to
not offer a lease for bid at all. In 2010, environmental organizations filed legal challenges against the BLM's findings on the final EIS and other matters associated with the West Antelope II LBA,
which was nominated by our Antelope mine. These challenges have created some uncertainty with respect to the timing of the LBA bid and lease acquisition and may ultimately delay the leasing process or
prevent mining operations. Even after a lease has been issued and a successful bidder has paid installment money to the BLM, legal challenges may still seek to delay or prevent mining operations. It
is possible that subsequent EISs for other mines

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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 applicable leasing regulations. In certain cases, a lessee may
combine contiguous leases into a logical mining unit, or LMU. This allows the production of coal from any of the leases within the LMU to be used to meet the continuous operation requirements for the
entire LMU. We currently have an LMU for our Antelope mine. We pay to the federal government an annual rent of $3.00 per acre and production royalties of 12.5% of gross revenues on surface mined coal.
The federal government remits approximately 50% of the production royalty payments to the state after deducting administrative expenses. Some of our mines are also subject to coal leases with the
states of Montana or Wyoming, as applicable, and have different terms and conditions that we must adhere to in a similar way to our federal leases. Under these federal and state leases, if the leased
coal is not diligently developed during the initial 10-year development period or if certain other terms of the leases are not complied with, including the requirement to produce a minimum
quantity of coal or pay a minimum production royalty, if applicable, the BLM or the applicable state regulatory agency can terminate the lease prior to the expiration of its term.

Most
of the coal we lease from the United States comes from "split estate" lands in which one party, typically the federal government, owns the coal and a private party owns the surface.
In order to mine the coal we acquire through the LBA process, we must also acquire rights to mine from the owners of the surface lands overlying the coal. Certain federal regulations provide a
specific class of surface owners, Qualified Surface Owners, or QSOs, with the ability to prohibit the BLM from leasing its coal. For example, in connection with a pending LBA that we nominated for our
Cordero Rojo mine, the BLM has indicated that certain surface owners satisfy the regulatory definition of QSO. If the land overlying a coal tract is owned by a QSO, federal laws prohibit us from
leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO, which would allow us to conduct our mining operations. Furthermore, the state
permitting process requires us to demonstrate surface owner consent for split estate lands before the state will issue a permit to mine coal. This consent is separate from the QSO consent required
before leasing federal coal. The right of QSOs and certain other surface owners allows them to exercise significant influence over negotiations and prices to acquire surface rights and can delay the
LBA or permitting processes or ultimately prevent the acquisition of the LBA or permit over that land entirely. There are QSOs that own land adjacent to or near our existing mines that may be
attractive acquisition candidates for us. Typically, we seek to purchase the land overlying our coal or enter into option agreements granting us an option to purchase the land upon acquiring an LBA.
In some instances, however, we enter into separate lease arrangements with surface owners allowing us to conduct our mining operations on the land. We own substantially all of the land over our
reserves.

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

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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, 2011 and May 31, 2012, and we lease
approximately 28,100 square feet of office space in Broomfield, Colorado under a lease that expires in February 2021. As of December 31, 2010, all of our long-lived assets were
located in the U.S. See Note 18 of Notes to Consolidated Financial Statements in Item 8.

Item 3.Legal Proceedings.

MMS LitigationDecker Mine

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

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

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

We
have not accrued a liability in our consolidated financial statements with respect to this matter as any potential losses are not considered to be probable and reasonably estimable.
If the MMS issues a new assessment for the 1993 - 2001 period, Decker believes it will have substantive challenges to any such assessment in light of the District Court's
decision in Decker I. Decker also believes that it has contractual price escalation protection from any increased assessments for 1993-2001; and that, in addition, Commonwealth Edison has
indemnified Black Butte with respect to the 1993-2001 assessment,

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and
that in furtherance of that obligation, Commonwealth Edison or its parent company, Exelon Generation, Inc., has therefore agreed to indemnify Decker directly for such matters. If a new
assessment is issued by the MMS for the 1993 - 2001 period and is upheld and the indemnities and/or price protections were ultimately not available to Decker, the resulting
Decker liability could be material. As a result of our 50% ownership interest in Decker, our financial results could in turn be materially adversely affected. We consider Decker's conclusions to be
reasonable; however, we have not relied upon Decker's conclusions in reaching our decision that any potential losses are not considered probable and reasonably estimable.

Caballo Coal Company LitigationSpring Creek

In September 2009, Caballo Coal Company ("Caballo"), a subsidiary of Peabody Energy Corporation, commenced an action in Wyoming state
court against Spring Creek Coal Company ("Spring Creek"), our wholly-owned subsidiary, asserting that Spring Creek repudiated its allegedly remaining obligation under a 1987 agreement to purchase an
additional approximately 1.6 million tons of coal, for which it seeks unspecified damages. Spring Creek believes that it has meritorious defenses to the claim, including that Caballo breached
the agreement by failing to make required deliveries in 2006 and 2007. Spring Creek also believes that it has meritorious counterclaims against Caballo. We have not accrued a liability in our
consolidated financial statements with respect to this matter as any potential losses are not considered to be probable and reasonably estimable. If, however, the case was determined in an adverse
manner to us, the payment of any judgment could be material to our results of operations.

Other Legal Proceedings

We are involved in other legal proceedings arising in the ordinary course of business and may become involved in additional proceedings
from time to time. We believe that there are no other legal proceedings pending that are likely to have a material adverse effect on our consolidated financial condition, results of operations or cash
flows. Nevertheless, we cannot predict the impact of future developments affecting our claims and lawsuits, and any resolution of a claim or lawsuit or an accrual within a particular fiscal period may
adversely impact our results of operations for that period. In addition to claims and lawsuits against us, our LBAs, permits and other industry regulatory processes and approvals may also be subject
to legal challenges that may adversely impact our mining operations and results. For example, the West Antelope II LBA, which we have nominated for lease with the Bureau of Land Management, is subject
to pending legal challenges filed in 2010 against the Bureau of Land Management and the Secretary of the Interior by environmental organizations.

Item 4.Reserved.

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PART II

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

Our 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 our common stock.

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

High

LowFiscal 2009(commencing November 20, 2009)


15.04


12.69Fiscal 2010First Quarter 2010


16.84


13.51Second Quarter 2010


17.15


13.26Third Quarter 2010


18.37


13.20Fourth Quarter 2010


23.23


17.05


As
of the close of business on January 31, 2011, we have 1,446 holders of record of our common stock.

Dividend Policy

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

Stock Performance Graph

The following performance graph compares the cumulative total return on our common stock with the cumulative total return of the
following indices: (i) the Standard & Poor's ("S&P") MidCap 400 stock index and (ii) the Custom Composite Index comprised of Alpha Natural Resources, Inc., Arch
Coal, Inc., CONSOL Energy, Inc., Massey Energy Company and Peabody Energy Corp. The graph assumes that you invested $100 in our common stock and in each index at the closing price on
November 20, 2009, that all dividends were reinvested and that you continued to hold your investment through December 31, 2010. In January 2011, Alpha Natural Resources, Inc. and
Massey Energy Company announced they signed a definitive agreement under which Alpha Natural Resources will acquire all outstanding shares of Massey Energy Company common stock, subject to customary
closing conditions, including stockholder approval of both companies.

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

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COMPARISON OF CUMULATIVE TOTAL RETURN

GRAPHIC

ASSUMES $100 INVESTED ON NOV. 20, 2009  ASSUMES DIVIDEND REINVESTED  FISCAL YEAR ENDING DEC. 31, 2010

Company/Market/Peer Group

11/20/2009

12/31/2009

3/31/2010

6/30/2010

9/30/2010

12/31/2010Cloud Peak Energy

$
100.00

$
98.11

$
112.13

$
89.35

$
122.98

$
156.54S&P MidCap 400

$
100.00

$
105.90

$
115.53

$
104.45

$
118.15

$
134.11Custom Composite

$
100.00

$
104.34

$
106.41

$
81.60

$
98.43

$
135.21


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, 2010 and 2009 and for each of the three years in the period ended December 31, 2010 from our
audited consolidated financial statements included in Item 8 of this report. We have derived the historical consolidated balance sheet data as of December 31, 2008, 2007 and 2006 and the
historical consolidated statement of operations data for the years ended December 31, 2007 and 2006 from the audited consolidated financial statements of RTEA not included in this report.

The
historical financial information for all periods prior to our IPO included in this report was derived from the consolidated financial statements of RTEA and does not reflect what our
financial position, results of operations, and cash flows would have been had we been a separate, stand-alone

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public
company during those periods. We were not operated as a separate, stand-alone public company for the periods prior to our IPO. The historical costs and expenses reflected in our consolidated
financial statements for those periods include allocations of certain general and administrative expenses incurred by Rio Tinto America and other Rio Tinto affiliates. We believe these allocations
were reasonable; however, the allocated expenses are not necessarily indicative of the expenses that would have been incurred if we had been a separate, independent entity.

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

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Selected Consolidated Financial and Other Data

Year Ended December 31,2010

2009

2008

2007

2006(dollars in thousands, except per share amounts)Statement of Operations DataRevenues

$
1,370,761

$
1,398,200

$
1,239,711

$
1,053,168

$
942,841Operating income(1)


211,875


255,003


124,936


102,731


88,868Income from continuing operations


117,197


182,472


88,340


53,789


40,537Income (loss) from discontinued operations(2)





211,078


(25,215
)

(21,482
)

(2,599
)Net income


117,197


393,550


63,125


32,307


37,938Amounts attributable to controlling interest(3)Income from continuing operations


33,737


170,623


88,340


53,789


40,537Income (loss) from discontinued operations(4)





211,078


(25,215
)

(21,482
)

(2,599
)Net income


33,737


381,701


63,125


32,307


37,938Earnings per sharebasic(3)(4)Income from continuing operations

$
0.98

$
3.01

$
1.47

$
0.90

$
0.68Income (loss) from discontinued operations(2)

$


$
3.73

$
(0.42
)
$
(0.36
)
$
(0.05
)Net income

$
0.98

$
6.74

$
1.05

$
0.54

$
0.63Earnings per share attributable to controlling interestdiluted(3)(4)Income from continuing operations

$
0.98

$
2.97

$
1.47

$
0.90

$
0.68Income (loss) from discontinued operations(2)

$


$
3.52

$
(0.42
)
$
(0.36
)
$
(0.05
)Net income

$
0.98

$
6.49

$
1.05

$
0.54

$
0.63




December 31,2010

2009

2008

2007

2006(dollars in thousands)Balance Sheet DataCash and cash equivalents

$
340,101

$
268,316

$
15,935

$
23,616

$
19,585Property, plant and equipment, net


1,008,337


987,143


927,910


719,743


703,726Assets of continuing operations(2)


1,915,107


1,677,596


1,198,023


1,059,366


1,029,269Total assets


1,915,107


1,677,596


1,785,191


1,781,201


1,723,335Long-term debt


595,684


595,321





500,627


583,181Federal coal leases and related obligations(5)


126,360


178,367


209,526


70,932


82,554Liabilities of continuing operations(2)


1,383,908


1,232,118


672,805


1,176,191


1,163,493Total liabilities


1,383,908


1,232,118


800,025


1,446,240


1,433,480Controlling interest equity(3)


531,199


252,905


985,166


334,961


289,855Noncontrolling interest equity(3)





192,573













Year Ended December 31,2010

2009

2008

2007

2006(dollars in thousands)Other DataAdjusted EBITDA(6)

$
322,733

$
320,582

$
207,229

$
159,845

$
119,028Adjusted EPS(6)

$
1.62

$
2.48

$
1.06

$
0.46

$
0.24Tons soldcompany owned and operated mines (millions)


93.7


90.9


93.7


90.7


88.2Tons soldDecker mine (millions)(7)


1.5


2.3


3.3


3.5


3.6Tons soldtotal production (millions)


95.2


93.2


97.0


94.2


91.8Tons purchased and resold (millions)


1.7


10.1


8.1


8.1


8.1Total tons sold (millions)


96.9


103.3


105.1


102.3


99.9


(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 our IPO. For the year ended December 31, 2009, discontinued operations includes the $264.8 million pre-tax gain on sale of the Jacobs
Ranch


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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 our 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 our 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 Cloud Peak Energy Inc.(4)Earnings
per share for periods prior to the IPO assumes 60,000,000 outstanding shares, which is the number of shares that our predecessor, RTEA, would have
been required to have outstanding in prior periods based on the capital structure of Cloud Peak Energy Inc., which requires a 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 Cloud Peak Energy Inc. See Note 16 of Notes to Consolidated Financial Statements in
Item 8.(5)Federal
coal leases and related obligations includes the current and long-term portions of discounted obligations pursuant to federal coal
leases of $118.3 million, $169.1 million, $206.3 million, $67.6 million and $79.0 million as of December 31, 2010, 2009, 2008, 2007 and 2006, respectively.(6)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., or U.S. GAAP. A quantitative reconciliation of Adjusted EBITDA to income from continuing operations and Adjusted EPS to EPS (as defined below) is
found in the tables below.
EBITDA
represents income from continuing operations before (1) interest income (expense) net, (2) income tax provision, (3) depreciation and depletion, (4) amortization,
and (5) accretion. Adjusted EBITDA represents EBITDA as further adjusted to exclude specifically identified items that management believes do not directly reflect our core operations. For the
periods presented herein, the specifically identified items are the income statement impacts of: (1) the tax agreement and (2) our 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 ("EPS"), adjusted to exclude the estimated per share impact of the same
specifically identified items used to calculate Adjusted EBITDA and described above.

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

We
believe Adjusted EBITDA 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, EPS or other U.S. GAAP
financial measures, as these non-GAAP measures exclude certain items, including items that are recurring in nature, which may be meaningful to investors. Adjusted EBITDA excludes interest
expense and interest income; however, as we have historically borrowed money in order to finance transactions and operations, and have invested available cash to generate interest income, interest
expense and interest income are elements of our cost structure and influence our ability to generate revenue and returns for shareholders. Adjusted EBITDA excludes depreciation and depletion and
amortization; however, as we use capital and intangible assets to generate revenues, depreciation, depletion and


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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 tax agreement expense;
however, this represents our current estimate of payments we will be required to make to Rio Tinto under our Tax Receivable Agreement. 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, 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 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 to evaluate the business allows management and investors to (a) assess our relative performance against our competitors and (b) ultimately monitor our capacity
to generate returns for shareholders.

Because
not all companies use identical calculations, our 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.

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


Year Ended December 31,2010

2009

2008

2007

2006(dollars in thousands)Net income from continuing operations

$
117,197

$
182,472

$
88,340

$
53,789

$
40,537Interest income


(565
)

(320
)

(2,865
)

(7,302
)

(3,604
)Interest expense


46,938


5,992


20,376


40,930


38,785Income tax provision


31,982


68,249


25,318


18,050


11,717Depreciation and depletion


100,023


97,869


88,972


80,133


59,352Amortization


3,197


28,719


45,989


34,512


34,957Accretion


12,499


12,587


12,742


12,212


10,088EBITDA


311,271


395,568


278,872


232,324


191,832Tax agreement expense


19,669











Expired significant broker contract


(8,207
)

(74,986
)

(71,643
)

(72,479
)

(72,804
)Adjusted EBITDA

$
322,733

$
320,582

$
207,229

$
159,845

$
119,028


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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 31,2010

2009

2008

2007

2006Diluted earnings (loss) per common share attributable to controlling interest from continuing operations

$
0.98

$
2.97

$
1.47

$
0.90

$
0.68Expired significant broker contract


(0.09
)

(0.49
)

(0.41
)

(0.44
)

(0.44
)Tax agreement expense


0.57











Change in net value of deferred tax assets


0.16











Adjusted EPS

$
1.62

$
2.48

$
1.06

$
0.46

$
0.24Weighted-average shares outstanding


34,305,205


60,000,000


60,000,000


60,000,000


60,000,000


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


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

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

Overview

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



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

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On December 15, 2010, Cloud Peak Energy Inc. priced the Secondary Offering of 29,400,000 shares of its common stock. In connection with the
Secondary Offering, we exchanged 29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the Secondary Offering, resulting in a divestiture
of 100% of Rio Tinto's holdings in CPE Resources. As a result of this transaction, CPE Resources is now a wholly-owned subsidiary of Cloud Peak Energy Inc. In addition, the elimination of Rio
Tinto as a member results in the elimination of noncontrolling interest in our consolidated balance sheet during the period. The statement of operations for the year ended December 31, 2010
will present the portion of income attributable to the noncontrolling interest through the date of the Secondary Offering and no income will be attributable to the noncontrolling interest in future
periods. This transaction also resulted in an increase to the undiscounted future liability under the Tax Receivable Agreement of $123.6 million and an increase to our deferred income taxes of
$93.6 million net of valuation allowances.

For
all periods presented, our historical consolidated financial statements include the accounts of CPE Resources and its subsidiaries. For periods ending after July 31, 2008 (the
date Cloud Peak Energy Inc. was incorporated), our consolidated financial statements include the accounts of Cloud Peak Energy Inc.; however, Cloud Peak Energy Inc. did not have
any business operations or material transactions prior to November 19, 2009. For periods prior to November 20, 2009, our consolidated financial statements also include the accounts of
RTEA, which was the parent company of CPE Resources prior to our IPO structuring transactions. As a result of our IPO structuring transactions, our consolidated financial statements reflect Cloud Peak
Energy Inc. as the parent company and no longer include the accounts of RTEA, our former parent company. For periods between November 20, 2009 (the date of the IPO) and
December 15, 2010 (the date of the Secondary Offering), Rio Tinto's
ownership interest in CPE Resources is reported as a noncontrolling interest in our consolidated financial statements.

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

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



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Historical

Adjustments

Pro FormaNet income

$
117,197

$
(28,451
)
$
88,746Less: Net income attributable to noncontrolling interest


83,460


(83,460
)

Net income attributable to controlling interest

$
33,737

$
55,009

$
88,746Earnings per common share attributable to controlling interestBasic

$
0.98




$
1.48Diluted

$
0.98




$
1.47Weighted-average shares outstandingBasic


34,305,205





60,000,000Diluted


34,305,205





60,168,263




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



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

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



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

Our
key business drivers include the following:



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

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

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

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

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

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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, the time periods over which those laws or regulations would be phased
in and the state of commercial development and deployment of carbon capture and storage technologies. In view of the significant uncertainty surrounding each of these factors, it is not possible for
us to reasonably predict the impact that any such laws or regulations may have on our results of operations, financial condition or cash flows. See Item 1, "BusinessEnvironmental
and Other Regulatory MattersClimate Change" and Item 1A, "Risk Factors" for additional discussion regarding how climate change and other environmental regulatory matters impact our
business.

Results of Operations



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

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

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

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

Year Ended
December 31,

Change2010

2009

$

PercentOwned and operated mines

$
1,154.7

$
1,072.1


82.6


7.7Other operations


216.1


326.1


(110.0
)

(33.7
)Total revenue

$
1,370.8

$
1,398.2


(27.4
)

(2.0
)


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

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

Other
revenues consist primarily of our share of revenues from coal produced at the Decker mine, broker coal sales and billings for transportation and delivery services. Our share of
revenues from coal produced at the Decker mine decreased reflecting a decline in shipments partially offset by higher average price per ton. Broker coal sales reduced following the expiration of our
significant contract that expired in the first quarter of 2010. 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 rail and port charges, where we arranged and paid for the freight costs and charged our customers on a cost-plus basis for
providing this service.



The following table presents cost of product sold for the years ended December 31, 2010 and 2009 (in millions):

Year Ended
December 31,

Change2010

2009

$

PercentOwned and operated mines

$
803.3

$
722.1


81.2


11.2Other operations


175.6


211.4


(35.8
)

(16.9
)Total cost of product sold

$
978.9

$
933.5


45.4


4.9


The
increase in costs for our owned and operated mines reflects a 3.1% increase in tons shipped from our mines, and a 7.9% increase in the cost per ton of coal produced, from $7.94 in
2009 to $8.57 in 2010. The increase in the cost per ton of coal produced 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 produced increased
from $4.53 to $4.83. The increase in the cost per ton of coal produced 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 produced 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

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coal
decreased $86.7 million, primarily as a result of decreases of $64.7 million related to our 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.



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

Year Ended
December 31,

Change2010

2009

$

PercentOperating income

$
211.9

$
255.0


(43.1
)

(16.9
)


Operating
income was affected by the following factors in addition to those discussed above:





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

Year Ended
December 31,

Change2010

2009

$

PercentTotal 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 third quarter, 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 13 of Notes to Consolidated Financial Statements in Item 8.



The following table presents our income tax provision for the years ended December 31, 2010 and 2009 (in millions):

Year Ended
December 31,

Change2010

2009

$

PercentIncome tax provision

$
32.0


68.2


(36.2
)

(53.1
)Effective tax rate


21.9
%

27.4
%


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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 13 of Notes to Consolidated Financial Statements in Item 8.



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

Year Ended
December 31,

Change2010

2009

$

PercentDiscontinued operations

$


$
211.1


(211.1
)

(100
)


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



The following table presents income attributable to noncontrolling interest for the years ended December 31, 2010 and 2009 (in
millions):

Noncontrolling interest January 1, 2009 through November 19, 2009

$
Noncontrolling interest November 19, 2009 through December 31, 2009


11.8December 31, 2009 income attributable to noncontrolling interest

$
11.8Noncontrolling interest January 1, 2010 through December 15, 2010

$
83.5Noncontrolling 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 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 Cloud Peak Energy 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 our IPO on November 19, 2009 or after the Secondary Offering on December 15, 2010.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

During the first half of 2008, due to a favorable supply and demand balance for PRB coal, increasing prices for our coal enabled us to
enter into long-term contracts at higher prices. Since mid-2008, however, the economic downturn, particularly with respect to the U.S. economy, coupled with the global
financial and credit market disruptions, had an adverse impact on the coal industry. As a result of our long-term contracting strategy, in which we enter into forward contracts for a
significant portion of our coal, we experience a lag in revenue trends compared to spot price fluctuations.

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Consequently,
despite a decrease in tons sold from 2008 to 2009, we experienced an increase in total revenues from sales of coal.

The
weak market conditions during 2009 resulted in decreased demand for our coal and lower spot prices, and the fixed price contracts we entered into for future sales were at lower
prices than the contractual prices we were able to achieve in 2008 for future sales. These lower prices will negatively impact our future revenues for the contractual periods, which historically have
been one to five years; however, we are currently experiencing a period where we, and our customers, are seeking to enter into contracts with shorter terms, which may mitigate the impact. To further
mitigate the potentially negative impact on our operating results, we have focused our cost management efforts, which resulted in reducing utilization of contractors, lowering employee overtime, and
optimizing repairs and maintenance expense.



The following table presents revenues for the years ended December 31, 2009 and 2008 (in millions):

Year Ended
December 31,

Change2009

2008

$

PercentOwned and operated mines

$
1,077.2

$
978.3


98.9


10.1Other operations


321.0


261.4


59.6


22.8Total revenue

$
1,398.2

$
1,239.7


158.5


12.8


The
increase in revenues from our owned an operated mines reflects a 13.5% increase in the average price per ton of coal sold, from $10.44 in 2008 to $11.85 in 2009, and a 3.0% decrease
in shipments, from 93.7 tons in 2008 to 90.9 million tons in 2009. The increase in average price per ton sold reflects the strong demand for PRB coal due to prevailing economic and industry
conditions at the time we entered into the related coal supply contracts. The decrease in volume reflects the downturn in the overall economic conditions in the U.S. markets near the end of 2008 and
continuing into 2009, which resulted in certain customers not taking all of their contracted purchases of coal. Our share of revenues from coal produced at the Decker mine decreased, reflecting a
decline in shipments partially offset by higher average price per ton.

The
balance of our revenues consist primarily of broker coal sales including revenues from our significant broker sales contract that expired in 2010 of $140.4 million and
$135.1 million for the years 2009 and 2008, respectively, and billings for transportation and delivery services. Other broker coal sales increased by $28.1 million in 2009 compared to
2008, reflecting increases in shipments and average selling prices. Revenues from transportation and delivery services increased by $39.6 million, as a result of a higher volume of coal sold on
a delivered basis, including export sales with delivered pricing terms that include rail and port charges, where we arranged and paid for the freight costs and charged our customers on a
cost-plus basis for providing this service. Other revenues, which in 2008 included $6.3 million from a Decker contract settlement, decreased $5.1 million in 2009.

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The following table presents cost of product sold for the years ended December 31, 2009 and 2008 (in millions):

Year Ended
December 31,

Change2009

2008

$

PercentOwned and operated mines

$
722.7

$
730.0


(7.3
)

1.0Other operations


210.8


164.0


46.8


28.5Total cost of product sold

$
933.5

$
894.0


39.5


4.4


The
largest component of cost of product sold is the cost of coal produced at the three mines that we own and operate. The moderate decrease reflects the 3.0% decrease in tons shipped
from our mines, partially offset by 2.1% increase in the cost per ton of coal produced, from $7.79 in 2008 to $7.95 in 2009. The increase in the cost per ton of coal produced is primarily the result
of an 11.0% per ton increase in royalties and production taxes which reflects the higher average sales prices realized on our 2009 coal shipments. Excluding royalties and production taxes, the cost
per ton of coal produced declined from $4.70 to $4.52, primarily reflecting decreases in unit costs for fuel, lubricants and explosives, as a result of lower prevailing commodity prices in 2009,
partially offset by moderate increases in unit costs for labor, repairs and supplies. The cost of coal produced by the Decker mine decreased $5.3 million in 2009, reflecting lower production
volumes partially offset by higher unit production costs.

Cost
of product sold also increased in 2009 due to the greater volume of sales on a delivered basis, where we arranged transportation, resulting in a $27.8 million increase in
freight and handling costs. In addition, the cost of purchased coal increased $24.2 million, including increases of $2.0 million for our significant broker sales contract that expired in
2010 and $22.2 million for other broker sales, consistent with the related increase in broker sales revenues in 2009.



The following table presents operating income for the years ended December 31, 2009 and 2008 (in millions):

Year Ended
December 31,

Change2009

2008

$

PercentOperating income

$
255.0

$
124.9


130.1


104.2


Operating
income was affected by the following other factors not discussed above:



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The following table presents total other expense for the years ended December 31, 2009 and 2008 (in millions):

Year Ended
December 31,

Change2009

2008

$

PercentTotal other expense

$
5.7

$
15.8


(10.1
)

(63.9
)


Total
other expense declined primarily due to a decrease in interest expense, which declined due to the termination on September 24, 2008 of the RTA Facility, under which we
incurred interest of $16.8 million in 2008. Interest expense will increase going forward as a result of the debt financing transactions entered into in connection with the IPO. See
"Liquidity and Capital ResourcesSenior Unsecured Notes and Senior Secured Revolving Credit Facility" below.



The following table presents our income tax provision for the years ended December 31, 2009 and 2008 (in millions):

Year Ended
December 31,

Change2009

2008

$

PercentIncome tax provision

$
68.2

$
25.3


42.9


169.6Effective tax rate


27.4
%

23.2
%


Income
tax expense increased primarily due to higher income before taxes. The increase in effective tax rate in 2009 was primarily due to a reduction in tax benefits received for
percentage depletion deductions. The adjustment to the effective tax rate for the post-IPO period in 2009 to account for pretax income attributable to the noncontrolling interest reduced
our effective tax rate by approximately 1.5%. See Note 13 of Notes to Consolidated Financial Statements in Item 8.



The following table presents income (loss) from discontinued operations for the years ended December 31, 2009 and 2008 (in
millions):

Year Ended
December 31,

Change2009

2008

$

PercentDiscontinued operations

$
211.1

$
(25.2
)

236.3


*


*Change
from prior period is not a relevant percentage


The
favorable change in income from discontinued operations was primarily attributable to income from the Jacobs Ranch mine, which was sold on October 1, 2009, resulting in a
pre-tax gain of $264.8 million. Jacobs Ranch mine operating income prior to disposal improved by $69.4 million due to higher coal prices and the cessation of depreciation,
depletion and amortization as a result of the assets

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being
classified as held for sale as of March 1, 2009. These favorable changes were partially offset by a $119.0 million increase in related income taxes. The overall increase in income
from discontinued operations also reflects the absence in 2009 of net losses incurred at the Colowyo mine and the uranium mining venture after RTEA transferred its interests in the property to Rio
Tinto America in October 2008.

Liquidity and Capital Resources

Total cash comprises cash and cash equivalents and restricted cash. As of December 31, 2010 and 2009, total cash was
$522.2 million and $348.5 million, respectively. These amounts included cash and cash equivalents of $340.1 million and $268.3 million, respectively, and restricted cash of
$182.1 million and $80.2 million, respectively. Restricted cash collateralizes certain of our surety bond obligations at collateral levels that were established by our surety bond
providers in 2009 following our IPO. As of December 31, 2009, our surety bonds were generally collateralized using Rio Tinto's balance sheet and letters of credit. During 2010, we posted
$218.4 million in restricted cash collateral as we replaced Rio Tinto's surety bonds. We used restricted cash to avoid the fees associated with letters of credit, which can also be used as
collateral. In the fourth quarter of 2010 we were successful in releasing $36.3 million of collateral from our surety program and this balance is reflected in our cash and cash equivalents.
Prior to our IPO, substantially all of our cash balances, except cash held by Decker, were transferred to Rio Tinto in accordance with the Rio Tinto cash management arrangement.

In
addition to our cash and cash equivalents, our primary sources of liquidity are cash from our operations and borrowing capacity under our $400 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 impacting our business, reclamation costs, the market price we pay for diesel fuel, variables affecting other costs of our business and other risks and
uncertainties, including those discussed in Item 1A "Risk Factors."

The
borrowing capacity under our revolving credit facility is reduced by the amount of letters of credit issued. As of December 31, 2010, our borrowing capacity under the
revolving credit facility was $389.5 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, federal coal lease installment
payments for existing and new LBAs, capital expenditures, interest on our debt and payments to RTEA under our Tax Receivable Agreement.

We
intend to seek increases in our reserve position by acquiring federal coal and surface rights adjoining our current operations in Wyoming and Montana. Through the LBA process, we have
nominated large coal tracts adjacent to our existing operations. If we are awarded new coal leases, which may occur as early as 2011, our cash flows could be significantly impacted as we would be
required to make the initial lease payment and annual payments thereafter. We will continue to explore additional opportunities to increase our reserve base.

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In addition, our anticipated capital expenditures, which we expect will be between $100 million and $140 million (excluding federal coal lease
payments) in 2011, 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.

We
are required to make semi-annual interest payments on our senior notes, which commenced on June 15, 2010. We also expect to make on-going payments to
RTEA under the Tax Receivable Agreement, which will impact our liquidity.

If
we do not have sufficient resources to satisfy our obligations, we may need to borrow money or take other actions. 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 adopting certain alternatives to obtain additional funding.



We started 2010 with $268.3 million of unrestricted cash and cash equivalents. After making interest and private and federal
coal lease payments of $53.0 million and $65.4 million, respectively, capital expenditures of $65.0 million and generating $322.7 million of Adjusted EBITDA, we ended the
year with $340.1 million of unrestricted cash and cash equivalents. We started 2010 with $80.2 million of restricted cash. During the first half of 2010, we contributed an additional
$138.2 million of cash and cash equivalents to restricted cash to collateralize our surety and performance bond obligations. We released $36.3 million of collateral in the fourth quarter
of 2010 following a negotiated reduction of the collateral required. We ended the year with $182.1 million of restricted cash.



The following table summarizes operating cash flows for the years ended December 31, 2010 and 2009 (in millions):

Year Ended
December 31,

Change2010

2009

$

PercentNet income from continuing operations

$
117.2

$
182.5


(65.3
)

(35.8
)Non-cash reconciling items


174.8


158.8


16.0


10.1Increase in working capital


32.8


115.3


(82.5
)

(71.6
)Net cash provided by operating activities

$
324.8

$
456.6


(131.8
)

(28.9
)


The
increase from adjustments before changes in working capital was largely due to a change in deferred taxes. The decrease in working capital was largely driven by a reduction in
related party receivables as a result of changes in our relationship with Rio Tinto through the IPO structuring transactions.

The
following table summarizes investing cash flows for the years ended December 31, 2010 and 2009 (in millions):

Year Ended
December 31,

Change2010

2009

$

PercentPurchases of property, plant, and equipment

$
91.6

$
119.7


(28.1
)

(23.5
)Other investing activities, net


100.4


297.3


(196.9
)

(66.2
)Cash used in investing activities from continuing operations

$
192.0

$
417.1


(225.1
)

(54.0
)


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The
decrease in cash used in investing activities from continuing operations 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.
Year-to-date property, plant, and equipment purchases include 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 $101.9 million increase in restricted cash to collateralize surety bonds obligations.

The
following table summarizes financing cash flows for the years ended December 31, 2010 and 2009 (in millions):

Year Ended
December 31,

Change2010

2009

$

PercentCash used in financing activities from continuing operationsnon IPO related

$
61.0

$
68.6


7.6


11.1Cash used in financing activities from continuing operationsIPO only





513.6


(513.6
)

*Cash used in financing activities from continuing operationsTotal

$
61.0

$
582.2


(521.2
)

(89.5
)


*Change
from prior period is not a relevant percentage


During
2010, we made distributions to Rio Tinto totaling $10.2 million and principal payments for coal lease obligations of $50.8 million. Distributions to Rio Tinto were
required by the CPE Resources limited liability company agreement and correspond to distributions made to Cloud Peak Energy Inc. 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.

The
following table summarizes operating cash flows for the years ended December 31, 2009 and 2008 (in millions):

Year Ended
December 31,

Change2009

2008

$

PercentNet income from continuing operations

$
182.5

$
88.3


94.2


106.7Non-cash reconciling items


158.8


181.8


(23.0
)

(12.7
)Increase in working capital


115.3


(120.1
)

235.4


196.0Net cash provided by operating activities

$
456.6

$
150.0


306.6


204.4


This
increase reflects a $201.5 million change in the effects of transactions with related parties. In the year ended December 31, 2008, we made payments to affiliates that
resulted in a $129.3 million net reduction in amounts due to related parties, while in 2009 no similar payments were made and the amounts due to related parties increased by
$103.4 million, reflecting expenses incurred by related parties on our behalf. The increase in operating cash flow also reflects a $94.1 million increase in
income from continuing operations and a $32.3 million increase in deferred income taxes, partially offset by a $26.5 million decrease in non-cash expenses. The decrease in
non-cash expenses is primarily related to amortization expense and interest expense converted to principal.

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The
following table summarizes investing cash flows for the years ended December 31, 2009 and 2008 (in millions):

Year Ended
December 31,

Change2009

2008

$

PercentPurchases of property, plant, and equipment

$
119.7

$
138.1


(18.4
)

(13.3
)Other investing activities, net


297.4


15.6


281.8


181.0Cash used in investing actives from continuing operations

$
417.1

$
153.7


263.4


171.4


The
increase in cash used in investing activities from continuing operations was primarily the result of a $182.5 million increase in amounts invested in the Rio Tinto America
cash management program, an $80.2 million increase in restricted cash and a $21.4 million decrease in net receipts of refundable deposits related to coal reserve acquisition bids
partially offset by a $18.4 million decrease in purchases of property, plant and equipment.

The
following table summarizes financing cash flows for the years ended December 31, 2009 and 2008 (in millions):

Year Ended December 31,

Change2009

2008

$

PercentCash used in financing actives from continuing operations

$
582.2

$
2.9


579.3


*
  *Change
from prior period is not a relevant percentage


The
increase in cash used in financing activities from continuing operations is primarily attributable to approximately $1.52 billion in distributions to Rio Tinto,
$764.1 million of which represented the proceeds from the sale of the Jacobs Ranch mine, $309.7 million of which was funded by the proceeds of our senior notes offering, and
$433.8 million represented the net proceeds from our IPO. Also contributing to the use of cash was a $29.2 million increase in payments on long-term debt, including federal
coal leases, and net borrowings and repayments on the RTA Facility during the year ended December 31, 2008 that did not occur in 2009. Partially offsetting these increases was $568.7 in net
proceeds from our senior notes offering.



Net cash provided by operating activities from discontinued operations was $36.0 million and $50.3 million for the years
ended December 31, 2009 and 2008, respectively. The $14.3 million decrease in net cash provided by operating activities from discontinued operations for the year ended
December 31, 2009 compared to 2008 was due primarily to an increase in royalty and production tax payments.

Net
cash provided by investing activities from discontinued operations was $759.0 million for the year ended December 31, 2009, compared to net cash used in investing
activities from discontinued operations of $41.2 million for the year ended December 31, 2008. Our 2009 cash flows reflect proceeds of $764.1 million from the sale of the Jacobs
Ranch mine, which was completed on October 1, 2009.

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There
was no cash used or provided from financing activities for discontinued operations during 2009 due to the absence of Colowyo financing activities as a result of the October 2008
disposal of Colowyo.



We refer to the $300.0 million senior notes due December 15, 2017 (the "2017 Notes") and the $300.0 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 our IPO structuring transactions, we distributed $309.7 million of the net proceeds 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.



Concurrent with the offering of the senior notes, we entered into a $400.0 million senior secured revolving credit facility, or
credit facility, with a syndicate of lenders, the full amount of which is available for use in connection with loans or the issuance of letters of credit. Our obligations under the credit facility are
supported by a guarantee by our domestic restricted subsidiaries. The credit facility matures on December 16, 2013. As of December 31, 2010, there were no amounts drawn under the credit
facility and $10.5 million was committed in connection with the issuance of letters of credit. The letters of credit are used as collateral to secure our obligations to reclaim lands used for
mining. See "Off-Balance Sheet Arrangements" below.

Loans
under the credit facility bear interest at the greater of the LIBOR or 2.50%, plus an applicable margin based on our credit rating of between 3.25% and 4.25% depending on our
credit rating (4.00% at December 31, 2010). We are required to pay the lenders a commitment fee of 0.75% per year on the unused amount of the credit facility. Letters of credit issued under the
credit facility, unless drawn upon, will bear interest at the applicable margin for LIBOR loans from the date at which they are issued. In addition, in connection with the issuance of a letter of
credit we will be required to

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pay
the issuing bank a fronting fee of 0.25% plus additional customary administrative fees and expenses.

Our
obligations under the credit facility are secured by substantially all of our assets and substantially all of the assets of certain of our subsidiaries, subject to certain permitted
liens and to customary exceptions for similar coal financings. We are subject to financial maintenance covenants based on EBITDA (which is defined in the credit agreement and is not the same as EBITDA
or Adjusted EBITDA presented elsewhere in this report) requiring us to maintain defined minimum levels of interest coverage and providing for a limitation on our total and first lien senior secured
debt leverage ratios. Specifically, the credit agreement requires us to maintain a ratio of EBITDA to consolidated net cash interest expense equal to or greater than 2.75 to 1, a ratio of funded debt
to EBITDA equal to or less than 3.5 to 1, and a ratio of first lien senior secured debt to EBITDA equal to or less than 1.5 to 1 as long as the credit facility is in effect.

Our
credit facility also requires us to comply with non-financial covenants that restrict certain corporate activities and certain of our subsidiaries and contains customary
events of default with customary grace periods and thresholds. These covenants include restrictions on our ability to incur additional debt and pay dividends, among other restrictive covenants. Our
ability to access the available funds under our credit facility may be impaired in the event that we do not comply with the covenant requirements or if we default on our obligations under the
agreement. In addition, under the terms of our credit facility, a change in control of Cloud Peak Energy Inc. or CPE Resources will result in an automatic event of default and, unless waived by
the required lenders, will result in all obligations under the agreement becoming immediately due and payable. At December 31, 2010, we were in compliance with the covenants contained in our
credit facility.



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 total $133.2 million, with $63.8 million due in 2011, $59.8 million due in 2012 and
$9.6 million due in 2013. We recognize imputed interest on federal coal leases based on an estimate of the credit-adjusted, risk-free rate reflecting our estimated
credit rating at the inception of the lease. The outstanding principal balance of our federal coal lease obligations was $118.3 million as of December 31, 2010.

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. While we were a subsidiary of Rio Tinto, Rio Tinto maintained our surety bonds and
facilitated the issuance of letters of credit on our behalf. Pursuant to our IPO Structuring Agreements, we agreed to use our commercially reasonable efforts to obtain new surety bonds, letters of
credit or other credit arrangements and to obtain the full release of Rio Tinto with respect to any existing arrangements.

As
of December 31, 2009, with the exception of our obligations with respect to Decker, Rio Tinto remained the guarantor and we maintained $80.2 million in restricted cash
as collateral for the benefit of Rio Tinto. We completed the replacement of surety bonds and letters of credit provided by Rio

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Tinto
on our behalf during 2010. These surety bonds are collateralized by a restricted cash balance of $182.1 million.

As
of December 31, 2010, we used surety bonds and letters of credit to secure outstanding obligations as follows (in millions):

Surety
Bonds

Letters of
Credit

TotalReclamation obligations(1)

$
492.6

$
10.5

$
503.1Lease obligations(2)


32.3





32.3Other obligations(3)


0.1





0.1Total off-balance sheet obligations

$
525.0

$
10.5

$
535.5Collateralized by:Restricted cash(4)

$
182.1

$


$
182.1


(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. Includes $74.2 million representing our 50% share of surety bonds securing Decker's reclamation obligations and $10.5 million in letters
of credit issued under our revolving credit facility to secure our 50% share of additional Decker 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 and other miscellaneous items as mandated by the
applicable governing agencies.(4)We
are required to collateralize 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 and lease obligations were $525.0 million at December 31, 2010 (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 asset retirement obligation, or 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 must be calculated for the highest cost scenario over that period.

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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 $182.2 million at December 31, 2010, $6.6 million of which is payable in 2011. We estimate our ARO liabilities based on disturbed acreage to
date and third party cost estimates. 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 perform
reclamation concurrently with our mining activities. We have estimated that we will perform concurrent reclamation of approximately $5.9 million during 2011. Concurrent reclamation is performed
on an annual basis as a part of our normal mining operations. Finally, the carrying amount of our ARO liabilities reflects discounting of estimated reclamation costs using a credit-adjusted
risk-free interest rate. 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 or be incurred
sooner 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 and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors including lack of
availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety 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 17 of Notes to Consolidated Financial Statements in Item 8.

Contractual Obligations

As of December 31, 2010, we had the following contractual obligations (in millions):

Total

2011

2012 - 2013

2014 - 2015

2016 and ThereafterSenior notes(1)

$
600.0

$


$


$


$
600.0Coal lease obligations(2)


123.1


56.1


67.0





Interest related to long-term debt(3)


418.2


59.7


106.5


100.5


151.5Operating and capital lease obligations


8.7


0.8


1.6


1.6


4.7Coal purchase obligations(4)


10.7


10.7








Capital expenditure obligations(4)


13.1


9.6


3.5





Total

$
1,173.8

$
136.9

$
178.6

$
102.1

$
756.2


(1)CPE
Resources issued $600.0 million aggregate principal amount of senior notes in two tranches due 2017 and 2019. CPE Resources also has entered into
a $400.0 million four-year revolving credit facility, none of which had been drawn as of December 31, 2010. See Note 9 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 10
of Notes to Consolidated Financial Statements in Item 8.(3)As
of December 31, 2010, 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 9 and 10 of Notes to Consolidated Financial Statements in Item 8.


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(4)As
of December 31, 2010, we had outstanding commitments for coal purchases and capital expenditures which are not included on consolidated balance
sheet. See Note 17 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) as determined in accordance with U.S. GAAP is $188.8 million as
of December 31, 2010. See Note 11 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 $190.1 million liability for our estimated payments to RTEA
under the Tax Receivable Agreement, of which $18.2 million and $171.9 million is classified as current and noncurrent, respectively, as of December 31, 2010. The estimated
liability is based on forecasts of future taxable income over the anticipated life of our mining operations and reclamation activities, 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, 2010, we expect to make payments of $18.2 million in 2011 and payments averaging approximately
$24.5 million during 2012 to 2015. See Item 1A "Risk FactorsRisks Related to Our Corporate StructureWe are required to
pay RTEA for most of the tax benefits we may claim as a result of the tax basis step-up we received in connection with our IPO, related IPO structuring transactions and the 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

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the U.S. These
accounting principles require 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. 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

Revenues from coal sales are recognized when a customer takes delivery of our coal, which usually occurs at the time of shipment from
our mine. 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

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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 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 at fair value, or the amount at which we estimate we could transfer our future reclamation obligations to informed and willing third parties. We use
estimates of future third party costs to arrive at the AROs because the fair value of such costs generally reflects a profit component. It has been our practice, and we anticipate it will continue to
be our practice, to perform a substantial portion of the reclamation work using internal resources. Hence, the estimated costs used in determining the carrying amount of our AROs may exceed the
amounts that are eventually paid for reclamation costs if the reclamation work is performed using internal resources.

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 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 an adjusted, risk-free interest rate based on U.S. Treasury bonds with a maturity similar to
the expected life of the mine.

The
amount initially 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 increase in estimated reclamation costs using an adjusted,
risk-free interest rate based on U.S. Treasury bonds with a maturity similar to the expected remaining life of the mine. Adjustments to the ARO for decreases in the estimated amount of
reclamation costs are measured using an adjusted, risk-free interest rate as of the date of the initial recognition of the ARO. Annually, we analyze AROs on a
mine-by-mine basis and, if necessary, adjust the balance to take into account any changes in estimates.

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 long-term debt. 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 long-term debt, 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 rate 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 long-term debt 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.

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Income Taxes and Tax Agreement Liability

Our consolidated deferred tax assets as of December 31, 2010 were $162.5 million, net of a $94.6 million valuation
allowance. 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.
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 historical operations, the effects of the structuring and financing transactions completed in connection with our 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.

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 pre-tax income, and may also result in corresponding adjustments to our income tax expense and deferred income
tax accounts.
Acquisitions of additional coal leases 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 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 its 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.

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 and interest rate risk.

Commodity Price Risks

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, rather than through the use of derivative instruments.

We
also face price risk involving other commodities used in our production process such as 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

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$9 million
over the next twelve months. Historically, we have not hedged commodities such as diesel fuel. We may enter into hedging arrangements in the future.

Interest Rate Risk

Our credit facility 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, 2010. 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.

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Item 8.Financial Statements and Supplementary Data.

Report of Independent Registered Public Accounting Firm

To
the Board of Directors and Shareholders 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in
the period ended December 31, 2010 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, 2010, based on criteria established inInternal ControlIntegrated
Frameworkissued 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 was an integrated audit in 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.

PricewaterhouseCoopers LLP
Denver, Colorado
February 24, 2011

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands, except per share amounts)

Year Ended December 31,2010

2009

2008Revenues

$
1,370,761

$
1,398,200

$
1,239,711Costs and expensesCost of product sold (exclusive of depreciation, depletion, amortization and accretion, shown separately)


978,914


933,489


894,036Depreciation and depletion


100,023


97,869


88,972Amortization


3,197


28,719


45,989Accretion


12,499


12,587


12,742Selling, general and administrative expenses


63,594


69,835


70,485Asset impairment charges


659


698


2,551Total costs and expenses


1,158,886


1,143,197


1,114,775Operating income


211,875


255,003


124,936Other income (expense)Interest income


565


320


2,865Interest expense


(46,938
)

(5,992
)

(20,376
)Tax agreement expense


(19,669
)




Other, net


157


9


1,715Total other expense


(65,885
)

(5,663
)

(15,796
)Income from continuing operations before income tax provision and earnings from unconsolidated affiliates


145,990


249,340


109,140Income tax provision


(31,982
)

(68,249
)

(25,318
)Earnings from unconsolidated affiliates, net of tax


3,189


1,381


4,518Income from continuing operations


117,197


182,472


88,340Income (loss) from discontinued operations, net of tax





211,078


(25,215
)Net income


117,197


393,550


63,125Less: Net income attributable to noncontrolling interest


83,460


11,849


Net income attributable to controlling interest

$
33,737

$
381,701

$
63,125Amounts attributable to controlling interest common shareholders:Income from continuing operations

$
33,737

$
170,623

$
88,340Income (loss) from discontinued operations





211,078


(25,215
)Net income

$
33,737

$
381,701

$
63,125Earnings (loss) per common share attributable to controlling interest:BasicIncome from continuing operations

$
0.98

$
3.01

$
1.47Income (loss) from discontinued operations





3.73


(0.42
)Net income

$
0.98

$
6.74

$
1.05Weighted-average shares outstandingbasic


34,305,205


56,616,986


60,000,000DilutedIncome from continuing operations

$
0.98

$
2.97

$
1.47Income (loss) from discontinued operations





3.52


(0.42
)Net income

$
0.98

$
6.49

$
1.05Weighted-average shares outstandingdiluted


34,305,205


60,000,000


60,000,000


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

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands, except share data)

December 31,2010

2009ASSETSCurrent assetsCash and cash equivalents

$
340,101

$
268,316Restricted cash


182,072


80,180Accounts receivable


65,173


82,809Due from related parties


434


8,340Inventories


64,970


64,199Deferred income taxes


21,552


280Other assets


17,449


7,321Total current assets


691,751


511,445Non-current assetsProperty, plant and equipment, net


1,008,337


987,143Intangible assets, net





3,197Goodwill


35,634


35,634Deferred income taxes


140,985


100,520Other assets


38,400


39,657Total assets

$
1,915,107

$
1,677,596LIABILITIES AND EQUITYCurrent liabilitiesAccounts payable

$
81,975

$
57,304Royalties and production taxes


127,038


102,912Accrued expenses


51,197


47,763Current portion of tax agreement liability


18,226


758Current portion of federal coal lease obligations


54,630


50,768Other liabilities


4,880


4,514Total current liabilities


337,946


264,019Non-current liabilitiesTax agreement liability, net of current portion


171,885


53,751Senior notes


595,684


595,321Federal coal lease obligations, net of current portion


63,659


118,289Asset retirement obligations, net of current portion


182,170


175,940Other liabilities


32,564


24,798Total liabilities


1,383,908


1,232,118Commitments and contingencies (Note 17)EquityCommon stock ($0.01 par value; 200,000,000 shares authorized; 60,878,317 and 31,449,002 shares issued and outstanding at December 31, 2010 and 2009,
respectively)


609


314Additional paid-in capital


502,952


251,083Retained earnings


42,296


8,459Accumulated other comprehensive loss


(14,658
)

(6,951
)Total Cloud Peak Energy Inc. shareholders' equity


531,199


252,905Noncontrolling interest





192,573Total equity


531,199


445,478Total liabilities and equity

$
1,915,107

$
1,677,596


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

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

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
InterestShares

Amount

TotalBalances at December 31, 2007




$


$


$


$
(1,738
)
$
336,699

$


$
334,961Comprehensive incomeNet income











(116
)




63,241





63,125Decker pension adjustments, net of tax














(2,770
)







(2,770
)Total comprehensive income























60,355Stock compensation

















1,033





1,033Dividend to former parent

















(3,956
)




(3,956
)Conversion of RTA Facility to equity

















547,382





547,382Costs incurred by affiliates

















31,216





31,216Pension transition adjustment, net of tax

















(687
)




(687
)Discontinued operations distribution

















14,862





14,862Balances at December 31, 2008











(116
)

(4,508
)

989,790





985,166Comprehensive incomeNet income











8,575





373,126


11,849


393,550Decker pension adjustments, net of tax














707





1,032


1,739Retiree medical plan initiation and adjustment, net of tax














(5,299
)




(7,741
)

(13,040
)Total comprehensive income























382,249Stock compensation








785








1,180





1,965Cash distribution to former parent

















(8,477
)




(8,477
)Costs incurred by affiliates

















8,542





8,542Distribution of Jacobs Ranch mine sale proceeds

















(764,122
)




(764,122
)IPO structuring transactions








46,430





1,327


(3,815
)




43,942IPO 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





105,917Noncontrolling interest








(190,879
)




3,446





187,433


Balances at December 31, 2009


31,449


314


251,083


8,459


(6,951
)




192,573


445,478Comprehensive incomeNet income











33,737








83,460


117,197Retiree medical plan adjustment, net of tax














(1,625
)




654


(971
)Total comprehensive income























116,226Adjustment to beginning balance, Tax Receivable Agreement








2,414














2,414Stock compensation








7,234














7,234Restricted 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


60,978

$
609

$
502,952

$
42,296

$
(14,658
)
$


$


$
531,199


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

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

Year Ended December 31,2010

2009

2008Operating activitiesNet income

$
117,197

$
393,550

$
63,125Adjustments to reconcile income to net cash provided by operating activities:Income or loss from discontinued operations, net of tax





(211,078
)

25,215Depreciation and depletion


100,023


97,869


88,972Amortization


3,197


28,719


45,989Accretion


12,499


12,587


12,742Asset impairment charges


659


698


2,551Earnings from unconsolidated affiliates


(3,189
)

(1,381
)

(4,518
)Distributions of income from equity investments


35


4,000


4,750Deferred income taxes


28,503


13,595


(18,697
)Expenses paid by affiliates








31,216Stock compensation expense


7,234


1,919


727Change in tax agreement liability


19,669





Interest expense converted to principal








16,755Other, net


4,718


750


1,336Changes in operating assets and liabilities:Accounts receivable, net


17,636


(3,358
)

12,609Inventories


(638
)

(7,638
)

(5,707
)Due to or from related parties


7,906


103,414


(129,252
)Other assets


(10,090
)

(1,097
)

(4,377
)Accounts payable and accrued expenses


27,040


28,890


9,715Tax agreement liability


(1,685
)




Asset retirement obligations


(5,938
)

(4,855
)

(3,151
)Net cash provided by operating activities from continuing operations


324,776


456,584


150,000Investing activitiesPurchases of property, plant and equipment


(91,639
)

(119,742
)

(138,104
)Payment on refundable deposit








(11,806
)Return of refundable deposit








33,156Return of restricted cash


116,533





Restricted cash deposit


(218,425
)

(80,180
)

Change in cash advances to affiliate





(217,468
)

(35,025
)Other, net


1,511


313


(1,880
)Net cash used in investing activities from continuing operations


(192,020
)

(417,077
)

(153,659
)Financing activitiesBorrowings on long-term debt





595,284


40,000Principal repayments on federal coal leases


(50,768
)

(68,583
)

(39,415
)Payment of debt issuance costs





(26,585
)

Proceeds from issuance of common stock





433,755


Distributions to Rio Tinto


(10,203
)

(1,516,058
)

(3,448
)Net cash used in financing activities from continuing operations


(60,971
)

(582,187
)

(2,863
)Net cash provided by (used in) continuing operations


71,785


(542,680
)

(6,522
)Cash flows from discontinued operationsNet cash from operating activities





36,029


50,320Net cash from investing activities





759,032


(41,231
)Net cash from financing activities








(10,248
)Net cash provided by (used in) discontinued operations





795,061


(1,159
)Net increase (decrease) in cash and cash equivalents


71,785


252,381


(7,681
)Cash and cash equivalents at beginning of year


268,316


15,935


23,616Cash and cash equivalents at end of year

$
340,101

$
268,316

$
15,935Supplemental cash flow disclosures for continuing operations:Interest paid

$
69,317

$
17,606

$
4,410Income taxes paid (refunded), net


9,120


79,089


(348
)Supplemental noncash investing and financing activities from continuing operations:Obligations to acquire federal coal leases and other mineral rights

$


$
37,424

$
168,009Conversion of debt to equity








547,382Noncash capital contributions from Rio Tinto America





158,400


46,078


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

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1. Organization and Business

Cloud Peak Energy Inc. ("CPE Inc.") was incorporated in Delaware on July 31, 2008 and had no business operations prior to November 19, 2009, when it acquired
its coal business in connection with the initial public offering of its common stock ("IPO"). Prior to its IPO, CPE Inc. was a wholly-owned subsidiary of Rio Tinto America Inc. ("Rio
Tinto America") and was an indirect subsidiary of Rio Tinto plc ("Rio Tinto"), one of the largest mining companies in the world. CPE Inc. used the net proceeds from its IPO to repay a
promissory note that was issued on November 19, 2009 in exchange for the managing member interest in Cloud Peak Energy Resources LLC ("CPE Resources") from Rio Tinto Energy
America Inc. ("RTEA"), a wholly-owned subsidiary of Rio Tinto America that historically had operated Rio Tinto's western United States ("U.S.") coal business. CPE Resources was formed as Rio
Tinto Sage LLC on August 19, 2008 and was renamed Cloud Peak Energy Resources LLC in November 2009. RTEA was formed in March 1993 as Kennecott Coal Company and was renamed Rio
Tinto Energy America Inc. in May 2006. Prior to the IPO, RTEA had contributed to CPE Resources substantially all of the assets used in Rio Tinto's western U.S. coal business.

On
December 15, 2010, Cloud Peak Energy Inc. priced a secondary offering of 29,400,000 shares of its common stock on behalf of Rio Tinto. In connection with the secondary
offering, we exchanged 29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the secondary offering on behalf of Rio Tinto (the "Secondary
Offering"), resulting in a divestiture of 100% of Rio Tinto's holdings in CPE Resources. As a result of this transaction, CPE Resources is now a wholly-owned subsidiary of Cloud Peak Energy Inc, and
Rio Tinto no longer holds an interest in CPE Resources.

Through
CPE Resources and its subsidiaries, CPE Inc. engages in coal mining operations in the Powder River Basin ("PRB"), the lowest cost coal producing region in the U.S., and
operates two of the four
largest coal mines in the region and in the U.S. CPE Resources operates three surface coal mines, of which two are in Wyoming and one is in Montana, and owns a 50% interest in another surface coal
mine in Montana. CPE Resources produces sub-bituminous steam coal with low sulfur content and sells the coal primarily to electric utility companies, which use the coal as fuel for
electricity generation.

"Cloud
Peak Energy," "we," "us," "our" or the "Company" refer collectively to CPE Inc., CPE Resources and their consolidated subsidiaries. Those terms also include RTEA with
respect to periods prior to our IPO, when RTEA was the parent company of CPE Resources and its subsidiaries.

2. Basis of Presentation

Principles of Consolidation

Our consolidated financial statements present the financial position, results of operations and cash flows of our business, which was
controlled by Rio Tinto, through RTEA, prior to our IPO and by CPE Inc. thereafter. For dates and periods prior to our IPO, our consolidated financial statements present RTEA as the parent
company (the "former parent") and reflect allocations of certain costs incurred by other Rio Tinto affiliates. For dates and periods following our IPO but preceding our Secondary Offering, our
consolidated financial statements present CPE Inc. as the parent company and present Rio Tinto's remaining interest in CPE Resources as a noncontrolling interest. Dates and periods following
our Secondary Offering present CPE Inc. as the sole owner in CPE Resources.

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We
consolidate the accounts of entities in which we have a controlling financial interest under the voting control model and consolidate the accounts of variable interest entities for
which we are the primary beneficiary. We account for our 50% interest in Decker Coal Company ("Decker") using the proportionate consolidation method, whereby our share of Decker's assets, liabilities,
revenues and expenses are included in our consolidated financial statements. Investments in other entities that we do not control but have the ability to exercise significant influence over the
investee's operating and financial policies, are accounted for under the equity method. The consolidated financial statements have been prepared in conformity with accounting principles generally
accepted in the U.S. ("U.S. GAAP"). All intercompany balances and transactions have been eliminated in the consolidated financial statements.

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



In anticipation of an IPO or divestment transaction, substantially all assets used in Rio Tinto's western U.S. coal business were
transferred to CPE Resources during 2008 and 2009, including Cloud Peak Energy Services Company (formerly known as Rio Tinto Energy America Services Company), or CPESC, which employs personnel who
operate the business of CPE Resources. On November 17, 2009, CPE Resources declared a cash distribution to RTEA in anticipation of its senior notes offering (see Note 9). CPE Resources
made payments to RTEA totaling $309.7 million pursuant to this declaration and a related working capital adjustment prior to December 31, 2009. These distributions were charged to former
parent's equity. On November 19, 2009, CPE Inc. completed the initial public offering of its common stock. Our IPO resulted in the issuance of 30,600,000 shares at an offering price of
$15.00 per share and generated net proceeds of $433.8 million, after deducting offering costs of $25.2 million. CPE Inc. used the net proceeds to repay a promissory note that was
issued to acquire from RTEA 30,600,000 common membership units in CPE Resources, representing 51.0% of the 60,000,000 common membership units outstanding as of November 19, 2009. RTEA and a Rio
Tinto affiliate retained the remaining 49.0% interest in CPE Resources. The CPE Resources limited liability company agreement was amended in connection with our IPO to designate CPE Inc. as the
managing member of CPE Resources. As amended, the limited liability company agreement provided for CPE Inc., as managing member, to control the activities of CPE Resources.

In
connection with our IPO, CPE Inc., CPE Resources, RTEA and other Rio Tinto affiliates entered into transactions pursuant to several agreements that affected certain existing
obligations of the respective parties and required adjustments to certain assets and liabilities of CPE Resources. These transactions were arranged while the parties were under common control by Rio
Tinto and, accordingly, were accounted for as equity transactions, resulting in a $3.8 million charge to former parent's equity.

Following
the IPO, CPE Inc. recognized deferred tax assets totaling $105.3 million based on the excess of the increased tax basis over the related carrying amount of the
interest for financial reporting, which did not change as a result of our IPO structuring transactions. In addition, CPE Inc. and RTEA entered into a Tax Receivable Agreement, pursuant to which
CPE Inc. generally is required to pay to RTEA 85% of the income tax savings that it realizes in the future from the increase in tax basis. See "Tax Receivable Agreement" in Note 17.
CPE Inc. recognized an initial $54.5 million undiscounted liability for the amounts it expected to pay RTEA under this agreement. The increase in tax basis and

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the
obligation pursuant to the Tax Receivable Agreement were arranged while CPE Inc. and RTEA were under common control by Rio Tinto. Accordingly, the $50.8 million net effect of these
transactions was recognized in equity, including $4.4 million related to unrecognized pension and postretirement benefit costs, which were credited to several components of accumulated other
comprehensive income, and the remainder of $46.4 million, which was credited to additional paid-in capital.

CPE Inc.
and RTEA were under common control by Rio Tinto at the time CPE Inc. acquired the controlling interest in CPE Resources from RTEA. In accordance with
U.S. GAAP, we did not adjust the carrying amounts of the assets and liabilities of CPE Resources as a result of this transfer. The $433.8 million net proceeds from our IPO are reported
in the consolidated statement of equity as increases in common stock and additional paid-in capital, and the corresponding payment to RTEA to repay a promissory note that was issued to
acquire the controlling interest in CPE Resources is reported as a distribution in former parent's equity. These reported amounts exceed the carrying amount of the transferred interest in the
underlying net assets of CPE Resources on the date of transfer by $38.7 million. Accordingly, the consolidated statement of equity reflects offsetting adjustments of $38.7 million to
additional paid-in capital and former parent's equity to reduce the reported IPO proceeds and distribution amounts to reflect the carrying amounts of the underlying net assets of CPE
Resources.

As
a result of CPE Inc.'s acquisition of the controlling interest in CPE Resources from RTEA, effective November 19, 2009, RTEA was no longer our parent company. The
consolidated statement of equity includes a $108.5 million increase in former parent's equity to reflect the elimination of RTEA's accounts, consisting primarily of deferred income tax
liabilities, accrued royalties and production taxes related to the Jacobs Ranch mine and payables to other Rio Tinto affiliates. In addition, a $2.6 million charge to accumulated other
comprehensive loss was recorded to reflect the derecognition of certain tax benefits that RTEA previously had recognized in other comprehensive income.



On December 15, 2010, Cloud Peak Energy Inc. priced the Secondary Offering of 29,400,000 shares of its common stock on
behalf of Rio Tinto. In connection with the Secondary Offering, we exchanged 29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the
Secondary Offering, resulting in a divestiture of 100% of Rio Tinto's holdings in CPE Resources. As a result of this transaction, CPE Resources is now a wholly-owned subsidiary of Cloud Peak
Energy Inc., and Rio Tinto no longer holds any interest in CPE Resources. The elimination of Rio Tinto as a member results in the elimination of noncontrolling interest as of
December 31, 2010. The statement of operations for the year ended December 31, 2010 presents the portion of income attributable to the noncontrolling interest through the date of the
Secondary Offering and no income will be attributable to the noncontrolling interest in future periods. The Secondary Offering also resulted in an increase to the undiscounted future liability under
the Tax Receivable Agreement of $123.6 million and an increase to our deferred income taxes net of valuation allowance of $93.6 million.

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Variable Interest Entities

A variable interest entity ("VIE") generally is an entity that is designed to have one or more of the following characteristics:
(a) the total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support; (b) as a group, the holders of
equity at risk do not have all the characteristics of a controlling financial interest in the entity; or (c) the equity investors have voting rights that are not proportional to their economic
interests and substantially all of the entity's activities either involve, or are conducted on behalf of, an investor that has disproportionately few voting rights. A VIE is required to be
consolidated in the financial statements of the entity that is determined to hold a controlling financial interest in the VIE. A controlling financial interest is defined as the power to direct the
activities of a VIE that most significantly influence the VIE's economic performance and the obligation to absorb the losses of or receive the benefits from the VIE that could potentially be
significant to the VIE.

Prior
to our IPO, RTEA was the primary beneficiary of Cloud Peak Energy Services Company ("CPESC"), which was an indirect wholly-owned subsidiary of Rio Tinto America. We determined that
CPESC was a VIE, primarily because substantially all of CPESC's activities were conducted on behalf of RTEA. We determined that RTEA was the primary beneficiary of CPESC, because RTEA was the
Rio Tinto affiliate that was most closely associated with CPESC. As a result, RTEA included CPESC in its consolidated financial statements prior to our IPO. In connection with our IPO structuring
transactions, Rio Tinto America contributed CPESC to CPE Resources and we consolidated CPESC based on voting control. Subsequent to the Secondary Offering, CPESC is consolidated as a wholly-owned
subsidiary.

Prior
to October 7, 2008, we were the primary beneficiary of Colowyo Coal Company, L.P. ("Colowyo"), a VIE with coal mining operations in Colorado. We distributed our
equity interests in Colowyo to Rio Tinto America on October 7, 2008, and report the operations of Colowyo prior to that date in discontinued operations (see Note 4).

Pre-IPO Expense Allocations

For periods prior to our IPO, our consolidated financial statements include allocations of certain general and administrative expenses
incurred by Rio Tinto America and other Rio Tinto affiliates. Rio Tinto America provided various services and other support to the Company, including tax, treasury, corporate secretary, legal,
procurement, information systems and technology, human resources, accounting and insurance/risk management in the ordinary course of business. RTA charged the Company for such services on a unit cost
or cost allocation basis, such as per invoice processed, proportion of information technology users, share of time or based on a combination of factors, including revenue, operating expenses and head
count. Our consolidated financial statements for periods prior to our IPO also reflect allocations of Rio Tinto's headquarters costs, including costs for technology and innovation, corporate
governance, community and external relations, investor relations, human resources and Rio Tinto's Energy and Minerals product group. The allocations were based on a percentage of operating expenses or
revenue. We believe that the allocation methodologies reflected in these consolidated financial statements, as described above, were reasonable; however, the allocated expenses are not necessarily
indicative of the expenses that would have been incurred if we had been a separate, independent entity.

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Our
consolidated statements of operations include allocations of general and administrative expenses incurred by Rio Tinto America and other Rio Tinto affiliates totaling
$20.7 million and $25.4 million for the years ended December 31, 2009 and 2008, respectively. Of these amounts, $15.8 million and $21.0 million for the years ended
December 31, 2009 and 2008, respectively, are included in selling, general and administrative expenses. The remaining $4.9 million and $4.4 million for the years ended
December 31, 2009 and 2008, respectively, are included in cost of product sold. Also included in selling, general and administrative expenses are costs incurred as a result of actions to divest
RTEA, either
through a trade sale or an initial public offering, of $18.3 million and $25.8 million for the years ended December 31, 2009 and 2008, respectively.

Reclassifications

Certain amounts in the 2009 and 2008 consolidated financial statements have been reclassified to conform to the 2010 presentation.

3. Critical and Significant Accounting Policies

The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires our
management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting periods. Significant estimates in these consolidated financial statements include allowances for inventory obsolescence, share-based
compensation expense, useful lives of long-lived assets, assumptions about the amount and timing of future cash flows and related discount rates used in determining asset retirement
obligations and in testing long-lived assets and goodwill for impairment, the recognition and measurement of income tax benefits and related deferred tax asset valuation allowances, and
assumptions about the timing of future cash flows used in determining the tax agreement liability. Actual results could differ materially from those estimates.

Critical Accounting Policies

We consider certain accounting policies to be critical, as their application requires management's judgment about the effects of
matters that are inherently uncertain. Following is a discussion of the accounting policies we consider critical to 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.

Coal
sales revenues include sales to customers of coal produced at our facilities and coal purchased from other companies. Coal sales are made to our customers under the terms of coal
supply agreements, most of which have a term greater than one year. Under the typical terms of these coal supply agreements, title and risk of loss transfer to the customer at the time the coal is
shipped, which is the point at which revenue is recognized. Certain contracts provide for title and risk of loss transfer at the point of destination, in which case revenue is recognized when it
arrives at its destination.

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Coal
sales contracts typically contain coal quality specifications. With coal quality specifications in place, the raw coal sold by us to the customer at the delivery point must be
substantially free of magnetic material and other foreign material impurities, and crushed to a maximum size as set forth in the respective coal sales contract. Prior to billing the customer, price
adjustments are made based on quality standards that are specified in the coal sales contract, such as British thermal unit factor, moisture, ash and sodium content, and can result in either increases
or decreases in the value of the coal shipped.

Transportation
costs are included in cost of product sold, and amounts we bill to our customers for transportation are included in revenues.

Asset Retirement Obligations and Remediation Costs

We recognize liabilities for asset retirement obligations ("AROs") where we have legal obligations associated with the retirement of
long-lived assets. We recognize AROs at fair value at the time the obligations are incurred. The Company's AROs generally are incurred when a mine site is disturbed by mining activities
and as the extent of disturbance increases. AROs reflect costs associated with legally required mine reclamation and closure activities, including earthwork, revegetation and demolition and are
estimated based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are adjusted for
estimated inflation and discounted at an adjusted, risk-free rate. The ARO amount is capitalized as part of the related mining property upon initial recognition and is included in
depreciation and depletion expense using the units-of-production method based on proven and probable reserves. As changes in estimates occur (such as changes in estimated costs
or timing of reclamation activities resulting from mine plan revisions), the ARO liability and related asset are adjusted to reflect the updated estimates. Increases in ARO liabilities resulting from
the passage of time are recognized as accretion expense by applying the adjusted, risk-free rate that existed when the liability was initially measured to the amount of the liability at
the beginning of the period. Other costs related to environmental remediation are charged to expense as incurred. When the 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.

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 increase in estimated reclamation costs using an adjusted, risk-free interest rate based on U.S. Treasury bonds with a maturity similar to the
expected remaining life of the mine. Adjustments to the ARO for decreases in the estimated amount of reclamation costs are measured using an adjusted, risk-free interest rate as of the
date of the initial recognition of the ARO.

Coal Reserves, Mineral Rights, and Federal Coal Leases

We state our coal reserves at cost, less accumulated depletion. The cost of coal reserves includes, where applicable, the present value
of payments required under leases that convey mineral rights, based on our estimate of the credit-adjusted, risk-free interest rate at inception of the lease. We compute depletion of coal
reserves and mineral rights using the units-of-production method based on proven

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and
probable reserves. Coal reserves and mineral rights are included in land, improvements and mineral rights in property, plant and equipment, net.

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 long-term debt. 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 long-term debt, 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 rate 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 long-term debt 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

We account for income taxes using a balance sheet approach in accordance with U.S. GAAP. Deferred income taxes are provided for
temporary differences arising from differences between the financial statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates expected to be in
effect when the related taxes are expected to be paid or recovered. A valuation allowance is established if it is more likely than not that a deferred tax asset will not be realized. In determining
the appropriate valuation allowance, we consider projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies and our overall deferred tax
position. We recognize the benefit of uncertain tax positions at the greatest amount that is determined to be more likely than not of being realized. Interest and penalties related to income tax
matters are included in income tax expense in the consolidated statements of operations.

Prior
to our IPO, we were a member of a consolidated federal tax group and were party to a federal tax sharing agreement with the other members of the consolidated federal tax group.
However, for the purposes of our pre-IPO consolidated financial statements, which were prepared on a carve-out basis, our current and deferred income taxes were calculated on a
stand-alone income tax return basis. Differences arose as a result of computing our federal income taxes pursuant to the federal tax sharing agreement and on a stand-alone income tax return basis for
the carve-out consolidated financial statements. For the year ended December 31, 2008, income taxes recognized in the carve-out consolidated financial statements
exceeded income taxes pursuant to the tax sharing agreement by $29.6 million. This amount is presented as a capital contribution within former parent's equity, as the amount will not be paid by
us.

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Tax Agreement Liability

In connection with our IPO structuring transactions and Secondary Offering (see Note 2), we recognized a liability for the
estimated, undiscounted amounts that we expect to pay RTEA in future years pursuant to the Tax Receivable Agreement, which we generally refer to as the tax agreement liability. The actual amounts
payable under this agreement are determined and paid annually, after CPE Inc. has filed its income tax returns for the prior year. The annual payments are determined based on the difference
between (i) CPE Inc.'s actual income tax liability for the prior year, which reflects the effects of the increase in tax basis that resulted from its acquisition of interests in CPE
Resources, and (ii) a hypothetical calculation of CPE Inc.'s tax liability that assumes no such increase in tax basis. The required annual payments generally are equal to 85% of the tax
savings actually realized as a result of the tax basis increase. Our estimate of the tax agreement liability is based on forecasts of our future income tax payments, with and without the tax basis
increase, over the anticipated life of our mining operations and reclamation activities, assuming no additional coal reserves are acquired. The assumptions used in our forecasts are consistent with
assumptions used in determining the valuation allowance for our deferred tax assets and in other contemporaneous accounting measurements, such as our annual test of goodwill impairment. We revise our
estimated tax agreement liability annually in conjunction with our annual life-of-mine planning process, which typically takes place in the third quarter, or more frequently
when there are significant changes in circumstances, such as the acquisition of additional coal reserves. Future changes in our estimated tax agreement liability will be recognized in other expense in
our consolidated statement of operations. See Note 17 for more information about the Tax Agreement Liability.

Significant Accounting Policies

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Money market funds
that meet all qualifying criteria for a money market fund under the Investment Company Act of 1940 are considered to be cash equivalents.

Restricted Cash

Restricted cash consists of cash and cash equivalents held in accounts that are subject to contractual restrictions on our ability to
withdraw funds. We classify restricted cash as a current asset when we have the contractual right and economic ability to withdraw funds from the restricted cash account within one year from the
balance sheet date. We may use restricted cash balances to collateralize surety bonds that secure our performance under certain of our reclamation obligations. Our surety bonds permit us to provide
cash or letters of credit as collateral. In determining whether we have the ability to withdraw funds from restricted cash accounts, we consider the available capacity under our revolving credit
facility, our forecasted cash flows and other relevant information.

Allowance for Doubtful Accounts Receivable

We determine an allowance for doubtful accounts based on the aging of accounts receivable, historical experience and management
judgment. We write off accounts receivable against the allowance when we determine a balance is uncollectible and we no longer continue to actively pursue collection of

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the
receivable. Based on our assessment of the above criteria, there was no allowance for doubtful accounts at December 31, 2010 and 2009.

Inventories, Net



We state materials and supplies at the lower of average cost or net realizable value. We establish allowances for excess or obsolete
materials and supplies inventory based on prior experience and estimates of future usage.



We state our coal inventory, which consists of coal stockpiles that may be sold in their current condition or may be further processed
prior to shipment to a customer, at the lower of average cost or net realizable value. Net realizable value represents the estimated future sales price based on spot coal prices and prices under
long-term contracts, less the estimated costs to complete production and bring the product to sale. The cost of coal inventory reflects mining costs incurred up to the point of stockpiling
the coal and includes labor, supplies, equipment, applicable operating overhead and depreciation, depletion and amortization related to mining operations.

Property, Plant and Equipment



We state plant and equipment at cost, less accumulated depreciation. Plant and equipment used in mining operations that are expected to
remain in service for the life of the related mine are depreciated using the units-of-production method based on proven and probable reserves. Depreciation of other plant and
equipment is computed using the straight-line method over the following estimated useful lives:

Buildings and improvements

5 to 25 yearsMachinery and equipment

3 to 20 yearsFurniture and fixtures

3 years




We capitalize interest costs on accumulated expenditures incurred in preparing capital projects for their intended use.



We capitalize costs of developing new mines where proven and probable reserves exist. We amortize mine development costs using the
units-of-production method based on proven and probable reserves that are associated with the property being developed. Costs may include construction permits and licenses;
mine design; construction of access roads, slopes and main entries; and removing overburden and waste materials to access the coal ore body in a new pit prior to the production phase, which commences
when saleable coal, beyond a de minimis amount, is produced. Where multiple pits exist at a mining operation, overburden removal costs are capitalized if such costs are for the

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development
of a new area that is separate and distinct from the existing production phase mines. Overburden removal costs that relate to the enlargement of an existing pit are expensed as incurred.
Overburden removal costs incurred during the production phase are included as a cost of inventory to be recognized in cost of product sold in the same period as the revenue from the sale of inventory.
Additionally, mine development costs include the costs associated with asset retirement obligations. Mine development costs are included in land, improvements and mineral rights in property, plant and
equipment, net.



We capitalize costs associated with major renewals and improvements. Expenditures to replace or completely rebuild major components of
major equipment, which are required at predictable intervals to maintain asset life or performance, are capitalized. These major components are capitalized separately from the major equipment and
depreciated according to their own estimated useful life, rather than the estimated useful life of the major equipment. All other costs of repairs and maintenance are charged to expense as incurred.



We expense all direct costs incurred in identifying new resources and in converting resources to reserves at development and production
stage projects. Exploration costs of $0.2 million, $1.2 million and $1.4 million for the years ended December 31, 2010, 2009 and 2008, respectively, are included in cost of
product sold.



We evaluate the recoverability of our long-lived assets when events or changes in circumstances indicate that the carrying
amount of property, plant and equipment may not be recovered over its remaining service life. An asset impairment charge is recognized when the sum of estimated future cash flows associated with the
operation and disposal of the asset, on an undiscounted basis, is less than the carrying amount of the asset. An impairment charge is measured as the amount by which the carrying amount of the asset
exceeds its fair value. Fair value is measured using discounted cash flows based on estimates of coal reserves, coal prices, operating expenses and capital costs or by reference to observable
comparable transaction or replacement cost data.

Intangible Assets

We state intangible assets at cost, less accumulated amortization. The cost of intangible assets consists of the fair value assigned to
favorable long-term coal supply contracts in connection with business combinations and is amortized based on deliveries over the terms of the contracts. Intangible assets are subject to
evaluation for potential impairment if an event occurs or a change in circumstances indicates the carrying amount may not be recoverable. No impairment charges were recorded in 2010, 2009, or 2008.

Goodwill

We assess the carrying amount of goodwill for impairment annually during the fourth quarter, or more frequently if an event occurs or
circumstances change that would more likely than not reduce the

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fair
value of a reporting unit below its carrying amount. We assess goodwill for possible impairment using a two-step method in which we compare the carrying amount of each reporting unit
to its fair value. If the carrying amount of a reporting unit exceeds its fair value, we perform an analysis to determine the fair values of the assets and liabilities of the reporting unit to
determine whether the implied goodwill of that reporting unit has been impaired. We determine the fair value of our reporting units utilizing estimated future discounted cash flows based on estimates
of proven and probable reserves, coal prices and operating costs, consistent with assumptions that we believe marketplace participants would use in their estimates of fair value. The carrying amount
of our goodwill does not include any accumulated impairment losses.

Pensions and Other Postretirement Benefits

Our employees participate in defined contribution retirement plans, which require us to make contributions based on a percentage of
compensation or to match employee contributions, subject to limitations. We recognize compensation expense for our required contributions as incurred.

Prior
to our IPO, our employees, which do not include Decker employees, participated in a defined benefit retirement plan sponsored by Rio Tinto America. Periodic costs pertaining to
this plan were allocated to us by Rio Tinto America on a basis of projected benefit obligation with respect to financing costs and on the basis of actuarial determinations for current and prior
service costs. Our employees ceased to participate in this plan as a result of our IPO, and we have not assumed any pension obligations associated with this plan.

Prior
to our IPO, our employees participated in a defined benefit postretirement welfare plan sponsored by Rio Tinto America. This plan provided for retired employees and their
beneficiaries and dependents who meet eligibility requirements to receive medical, dental and life insurance benefits, subject to certain cost-sharing features, such as deductibles and
coinsurance. We recognized a net periodic postretirement benefit cost for our required contribution to this plan based on actuarial cost data and an allocation from Rio Tinto America. Our employees
ceased to participate in this plan; however, we agreed to sponsor, effective January 1, 2010, a new postretirement medical plan that provides retiree medical benefits for our employees. We
account for postretirement benefits other than pensions by accruing the costs of benefits to be provided over the employees' period of active service. These costs are determined on an actuarial basis.
Our consolidated balance sheets reflect the funded status of postretirement benefits.

Decker's
employees participate in a defined benefit retirement plan sponsored by Decker, which is accounted for in accordance with U.S. GAAP requirements for defined benefit
pension plans.

Accrued Liabilities



We account for contingent liabilities related to litigation, claims and assessments based on the specific facts and circumstances and
our experience with similar matters. We record our best estimate of a loss when the loss is considered probable and the amount of loss is reasonably estimable. When a loss is probable and there is a
range of the estimated loss with no best estimate in the range, we record our estimate of the minimum liability. As additional information becomes available, we revise our estimates as appropriate.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Critical and Significant Accounting Policies (Continued)



For our employees in Wyoming, workers' compensation insurance is provided through a state fund program. We contribute to this program
by applying the assessed state rate to gross payroll for the applicable employees, which is adjusted prospectively based on our workers' compensation historical incident rating.

For
our employees in Colorado and Montana, workers' compensation insurance is provided under a zero-deductible workers' compensation program, which provides full coverage for
any workers' compensation losses, including black-lung claims.

Share-Based Compensation

We measure the cost of share-based employee compensation based on the fair value of the award and recognize that cost over the period
during which the recipient is required to provide services in exchange for the award, typically the vesting period. For equity awards, compensation cost is measured based on grant-date
fair value of the award. The fair value of certain share-based payment awards is estimated using a Black-Scholes option valuation model. Prior to our IPO, certain of our employees participated in
share-based compensation plans sponsored by Rio Tinto. As a result of our IPO, the awards granted by Rio Tinto became vested in accordance with the employee separation provisions contained in the
original terms of the awards.

Discontinued Operations

We report items within discontinued operations in the consolidated statements of operations when the operations and cash flows of a
particular component (defined as operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity) have been eliminated from
our ongoing operations as a result of
a disposal transaction, and we will no longer have any significant continuing involvement in the operations of that component. See Note 4 for additional information about discontinued
operations.

Segment Information

We review, manage and operate our business as a single operating segmentthe production of low sulfur, steam coal from
surface mines, located in the Western region of the U.S. within the Powder River Basin ("PRB"), which is sold to electric utilities and industrial customers.

Earnings per Share

We compute basic earnings per share by dividing net income by the weighted-average number of common shares outstanding during the
period. Diluted earnings per share is computed using the weighted-average number of common and potential dilutive common shares outstanding during the period. We apply the treasury stock method to
determine potential dilutive common shares related to our stock options and non-vested share awards. We apply the if-converted method to determine potential dilutive common
shares related to CPE Resources common membership units that are convertible to CPE Inc. common shares.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Discontinued Operations

There were no discontinued operations for the year ended December 31, 2010.

Sale of Jacobs Ranch Mine

Effective March 8, 2009, we entered into an agreement to sell our membership interest in Jacobs Ranch Coal LLC, which
owned and operated the Jacobs Ranch coal mine, to Arch Coal, Inc. for cash consideration of $761.0 million, subject to certain adjustments as of the closing date. The sale closed on
October 1, 2009, resulting in gross sales proceeds of $768.8 million, which were distributed to Rio Tinto America, and a pre-tax gain on sale of $264.8 million. The
Jacobs Ranch mine was classified as held for sale and reported as discontinued operations as of March 1, 2009. As a result, the consolidated financial statements report the financial position,
results of operations and cash flows of the Jacobs Ranch mine as discontinued operations in all periods presented. Included in Jacobs Ranch mine revenues in the table below are sales to our other
subsidiaries of $21.9 million and $17.7 million for the years ended December 31, 2009 and 2008, respectively. Sales of coal to our other subsidiaries continued after the closing
date under contracts that terminate upon completion of all required shipments in 2010. We determined that our purchases from the mine after the closing date do not represent significant continuing
involvement based primarily on the immateriality of the expected purchases compared to the expected production of the mine and the short duration of the contracts.

Distribution of Colowyo and Uranium Mining Venture

Effective October 7, 2008, RTEA distributed to Rio Tinto America its controlling interests in Colowyo, together with a uranium
mining venture undergoing reclamation
activities. The consolidated financial statements report the financial position, results of operations and cash flows of the distributed entities as discontinued operations in all periods presented.
Subsequent to the distribution date, we provided certain transitional management and administrative support services to the distributed entities on a cost reimbursement basis. These transitional
services were concluded in March 2009.

The
liabilities of the entities distributed to Rio Tinto America (including amounts payable to RTEA) exceeded the assets of such entities by $130.1 million on the distribution
date. In December 2008, RTEA distributed to Rio Tinto America receivables due from the distributed entities totaling $115.2 million. We recorded a $14.9 million net capital contribution
in the fourth quarter of 2008 for the amount by which the liabilities of the distributed entities exceeded their assets and the distributed receivables. The assets and liabilities were transferred at
their respective carrying amounts as of the dates of distribution. No gain or loss was recognized in connection with the distribution.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Discontinued Operations (Continued)

Income
(loss) from discontinued operations, net of tax, presented in the consolidated statements of operations consists of the following for the years ended December 31 (in
thousands):

2009

2008Jacobs Ranch MineRevenues

$
368,640

$
478,039Costs and expenses


304,030


482,863Income (loss) from discontinued operations, before gain on sale and income taxes


64,610


(4,824
)Gain on sale


264,767


Income tax (expense) benefit


(118,299
)

685Income (loss) from discontinued operations, net of taxes

$
211,078

$
(4,139
)Colowyo and Uranium Mining VentureRevenues

$


$
90,678Costs and expenses





124,336Loss from discontinued operations, before income taxes





(33,658
)Income tax benefit





12,582Loss from discontinued operations, net of taxes

$


$
(21,076
)Total Discontinued OperationsRevenues

$
368,640

$
568,717Costs and expenses


304,030


607,199Income (loss) from discontinued operations, before gain on sale and income taxes


64,610


(38,482
)Gain on sale


264,767


Income tax (expense) benefit


(118,299
)

13,267Income (loss) from discontinued operations, net of taxes

$
211,078

$
(25,215
)


5. Inventories

Inventories, net consisted of the following at December 31 (in thousands):

2010

2009Materials and supplies, net

$
59,740

$
60,868Coal stockpiles and finished product


5,230


3,331$
64,970

$
64,199


Materials
and supplies are stated net of an obsolescence allowance of $0.6 million and $1.3 million as of December 31, 2010 and 2009, respectively. We recognized a
provision to increase the allowance by $976,000, $973,000 and $356,000, and charged inventory costs to the allowance of $1,709,000, $897,000 and $325,000, for the years ended December 31, 2010,
2009 and 2008, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. Property, Plant and Equipment

Property, plant and equipment, net consisted of the following at December 31 (in thousands):

2010

2009Land and improvements

$
269,581

$
272,598Mineral rights (1)


660,037


590,292Mining equipment


777,240


701,084Construction in progress


9,081


13,413Other equipment


59,143


99,949Buildings and improvements


69,267


69,1241,844,349


1,746,460Less: accumulated depreciation and depletion


(836,012
)

(759,317
)$
1,008,337

$
987,143


(1)Includes
mineral rights of $319.3 million and $295.5 million at December 31, 2010 and 2009, respectively, attributable to areas where
the Company was not currently engaged in mining operations and, therefore, the coal reserves are not currently being depleted.


Interest
costs capitalized on mine development and construction projects totaled $24.5 million, $15.5 million and $6.6 million for the years ended
December 31, 2010, 2009 and 2008, respectively.

In
2010, we recognized an impairment charge of $659,000 for a piece of equipment which we no longer use. The impairment represents an adjustment to the estimated net realizable value
that we expect to obtain from the sale of the equipment. In 2009, we recognized an impairment charge of $698,000 for costs incurred on an abandoned time-keeping software project. In 2008,
we recognized an impairment charge of $1.01 million for costs incurred on an abandoned production cost efficiency project.

A
$3.1 million reduction of the asset impairment charge was recognized in the year ended December 31, 2008, as a result of favorable changes in estimates and resolution of
contingencies related to a 2007 asset impairment charge associated with the abandonment of a Rio Tinto system implementation.

7. Intangible Assets

Intangible assets, net consisted of the following at December 31 (in thousands):

2010

2009Acquired long-term coal supply contracts

$
349,358

$
349,358Less: accumulated amortization


(349,358
)

(346,161
)$


$
3,197


At
December 31, 2009, acquired long-term coal supply contracts consisted of a contract acquired in 1993 that expired in 2010. The remaining $3.2 million
unamortized balance of the contract was fully amortized in 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Intangible Assets (Continued)

In
March 2008, a Decker contract was amended to provide for a reduction in the quantities of coal to be supplied during 2009 through 2012 in exchange for a $12.7 million cash
payment from the customer in 2009. Upon execution of the amendment, we recognized $6.3 million of revenue, representing our 50% interest in the cash to be received in exchange for the relief of
the Company's obligation to supply coal, and amortization expense of $9.2 million, representing the accelerated amortization of our contract rights corresponding to the reduction in coal supply
quantities under the amended contract. As a result of changes in the Decker mine plan in the fourth quarter of 2008, which resulted in lower projected cash flows, we evaluated the recoverability of
Decker long-lived assets in December 2008 and determined that the remaining carrying amount of the Decker contract was not recoverable. Consequently, we recognized a $4.6 million impairment
charge to reduce the carrying amount of our remaining contract rights to its estimated fair value of zero.

8. Investments

Investments are included in other noncurrent assets and have a carrying amount of $9.4 million and $4.5 million at December 31, 2010 and 2009, respectively.
Investments at December 31, 2010 and 2009 consist of our 50% equity investment in Venture Fuels Partnership, a coal marketing company.

9. Long-Term Debt

Long-term debt consisted of the following at December 31 (in thousands):

2010

20098.25% Senior Notes due 2017, net of $1,979 unamortized discount

$
298,021

$
297,8248.50% Senior Notes due 2019, net of $2,337 unamortized discount


297,663


297,497Total long term debt

$
595,684

$
595,321


Senior Notes

On November 25, 2009, CPE Resources and its wholly-owned subsidiary, Cloud Peak Energy Finance Corp., issued the 8.25% Senior
Notes due 2017 ("2017 Notes") and the 8.5% Senior Notes due 2019 ("2019 Notes"), which we refer to collectively as the Senior Notes, in accordance with Rule 144A of the Securities Act of 1933,
as amended. The 2017 Notes and the 2019 Notes each were issued in the aggregate principal amount of $300.0 million, net of original issue discounts of $2.2 million and
$2.5 million, respectively, resulting in aggregate proceeds of $595.3 million. The 2017 Notes and 2019 Notes bear interest at fixed annual rates of 8.25% and 8.50%, respectively, and
mature on December 15, 2017 and 2019, respectively. There are no mandatory redemption or sinking fund payments for the Senior Notes and interest payments are due semi-annually on
June 15 and December 15, which commenced 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.

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9. Long-Term Debt (Continued)

Debt
issuance costs of approximately $14.2 million were incurred in connection with the issuance of the Senior Notes. These costs were deferred and are being amortized to interest
expense over the
respective terms of the Senior Notes using the effective interest method. Unamortized debt issuance costs of $12.8 million and $14.1 million were included in noncurrent other assets at
December 31, 2010 and 2009, respectively.

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 in which CPE Resources holds a 50% interest, 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.

The
approximate fair value of our Senior Notes was $650.3 million at December 31, 2010. The fair value of the Senior Notes is based on market quoted prices as of
December 31, 2010.

Senior Secured Revolving Credit Facility

Concurrently with the offering of the Senior Notes, we entered into a $400.0 million senior secured revolving credit facility,
or Credit Facility, with a syndicate of lenders, the full amount of which is available for use in connection with loans or the issuance of letters of credit. The Credit Facility may be expanded at our
request, subject to certain conditions and to the extent lenders are willing to extend additional commitments, up to an additional $50.0 million. Our obligations under the Credit Facility are
supported by a guarantee by certain of our restricted subsidiaries. The Credit Facility matures on December 16, 2013. As of December 31, 2010, 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 17.

Lender
fees and costs of $15.9 million were incurred in connection with the execution of the Credit Facility. These costs are being amortized to interest expense over the term of
the Credit Facility using the straight-line method. Unamortized fees and costs of $11.7 million and $15.5 million were included in noncurrent other assets at
December 31, 2010 and 2009.

Loans
under the Credit Facility bear interest at the greater of the LIBOR or 2.50%, plus an applicable margin based on our credit rating of between 3.25% and 4.25% (4.00% at
December 31, 2010). At our option, the interest rate on loans under the Credit Facility may be based on an alternative base rate of at least 3.50%, and the applicable margins over such
alternative base rate are 1.00% less than the applicable margin for LIBOR loans. We are required to pay the lenders a commitment fee of 0.75% per year on the unused amount of the Credit Facility.
Letters of credit issued under the Credit Facility, unless drawn upon, bear interest at the applicable margin for LIBOR loans from the date at which they are issued. In addition, in connection with
the issuance of a letter of

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9. Long-Term Debt (Continued)

credit
we are required to pay the issuing bank a fronting fee of 0.25% plus additional customary administrative fees and expenses.

Our
obligations under the Credit Facility are secured by substantially all of our assets and substantially all of the assets of certain of our subsidiaries, subject to certain permitted
liens and to customary exceptions for similar coal financings. We are subject to financial maintenance covenants based on EBITDA (which is defined in the Credit Facility and is not the same as EBITDA
or Adjusted EBITDA presented elsewhere in our consolidated financial statements) requiring us to maintain defined minimum levels of interest coverage and providing for a limitation on our total and
first lien senior secured debt leverage ratios. Specifically, the Credit Facility requires us to maintain a ratio of EBITDA to consolidated net cash interest expense equal to or greater than 2.75 to
1, a ratio of funded debt to EBITDA equal to or less than 3.5 to 1, and a ratio of first lien senior secured debt to EBITDA equal to or less than 1.5 to 1 as long as the Credit Facility is in effect.

Our
Credit Facility also requires us to comply with non-financial covenants that restrict certain activities at both the corporate and subsidiary levels and contains
customary events of default with customary grace periods and thresholds. These covenants include restrictions on our ability to incur additional debt and pay dividends, among other restrictive
covenants. Our ability to access the available funds under the Credit Facility may be impaired in the event that we do not comply with the covenant requirements or if we default on our obligations
under the agreement. In addition, under the terms of the Credit Facility, a change in control of Cloud Peak Energy Inc. or CPE Resources would result in an automatic event of default and,
unless waived by the required lenders, would result in all obligations under the Credit Facility to become immediately due and payable. At December 31, 2010, we were in compliance with the
covenants contained in our Credit Facility.

RTA Facility

Prior to its termination in 2008, our credit facility with Rio Tinto America (the "RTA Facility") allowed us to borrow up to
$800.0 million from Rio Tinto America with no specified maturity date. Borrowings under the RTA Facility were subject to interest, payable quarterly, calculated on the daily average borrowings
outstanding during the quarter at a rate equal to the
average 3 month U.S. dollar LIBOR plus a margin of 1.5%. Interest cost related to the RTA Facility was $16.8 million for the year ended December 31, 2008. As of
December 31, 2007, $37.4 million of accrued interest on the RTA Facility was converted to principal. Effective September 24, 2008, the RTA Facility was terminated and the then
outstanding balance was converted to equity. The total outstanding principal and accrued interest amount at the effective date of the termination of the RTA Facility of $547.4 million is
reflected as a capital contribution in the consolidated statement of equity for the year ended December 31, 2008.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Long-Term Debt (Continued)

Future Maturities

Aggregate future maturities of long-term debt as of December 31, 2010 are as follows (in thousands):

2015 and thereafter


600,000600,000Less discount on senior notes


4,316Total long term debt

$
595,684


Interest
expense under financing arrangements, net of amounts capitalized, totaled $46.9 million, $6.0 million and $20.4 million for the years ended
December 31, 2010, 2009 and 2008, respectively.

10. Other Long-Term Obligations

Long-term obligations consisted of the following at December 31 (in thousands):

2010

2009Federal coal lease obligations

$
118,289

$
169,058Other


8,071


9,309Total obligations


126,360


178,367Less: current portion


(59,410
)

(55,282
)Total long-term obligations

$
66,950

$
123,085


Federal Coal Leases

The Company's federal coal leases, as reflected in the consolidated balance sheets, consist of discounted obligations payable to the
Bureau of Land Management of the U.S. Department of the Interior under four leases, each of which requires five equal annual payments, as follows (in thousands):

Principal Balance at December 31Annual
Payment

Imputed
Interest
RatePayment Dates

2010

2009December 1, 2007-2011

$
3,980


6.8
%
$
3,728

$
7,220August 1, 2008-2012


50,160


7.5
%

90,068


130,447May 1, 2009-2013


9,620


8.7
%

24,493


31,391$
118,289

$
169,058


The
Company recognizes imputed interest on federal coal leases based on an estimate of the credit-adjusted, risk-free rate reflecting the Company's estimated credit rating at
the inception of the lease. Imputed interest for the years ended December 31, 2010, 2009 and 2008 was $11.7 million, $14.2 million and $7.9 million, respectively, of which,
$10.8 million, $14.1 million and $5.8 million, respectively, was capitalized as we prepared to mine the related coal deposits.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. Other Long-Term Obligations (Continued)

Other

Other long-term obligations consists of obligations incurred in connection with the acquisitions of land and mineral
rights. At December 31, 2010 and 2009, we had $8.1 million and $9.3 million of purchase obligations with parties other than the BLM of which $4.8 million and
$4.5 million are current as of December 31, 2010 and 2009, respectively. These bear interest at rates ranging from 6% to 8%.

The
approximate fair value of our federal coal lease obligations was $127.6 million at December 31, 2010. The fair value estimates for the federal coal leases were
determined by discounting the remaining lease payments using a current estimate of the credit-adjusted, risk-free interest rate that is based on the Company's current credit standing.

11. Asset Retirement Obligations

Changes in the carrying amount of the Company's asset retirement obligations were as follows (in thousands):

2010

2009Balance at January 1

$
181,419

$
167,272Accretion expense


12,499


12,587Revisions to estimated cash flows


777


6,415Payments


(5,938
)

(4,855
)Balance at December 31


188,757


181,419Less current portion


(6,587
)

(5,479
)Asset retirement obligation, net of current portion

$
182,170

$
175,940


The
above amounts exclude $5.9 million and $6.5 million of concurrent reclamation for the years ended December 31, 2010 and 2009, respectively. The revisions to
estimated cash flows pertain to revisions in the estimated amount and timing of legally required reclamation activities throughout the lives of the respective mines and reflect changes in estimates of
closure volumes, disturbed acreages and third-party unit costs as of December 31, 2010 and 2009. Adjustments to AROs resulting from such revisions
generally result in a corresponding adjustment to the related asset retirement cost in property, plant and equipment, net.

In
2008, a change in the timing of reclamation activities for one of our mines resulted in a reduction in the asset retirement obligation that exceeded the carrying amount of the related
asset retirement cost by $4.7 million ($3.0 million after tax) and was recognized as a reduction of depreciation and depletion expense in the period.

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12. Employee Benefit Plans

Our consolidated statements of operations include expenses in connection with employee benefit plans sponsored by Cloud Peak Energy (subsequent to our IPO) and Rio Tinto America (prior
to our IPO), as follows for the years ended December 31 (in thousands):

2010

2009

2008Cloud Peak Energy plans:Defined contribution retirement plans

$
11,212

$
757

$
Retiree medical plan


4,710


359


15,922


1,116


Rio Tinto America plans:Defined contribution retirement plans





6,414


6,384Defined benefit pension plan





2,608


2,943Retiree medical plan





1,373


1,505


10,395


10,832Decker pension plan


626


892


44Total

$
16,548

$
12,403

$
10,876


Cloud Peak Energy Plans

Defined Contribution Retirement Plans

In connection with our IPO, we established the Cloud Peak Energy 401(k) Plan and Profit Sharing Plan in order to facilitate the
accumulation of retirement savings for our employees, which do not include Decker employees. Our employees may elect to contribute a portion of their salary on a pre-tax basis to their
account in the 401(k) Plan and we match the employee contributions up to 6% of eligible compensation. We also contribute an additional 6% of eligible compensation to employee accounts under the Profit
Sharing Plan. All contributions are fully vested at the date of contribution.

Retiree Medical Plan

In connection with our IPO, we agreed to establish a plan to provide certain postretirement medical benefits to eligible employees,
which does not include Decker employees (the "Retiree Medical Plan"). Employees who are 55 years old and have completed ten years of service with the Company generally are entitled to receive
benefits under the Retiree Medical Plan, except for employees who were eligible at the date of our IPO to receive benefits under the Rio Tinto America retiree medical plan and elect to receive such
benefits. As required by an agreement between Rio Tinto America and us in connection with the IPO, the retiree medical plan grants credit for service rendered by our employees to Rio Tinto America
prior to the IPO.

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12. Employee Benefit Plans (Continued)

Net
periodic postretirement benefit costs included the following components:

2010

2009Service cost

$
2,315.6

$
252.2Interest cost


988.7


107.2Amortization of prior service cost


1,405.7


Net periodic postretirement benefit cost

$
4,710.0

$
359.4


We
recognized a $16.6 million liability as of November 19, 2009, for our accumulated postretirement benefit obligation ("APBO") under the Retiree Medical Plan. The initial
APBO amount reflects the cost of certain benefits attributable to services rendered by our employees prior to the initiation of the Retiree Medical Plan. The APBO for prior service cost was allocated
between the controlling and noncontrolling interests in CPE Resources and charged to accumulated other comprehensive loss (see Note 14). These amounts will be recognized in net periodic
postretirement benefit cost over the remaining period prior to the date the employees become eligible to receive benefits. At the time that we recognized the liability we classified
$1.3 million of the liability as current.

At
December 31, 2009, we remeasured and adjusted the liability for the APBO to $16.4 million, of which $20,000 is included in current liabilities and $16.4 million
is included in noncurrent other liabilities in our consolidated balance sheet at December 31, 2009. The net decrease of $236,000 in the APBO for the period ended December 31, 2009, is
attributable to the recognition of a $595,000 pre-tax actuarial gain in other comprehensive income, partially offset by the recognition of service cost of $252,000 and interest cost of
$107,000 in our consolidated statement of operations.

At
December 31, 2010, we remeasured and adjusted the liability for the APBO to $23.3 million, of which $37,000 is included in current liabilities and $23.2 million
is included in noncurrent other liabilities in our consolidated balance sheet at December 31, 2010. The net increase of $6.9 million in the APBO for the period ended December 31,
2010, is attributable to $2.3 million in current period service cost, $1.0 million in interest costs and $3.6 million in increased costs associated with changes in actuarial
assumptions.

We
used the following assumptions in the measurement of the APBO:

December 31,
2010

December 31,
2009Discount rate


5.51
%

6.04
%Health care cost trend rate assumed for next year


8.50
%

9.00
%Ultimate health care cost trend rate


5.00
%

5.00
%Year that the rate reaches the ultimate trend rate


2018


2018


To
determine the discount rate, we matched our cash projections against the Citigroup Pension Discount Curve. Assumed health care cost trend rates have a significant effect on the
amounts reported for health care plans. A one-percentage-point increase in the assumed health care cost trend would increase net periodic postretirement benefit cost and the APBO by $492,865 and
$3.0 million, respectively, and a one-percentage-point decrease in the rate would decrease net periodic postretirement benefit cost and the APBO by $408,361 and $2.5 million,
respectively, as of December 31, 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Employee Benefit Plans (Continued)

Our estimated future benefit payments under the Retiree Medical Plan, which are net of estimated employee contributions and reflect expected future service, are as follows for the years
ended December 31 (in thousands):

2011

$
372012


952013


1742014


2792015


4222016 - 2020

$
6,515


Rio Tinto America Plans

Defined Contribution Retirement Plans

Prior to our IPO, we were a participating employer in two defined contribution plans sponsored by Rio Tinto America. We were required
to contribute to these plans based on eligible employee compensation and employee contribution matching requirements. Employees of Decker were not included in these plans.

Defined Benefit Plans

Prior to our IPO structuring transactions, our employees, which do not include Decker employees, participated in a defined benefit
pension plan and a retiree medical plan sponsored by Rio Tinto America. We made contributions to the pension plan as determined by consulting actuaries based upon the applicable regulatory funding
standard and made contributions to the retiree medical plan as benefits were paid. We recognized benefit costs in excess of our contributions on a carve-out basis, based on an allocation
of net periodic pension cost and net periodic postretirement benefit cost, as determined in accordance with U.S. GAAP. Our liabilities for costs incurred under these plans were recognized in
due to related parties and were cancelled in connection with our IPO structuring transactions (see Note 2). For the year ended December 31, 2008, we recorded a charge to former parent's
equity of $687,000, net of tax, in connection with a change in the measurement date for plan assets and benefit obligations.

Decker Pension Plan

Decker's employees participate in a defined benefit retirement plan sponsored by Decker. This plan does not have a material impact on
our consolidated financial position, results of operations or cash flows. Our share of the funded status of the plan is reported in noncurrent other liabilities and was $2.9 million and
$2.5 million at December 31, 2010 and 2009, respectively. Other comprehensive income or loss includes certain actuarial gains and losses that are reflected in the funded status of the
plan, but have not been recognized in periodic benefit cost.

13. Income Taxes

Our income from continuing operations before income tax provision and earnings (losses) from unconsolidated affiliates is earned solely in the U.S. For periods prior to our IPO, our
consolidated financial statements reflect income taxes recognized by RTEA. See "Initial Public Offering, Related

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13. Income Taxes (Continued)

IPO
Structuring Transactions, and Secondary Offering" in Note 2. RTEA was a member of an affiliated federal tax group and was party to a federal income tax sharing agreement with the other
members of the affiliated federal income tax group. However, for the purposes of our consolidated financial statements, which were prepared on a carve-out basis, RTEA's current and
deferred taxes were calculated on a stand-alone separate return basis. RTEA provided income taxes on substantially all pre-tax income reported in our consolidated financial statements for
such pre-IPO periods. For periods following our IPO, CPE Inc. is required to file a separate federal corporate income tax return and recognizes income taxes on its
pre-tax income, which for periods before the Secondary Offering has consisted solely of its share (approximately 51%) of CPE Resources pre-tax income. For periods following the
Secondary Offering, CPE Inc. recognizes income tax expense on 100% of pretax income. CPE Resources is organized as a limited liability company and generally is not subject to income taxes,
although several corporate subsidiaries of CPE Resources file separate corporate income tax returns and may incur minor amounts of income tax or may incur losses which cannot benefit other entities
included in the consolidated financial results. Because CPE Resources generally is not a taxable entity, our consolidated financial statements do not reflect any income taxes on pre-tax
income attributable to the noncontrolling interest in CPE Resources that existed before our Secondary Offering.

The
income tax provision (benefit) for continuing operations consisted of the following for the years ended December 31 (in thousands):

2010

2009

2008Current:Federal

$
3,478

$
52,309

$
44,154State





1,495


1,262Total current


3,478


53,804


45,416Deferred:Federal


27,961


14,044


(19,540
)State


543


401


(558
)Total deferred


28,504


14,445


(20,098
)Total income tax provision

$
31,982

$
68,249

$
25,318


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Income Taxes (Continued)

The
tax effects of temporary differences that result in deferred tax assets and deferred tax liabilities for continuing operations consisted of the following at December 31 (in
thousands):

2010

2009Deferred income tax assets:Property, plant and equipment

$
178,174

$
Accrued expense and liabilities


27,554


Pension and other postretirement benefits


8,884Investment in joint venture partnerships


4,542


Accrued reclamation and mine closure costs


41,128


Contract rights


21,533Investment in CPE Resources





103,639Tax agreement liability


69,006


19,623Other


10,618Total deferred income tax assets


361,439


123,262Less valuation allowance


(94,572
)

(22,462
)Net deferred income tax asset


266,867


100,800Deferred income tax liabilities:Inventories


(2,976
)

Mineral rights


(93,383
)

Other


(7,971
)

Total deferred income tax liabilities


(104,330
)

Net deferred income tax assets (liabilities)

$
162,537

$
100,800


At
December 31, 2009 CPE Inc.'s principal deferred tax asset relates to its partnership investment in CPE Resources, which reflects an increase in tax basis in connection
with our IPO structuring transactions. After the Secondary Offering, CPE Resources is no longer a partnership for tax purposes and CPE Inc. is required to report differences between tax bases
of assets and liabilities and the financial statement carrying amount of these items individually. CPE Inc. also has recognized a deferred tax asset for payments it expects to make pursuant to
the Tax Receivable Agreement with RTEA, which is recognized as a liability in our consolidated financial statements. Included in our other deferred tax
assets are net operating loss carryforwards of $7.8 million that expire in 2029 and 2030 and AMT credits of $2.7 million that do not expire.

Net
deferred income tax assets related to continuing operations are classified in the consolidated balance sheets at December 31 as follows (in thousands):

2010

2009Net current deferred income tax assets

$
21,552

$
280Net noncurrent deferred income tax assets


140,985


100,520Net deferred income tax assets

$
162,537

$
100,800


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13. Income Taxes (Continued)

The
future realization of deferred income tax assets that resulted from the increased tax basis arising from the IPO and the Secondary Offering depends on the existence of sufficient
future taxable income. Based on our consideration of CPE Resources' historical operations, current forecasts of taxable income over the remaining lives of our mines, the availability of tax planning
strategies, and other factors, we determined that $162.5 million of the potential tax benefits are more likely than not to be realized at the statutory federal and state income tax rates.
Accordingly, we have provided a $94.6 million valuation allowance to reduce our deferred tax assets to the amount that we determined is more likely than not to be realized.

The
effective tax rate for our continuing operations is reconciled to the U.S. federal statutory income tax rate for the years ended December 31 as follows:

2010

2009

2008United States federal statutory income tax rate


35.0
%

35.0
%

35.0
%State income taxes, net of federal tax benefit


0.4


0.8


0.6Depletion


(3.0
)

(5.6
)

(9.8
)Section 468 imputed interest








0.5Section 199 domestic manufacturing deduction


(0.1
)

(1.6
)

(3.3
)Valuation allowance


9.0





Noncontrolling interest


(18.9
)

(1.5
)

Prior year return-to-actual


(0.4
)




Other


(0.1
)

0.3


0.2Effective tax rate


21.9
%

27.4
%

23.2
%


The
effective tax rate for 2010 reflects a reduction related to the noncontrolling interest in the pre-tax income of CPE Resources for the period before the Secondary
Offering, for which no income taxes were recognized in the consolidated statement of operations.

14. Equity and Comprehensive Income

Immediately prior to our IPO structuring transactions, RTEA and an affiliate held 60,000,000 common
membership units in CPE Resources. See "Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering" in Note 2. In connection with our IPO, we purchased 30,600,000 of
the common membership units from RTEA, which represented 51% of the outstanding units. The CPE Resources limited liability company agreement, as amended, requires that there must be a
one-to-one ratio between the number of common membership units held by CPE Inc. and the number of shares of CPE Inc. common stock issued and outstanding and not
held in treasury.

Therefore,
when we issue restricted shares pursuant to the 2009 Cloud Peak Energy Long Term Equity Incentive Plan or if options issued under the plan are exercised and new shares are
issued, CPE Inc. acquires additional common membership units in order to maintain the one-to-one ratio. Any time that those restricted shares are forfeited; they are
cancelled along with the related membership units. CPE Inc. is required to contribute any cash consideration received for issued shares, net of applicable withholding taxes, to CPE Resources.
We issued 849,402 shares of restricted stock on our IPO date and subsequently cancelled 400 shares due to forfeitures (See Note 15). Further stock activity

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14. Equity and Comprehensive Income (Continued)

resulted
in a net increase of the total common membership units issued and outstanding to 60,849,002 at December 31, 2009.

Allocations
of CPE Resources' net income or net losses are made at the end of each fiscal quarter pro rata based on the number of common membership units owned by each member, as
compared to the total number of common membership units outstanding at the time of the allocation. In connection with the Secondary Offering, we exchanged 29,400,000 shares of common stock for the
common membership units of CPE Resources held by Rio Tinto and completed the Secondary Offering resulting in a divesture of 100% of Rio Tinto's holdings in Cloud Peak Energy. As CPE Inc. is the
100% holder of all membership units subsequent to the Secondary Offering, all CPE Resources income is now allocated to CPE Inc.

Comprehensive
income includes net income and other comprehensive income arising from activity related to our defined benefit employee benefit plans (see Note 12). The following
table summarizes the allocation of total comprehensive income between the controlling and noncontrolling interests for the year ended December 31, 2010 (in thousands):

Controlling
Interest

Noncontrolling
Interest

TotalNet income

$
33,737

$
83,460

$
117,197Other comprehensive income (loss):Decker pension adjustments


295





295Decker pension adjustments income tax


(106
)




(106
)Retiree medical plan amortization of prior service cost


751


654


1,405Retiree medical plan amortization of prior service cost income tax


(270
)




(270
)Retiree medical plan adjustment


(3,587
)




(3,587
)Retiree medical plan adjustment income tax


1,292





1,292Total other comprehensive loss


(1,625
)

654


(971
)Total comprehensive income

$
32,112

$
84,114

$
116,226


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. Equity and Comprehensive Income (Continued)

The
following table summarizes the allocation of total comprehensive income between the controlling and noncontrolling interests for the year ended December 31, 2009 (in
thousands):

Controlling
Interest

Noncontrolling
Interest

TotalNet income

$
381,701

$
11,849

$
393,550Other comprehensive income (loss):Decker pension adjustments


1,104


1,032


2,136Decker pension adjustments income tax


(397
)




397Retiree medical plan initiation


(8,587
)

(8,028
)

(16,615
)Retiree medical plan initiation income tax


3,091





3,091Retiree medical plan adjustment


308


287


595Retiree medical plan adjustment income tax


(111
)




(111
)Total other comprehensive loss


(4,592
)

(6,709
)

(11,301
)Total comprehensive income

$
377,109

$
5,140

$
382,249


The
following table summarizes the noncontrolling interest share of CPE Resources' net income (in thousands):

2010

2009Income from continuing operations before income tax provision and earnings from unconsolidated affiliates

$
149,331

$
24,559Adjustment for TRA expense not allocable to noncontrolling interest


19,669


Earnings (losses) from unconsolidated affiliates before income taxes


3,822


(35
)Income from continuing operations before income tax provision


172,822


24,524Income from continuing operations before income tax provision attributable to the noncontrolling interest (48.3%)

$
83,460

$
11,849


Prior
to the Secondary Offering, RTEA and its affiliate had the right to redeem any or all of their common membership units at a per unit redemption price equal to the
volume-weighted-average price of a share of CPE Inc. common stock for the ten previous trading days prior to redemption notice being given. CPE Inc. had the right to assume those units
by either paying the redemption price noted above in cash, by issuing to RTEA or its affiliate the same number of shares of its common stock as common membership units being redeemed, or a combination
of both. As a result of the Secondary Offering, CPE Inc. holds 100% of the common membership units.

15. Share-Based Compensation

Prior to our IPO, certain of our employees participated in share-based compensation plans sponsored by Rio Tinto. In connection with our IPO, we adopted the Cloud Peak Energy Inc.
2009 Long Term Incentive Plan, or LTIP, which permits awards to our employees, which do not include Decker employees, and eligible non-employee directors. The LTIP allows for the issuance
of

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15. Share-Based Compensation (Continued)

share-based
compensation in the form of restricted stock, restricted stock units, options, stock appreciation rights, dividend equivalent rights, performance awards and share awards. The
LTIP authorizes a pool of 3.4 million shares of our common stock for issuance in connection with share-based awards.

Total
share-based compensation expense recognized primarily within selling, general and administrative expenses in our consolidated statements of operations was as follows for the years
ended December 31 (in thousands):

2010

2009

2008Rio Tinto sponsored plans

$


$
2,288

$
(55
)Cloud Peak Energy sponsored plan


7,234


785


Total share-based compensation expense

$
7,234

$
3,073

$
(55
)


As
of December 31, 2010, the total unrecognized compensation cost related to nonvested awards was $18.2 million, which is expected to be recognized over 1.9 years.

Restricted Stock

In connection with our IPO, on November 20, 2009, we granted restricted stock under the LTIP to substantially all of our
employees and directors. Generally, the related agreements provide that restricted stock issued will fully vest on the third anniversary of the grant date. However, the restricted stock will
pro-rata vest sooner if a grantee terminates employment with or stops providing services to the Company because of death, disability, redundancy or retirement. The restricted stock will
fully vest if an employee is terminated without cause within two years after a change in control occurs (as such term is defined in the LTIP).

A
summary of restricted stock award activity is as follows (in thousands):

Number

Weighted
Average
Grant-Date
Fair Value
(per share)Non-vested shares at January 1, 2009




$
Granted


849,402


15.00Forfeited


(400
)

15.00Vested





Non-vested shares at December 31, 2009


849,002

$
15.00Non-vested shares at January 1, 2010


849,002

$
15.00Granted


69,153


16.19Forfeited


(39,838
)

15.00Vested


(384
)

15.15Non-vested shares at December 31, 2010


877,933

$
15.09


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15. Share-Based Compensation (Continued)

Non-Qualified Stock Options

In connection with our IPO, on November 20, 2009, we granted non-qualified stock options under the LTIP to certain
employees. Generally, the agreements provide that any option awarded will become exercisable in three years. However, the option will become pro-rata exercisable sooner if a grantee
terminates employment because of death, disability, redundancy or retirement. The option award will fully vest if an employee is terminated without cause within two years after a change in control
occurs (as such term is defined in the LTIP). No option can be exercised more than ten years after the date of grant. Each award will be forfeited if the grantee terminates employment with or stops
providing services to us for any reason other than those reasons noted above.

A
summary of non-qualified stock option activity is as follows (in thousands):

Number

Weighted
Average
Exercise
Price
(per option)

Weighted
Average
Contractual
Term
(Years)Options outstanding at January 1, 2009




$
Granted


1,011,951


15.00Forfeited





Options outstanding at December 31, 2009


1,011,951


15.00


9.89Exercisable at December 31, 2009


Options outstanding at January 1, 2010


1,011,951

$
15.00


9.89Granted


59,828


16.20Forfeited


(39,284
)

15.00Options outstanding at December 31, 2010


1,032,495


15.07


8.91Exercisable at December 31, 2010





We
used the Black-Scholes option pricing model to determine the fair value of stock options. Determining the fair value of share-based awards requires judgment, including estimating the
expected term that stock options will be outstanding prior to exercise and the associated volatility. As we have no historical exercise history, expected option life assumptions were developed using
the simplified method as outlined in Topic 14,Share-Based Payment, of the Staff Accounting Bulletin Series. We utilized U.S. Treasury yields as of the
grant date for our risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option. We utilized a 6.5-year peer historical lookback to
develop our expected volatility.

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15. Share-Based Compensation (Continued)

The
assumptions used to estimate the fair value of options granted on March 3, 2010 and on November 20, 2009 are as follows (dollar amount in thousands):

2010

2009Weighted average fair value (per option)


$9.34


$8.85Assumptions:Risk-free interest rate


3.0
%

2.9
%Expected option life


6.5 years


6.5 yearsExpected volatility


57
%

59
%Dividend yield


0
%

0
%


Rio Tinto Plans

Prior to our IPO, certain of our employees participated in Rio Tinto share-based compensation plans. As a result of our IPO, the awards
granted by Rio Tinto became vested, in full or on a pro-rata basis, in accordance with the employee separation provisions contained in the original terms of the awards. Our share-based
compensation expense for the year ended December 31, 2009 includes $936,000 as a result of the accelerated vesting of the Rio Tinto awards. Rio Tinto retained the obligation to settle the
vested awards with our employees. As a result of our IPO, we reversed a $1.3 million accrued liability for the fair value of certain awards to be settled in
cash and adjusted former parent's equity to reflect Rio Tinto's assumption of this liability. See "Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering" in
Note 2.

16. Earnings Per Share

Prior to our IPO on November 19, 2009, our parent company and predecessor for financial reporting purposes was RTEA. For all periods presented in these consolidated financial
statements, RTEA had one share of common stock outstanding. In anticipation of our IPO, RTEA contributed substantially all of its assets and liabilities associated with our coal business to CPE
Resources. The limited liability company agreement for CPE Resources was amended in connection with our IPO to increase the number of its common membership units to 60,000,000 units and to require a
one-to-one ratio between the number of common membership units held by CPE Inc. and the number of outstanding shares of CPE Inc. common stock. Consequently,
CPE Inc.'s acquisition of a 51% interest in CPE Resources resulted in the transfer of 30,600,000 common membership units to CPE Inc. and the issuance of 30,600,000 shares of common stock
to the public. We consider the effect of the equity restructuring transactions that occurred in connection with our IPO to be substantially similar to a stock split, where one share of RTEA stock,
which prior to our IPO represented 100% ownership of the business of CPE Resources, became equivalent to 60,000,000 common membership units in CPE Resources. Pursuant to the
one-to-one ratio requirements, CPE Inc. would have been required to have 60,000,000 shares of common stock outstanding if it had owned the 100% interest in CPE Resources
that was held by RTEA, as former parent, prior to our IPO. Accordingly, we assume that 60,000,000 shares of common stock were outstanding during periods prior to our IPO for purposes of calculating
basic and diluted earnings per share.

On
December 15, 2010, Cloud Peak Energy Inc. priced the Secondary Offering of 29,400,000 shares of its common stock on behalf of Rio Tinto. In connection with the Secondary
Offering, we

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16. Earnings Per Share (Continued)

exchanged
29,400,000 shares of common stock for the common membership units of CPE Resources held by Rio Tinto and completed the Secondary Offering, resulting in a divestiture of 100% of Rio
Tinto's holdings in CPE Resources. As a result of this transaction, CPE Resources is now a wholly-owned subsidiary of Cloud Peak Energy Inc.

The
table below summarizes the calculation of basic earnings per share for the years ended December 31, (in thousands, except per share amounts):

2010

2009

2008Amounts attributable to controlling interest common shareholders:Income from continuing operations

$
33,737

$
170,623

$
88,340Income (loss) from discontinued operations





211,078


(25,215
)Net income

$
33,737

$
381,701

$
63,125Earnings per share from continuing operations

$
0.98

$
3.01

$
1.47Earnings per share from discontinued operations





3.73


(0.42
)Basic earnings per share

$
0.98

$
6.74

$
1.05Weighted-average shares outstanding


34,305


56,617


60,000


There
were no dilutive potential common shares prior to our IPO. Following our IPO, dilutive potential common shares include restricted shares and options issued under the LTIP (see
Note 15) and common shares that may be issued in exchange for CPE Resources common membership units held by Rio Tinto members (see Note 14). We apply the treasury stock method to
determine dilution from restricted shares and options, and apply the if-converted method to determine dilution from the exchange of common membership units. In applying the
if-converted method, we assumed that the Rio Tinto members have exchanged all of their membership units in CPE Resources for an equivalent number of shares of CPE Inc. common stock.
In this calculation, we increased the numerator to include CPE Resources income attributable to the noncontrolling interest and decreased the numerator to reflect the additional income tax expense
that results from the attribution of additional CPE Resources income to CPE Inc.'s controlling interest in CPE Resources. The calculation of such additional income tax expense reflects our
combined federal and state statutory rate of 36%.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Earnings Per Share (Continued)

The
following table summarizes the calculation of diluted earnings per share for the years ended December 31, (in thousands, except per share amounts):

2010

2009

2008Numerator for calculation of diluted earnings per share:Income from continuing operations attributable to controlling interest shareholders

$
33,737

$
170,623

$
88,340Add back income from continuing operations attributable to the noncontrolling interest, net of estimated income taxes





7,583


Numerator for diluted income from continuing operations per share


33,737


178,206


88,340Income (loss) from discontinued operations





211,078


(25,215
)Numerator for diluted net income per share

$
33,737

$
389,284

$
63,125Denominator for basic income per shareweighted-average shares outstanding


34,305


56,617


60,000Weighted-average common shares from assumed exchange of CPE Resources common membership units held by noncontrolling interest





3,383


Denominator for diluted earnings per share


34,305


60,000


60,000Diluted earnings per share from continuing operations

$
0.98

$
2.97

$
1.47Diluted earnings (loss) per share from discontinued operations





3.52


(0.42
)Diluted earnings per share

$
0.98

$
6.49

$
1.05


For
the year ended December 31, 2010, 877,933 restricted shares and 1,032,495 options outstanding under the LTIP were excluded from the diluted earnings per share calculation
because they were anti-dilutive. For the year ended December 31, 2009, 849,002 restricted shares and 1,011,951 options outstanding under the LTIP were excluded from the diluted
earnings per share calculation because they were anti-dilutive.

17. Commitments and Contingencies

Commitments

Operating Leases

We occupy various facilities and lease certain equipment under various lease agreements. In April 2010, we entered into a lease
agreement for an office in Broomfield, Colorado. The lease commenced in August 2010 and has an initial term of 126 months (10.5 years). Total base rent, including estimated operating
expenses, for the entire initial term of the lease is $8.1 million, resulting in an average annual rent expense of approximately $770,000. This new lease agreement replaced our prior sublease
of office space in Greenwood Village, Colorado (see Note 18).

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17. Commitments and Contingencies (Continued)

The
minimum rental commitments under non-cancelable operating leases, with lease terms in excess of one year subsequent to December 31, 2010, are as follows (in
thousands):

2011

$
791.12012


816.02013


753.72014


796.62015


825.9Thereafter


4,680.3$
8,663.6


Rental
expense for the years ended December 31, 2010, 2009 and 2008, was $1.2 million, $2.2 million and $1.4 million, respectively.

Purchase Commitments

As of December 31, 2010, we had outstanding capital purchase commitments of $13.1 million and coal purchase commitments
of $10.7 million. The coal purchase commitments will be utilized for coal sales made to a customer under the terms of a coal supply agreement that terminates upon completion of all required
shipments in 2011.

In
April 2008, we entered into an agreement 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.

Tax Receivable Agreement

We have recognized a $190.1 million undiscounted liability for our estimated payments to RTEA under the Tax Receivable
Agreement, of which $18.2 and $171.9 million is classified as current and noncurrent, respectively, as of December 31, 2010. The estimated liability is based on forecasts of future
taxable income over the anticipated life of our mining operations and reclamation activities, 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, 2010, we expect to make payments of $18.2 in 2010 and payments averaging approximately $24.5 million during 2012 to 2015. CPE Inc. is obligated
to make these payments and expects to obtain funding for these payments by causing CPE Resources to distribute cash to its owner, CPE Inc.

During
the quarter ended September 30, 2010, CPE Inc. completed its 2009 federal income tax return filing process, which included a final determination of the amount of the
increased tax basis in CPE Inc.'s share of CPE Resources's assets recorded as a result of the IPO structuring transactions. As a result, the initial liabilities CPE Inc. expected to owe
under the Tax Receivable Agreement based on its operating plans at the time of the IPO decreased, resulting in a $2.4 million credit to retained earnings as of September 30, 2010.

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17. Commitments and Contingencies (Continued)

Additionally,
in the third quarter CPE Inc. completed its annual update of its most recent operating plans and to its resulting 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 for the year ended
December 31, 2010. Related adjustments of $5.4 million to the net value of deferred tax assets are recorded through income tax expense. These charges are solely attributable to Cloud
Peak Energy Inc., the controlling interest.

During
the quarter ended December 31, 2010, CPE Inc. completed the Secondary Offering and, as a result, we recognized an additional $123.6 million liability for the
estimated, undiscounted amounts that we expect to pay RTEA pursuant to the Tax Receivable Agreement. This adjustment does not result in a charge to our statement of operations, but rather as an
adjustment to our retained earnings.

CPE Inc.'s
payments under the Tax Receivable Agreement would be greater if CPE Inc. generates income significantly in excess of its current estimated future taxable income
over the anticipated life of its mines, for example, because CPE Inc. acquires additional LBAs beyond its existing LBAs and, as a result, CPE Inc. realizes the full tax benefit of such
increased tax basis (or an increased portion thereof). Required payments under the Tax Receivable Agreement also may increase or become accelerated as a result of certain asset transfers outside the
ordinary course of business, a change in control of CPE Resources, or a default by CPE Inc.

Contingencies

Litigation



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

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

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. Commitments and Contingencies (Continued)

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

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



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



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

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. Commitments and Contingencies (Continued)

and
results. For example, the West Antelope II LBA, which we have nominated for lease with the Bureau of Land Management, is subject to pending legal challenges filed in 2010 against the Bureau of
Land Management and the Secretary of the Interior by environmental organizations.

Tax Contingencies

Our income tax calculations are based on application of the respective U.S. federal or state tax law. Our tax filings, however, are
subject to audit by the respective tax authorities. Accordingly, we recognize tax benefits when it is more likely than not a position will be upheld by the tax authorities. To the extent the final tax
liabilities are different from the amounts originally accrued, the increases or decreases are recorded as income tax expense. We are not potentially liable for income tax contingencies related to
periods prior to our IPO, as the income taxes recognized in our consolidated financial statements for such periods were reported in Rio Tinto America's consolidated income tax returns, and Rio Tinto
has agreed to indemnify us for any claims related to such income taxes.

Several
audits involving our taxes other than income taxes currently are in progress. We have provided our best estimate of taxes and related interest and penalties due for potential
adjustments that may result from the resolution of such tax audits.

Concentrations of Risk and Major Customer

Approximately 83%, 84% and 69% of our revenues for the years ended December 31, 2010, 2009 and 2008, respectively, were under
multi-year contracts which specify pricing terms. While the majority of the contracts are fixed-price contracts, certain contracts have escalation provisions for determining periodic price
changes. No single customer accounted for 10% or more of revenues in 2010. One customer accounted for revenues of $140.4 million and $135.1 million for the years ended
December 31, 2009 and 2008, respectively, representing more than 10% of consolidated revenues. We generally do not require collateral or other security on accounts receivable because our
customers are comprised primarily of investment grade electric utilities. The credit risk is controlled through credit approvals and monitoring procedures.

Guarantees and Off-Balance Sheet Risk

In the normal course of business, we are party to guarantees and financial instruments with off-balance sheet risk, such as
bank letters of credit, performance or surety bonds and indemnities, which are not reflected on the consolidated balance sheet. In our past experience, virtually no claims have been made against these
financial instruments. Management does not expect any material losses to result from these guarantees or off-balance-sheet instruments.

United
States federal and state laws require we secure certain of our obligations to reclaim lands used for mining and to secure coal lease obligations. The primary method we have used
to meet these reclamation obligations and to secure coal lease obligations is to provide a third-party surety bond, typically through an insurance company, or provide a letter of credit, typically
through a bank. Specific bond and or letter of credit amounts may change over time, depending on the activity at the respective site and any specific requirements by federal or state laws. As of
December 31, 2010, we had $10.5 million of standby of letters of credit and $525.0 million of performance bonds outstanding (including our proportional share of the Decker mine)
to secure certain of our obligations to reclaim lands used for mining and to secure coal lease obligations.

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. Related Party Transactions

Credit Arrangements and Guarantee Fees

While we were a subsidiary of Rio Tinto, Rio Tinto served as guarantor of our surety bonds and certain letters of credit securing our
obligations were issued on our behalf under Rio Tinto's credit facilities. In connection with the IPO structuring transactions, we agreed to use our commercially reasonable efforts to obtain new
surety bonds, letters of credit or other credit arrangements and to obtain the full release of Rio Tinto with respect to the existing arrangements. As of December 31, 2009, Rio Tinto remained
the guarantor under these arrangements and we maintained $80.2 million in restricted cash as collateral for the benefit of Rio Tinto. As of December 31, 2010, we had obtained replacement
surety bonds for all of the $445.5 million in bonds for which Rio Tinto had been the guarantor. Included in interest expense was $683,000 in fees Rio Tinto charged us in connection with
transitional support of our credit arrangements for the year ended December 31, 2010, and $1.2 million of guarantee fees for the year ended December 31, 2009.

Transitional Support Services

Following our IPO, Rio Tinto affiliates provided certain transitional support services to us pursuant to a transition services
agreement. Costs incurred under this agreement are included in selling, general and administrative expenses and totaled $464,000 for the period from November 20, 2009 to December 31,
2009.

We
began leasing office space from Rio Tinto America during 2007. Rental expense for this lease was $245,000, $367,000 and $651,000 for the years ended December 31, 2010, 2009 and
2008, respectively.

Following
the distribution of our interests in Colowyo and the uranium mining venture (see Note 4), we provided certain transitional management and administrative support services
to the distributed entities on a cost reimbursement basis. Fees for these transitional support services are included as a reduction in cost of product sold and selling, general and administrative
expenses, and totaled $1.4 million for the year ended December 31, 2009. These transitional services were terminated in March 2009.

Coal Sales

Included in revenues were $27.7 million, $21.4 million and $13.6 million for the years ended December 31,
2010, 2009 and 2008, respectively, for sales of coal to Venture Fuels Partnership, a 50% owned coal marketing company.

Other Commercial Transactions

From time to time, we enter into arms-length commercial arrangements in the ordinary course of business with Rio Tinto,
including selling coal to Rio Tinto and engaging Rio Tinto for agency services in connection with our export coal sales. Since our November 2009 IPO and through the twelve months ended
December 31, 2010, we have paid approximately $0.3 million for agency services and received $8.6 million for export coal sales agreements. For calendar years 2011 and 2012, we
expect to pay approximately $0.7 million for agency services and receive approximately $17.4 million for export coal sales agreements based on currently proposed transactions.

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. Related Party Transactions (Continued)

For additional related party transactions, see "Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering" and "Pre-IPO Expense Allocations" in
Note 2 and Part III of this Form 10-K.

19. Segment Information

Our management reviews, manages and operates our business as a single operating segmentthe production of low sulfur, steam coal from surface mines, located in the Western
region of the U.S. within the Powder River Basin ("PRB"), which is sold to electric utilities and industrial customers.

The
following table presents a summary of total revenues from external customers by geographic location for the years ended December 31 (in thousands):

2010

2009

2008United States

$
1,194,800

$
1,271,738

$
1,183,299Other


175,961


126,462


56,412Total revenues from external customers

$
1,370,671

$
1,398,200

$
1,239,711


We
attribute revenue to individual countries based on the location of the customer. Our sales outside of the United States are made primarily to customers in Asia and Canada.

As
of December 31, 2010 and 2009, all of our long-lived assets were located in the U.S. All of our revenues for the years ended December 31, 2010, 2009 and 2008
originated in the U.S.

20. Cloud Peak Energy Inc. (Parent Company Only) Financial Information

The following parent company only condensed financial information reflects the financial condition, results of operations and cash flows of Cloud Peak Energy Inc. The results of
operations and cash flows are for the years ended December 31, 2010, 2009 and 2008.

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. Cloud Peak Energy Inc. (Parent Company Only) Financial Information (Continued)

Condensed Statements of Operations

Period Ended
December 31,2010

2009

2008(in thousands)Revenues

$
9,469

$
475

$
Costs and expensesGeneral and administrative expenses


9,517


475


116Total costs and expenses


9,517


475


116Loss before equity in earnings of consolidated subsidiaries and income taxes


(48
)




(116
)Equity in earnings of Cloud Peak Energy Resources LLC


86,237


12,791


Interest expense


(21
)




Change in TRA liability


(19,669
)




Income tax provision


(32,762
)

(4,216
)

Net income (loss)

$
33,737

$
8,575

$
(116
)


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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. Cloud Peak Energy Inc. (Parent Company Only) Financial Information (Continued)

Condensed Balance Sheets

December 31,2010

2009(in thousands)ASSETSCurrent assetsCash

$
1

$
Deferred income taxes


6,483


280Due from related party


11,297


Prepaid income tax


5,505


Other assets


1,200


891Total current assets


24,486


1,171Deferred income taxes


62,021


100,520Other assets


96


Investment in Cloud Peak Energy Resources LLC


639,260


205,995Total assets

$
725,863

$
307,686LIABILITIES and SHAREHOLDERS' EQUITYCurrent liabilitiesAccounts payable

$
133

$
Due to related party





106Current portion of tax agreement liability


18,226


758Accrued expenses


4,420


166Total current liabilities


22,779


1,030Tax agreement liability, net of current portion


171,885


53,751Total liabilities


194,664


54,781Total shareholders' equity


531,199


252,905Total liabilities and shareholders' equity

$
725,863

$
307,686


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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. Cloud Peak Energy Inc. (Parent Company Only) Financial Information (Continued)

Condensed Statements of Cash Flows

Period Ended
December 31,2010

2009

2008(in thousands)Operating activitiesNet income (loss)

$
33,737

$
8,575

$
(116
)Adjustments to reconcile net income (loss) to net cash used in operating activities


(33,736
)

(8,575
)

116Net cash used in operating activities


1





Investing activitiesNet cash provided by investing activities








Financing activitiesIssuance of common stock





433,755


Distribution to Rio Tinto America





(433,755
)

Net cash provided by financing activities








Increase (decrease) in cash and cash equivalents


1





Cash and cash equivalents at beginning of period








Cash and cash equivalents at end of period

$
1

$


$



21. Summary Unaudited Quarterly Financial Information

A summary of the unaudited quarterly results of operations for the years ended December 31, 2010 and 2009 is presented below (in thousands except share amounts).

Year Ended December 31, 2010First
Quarter

Second
Quarter

Third
Quarter

Fourth
QuarterRevenues

$
310,993

$
341,603

$
372,364

$
345,801Operating income


47,826


58,306


64,350


41,393Income from continuing operations


28,762


39,170


19,516


29,749Net income


28,762


39,170


19,516


29,749Net income (loss) attributable to controlling interest


11,597


15,858


(6,599
)

12,881Income (loss) per common share from continuing operations attributable to the controlling interest:Basic

$
0.38

$
0.52

$
(0.22
)
$
0.28Diluted

$
0.38

$
0.51

$
(0.22
)
$
0.28


Our
second, third and fourth quarter 2010 operating results included $4.3 million ($3.5 million after tax), $4.3 million ($3.5 million after tax), and
$6.8 million ($4.4 million after tax) charges due to updates to estimates for non-income based taxes.

Our
third quarter 2010 operating results included a $19.7 million charge to income from continuing operations and a $5.4 million charge to income tax expense related to our
Tax Receivable

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

21. Summary Unaudited Quarterly Financial Information (Continued)

Agreement.
See Note 17. This adjustment reduced third quarter income from continuing operations and net income by $25.1 million, and reduced related basic and diluted per share amounts
by $0.77.

In
the fourth quarter of 2010, we completed the Secondary Offering (see Note 2).

Year Ended December 31, 2009First
Quarter

Second
Quarter

Third
Quarter

Fourth
QuarterRevenues

$
360,493

$
343,552

$
357,241

$
336,914Operating income


64,140


69,531


73,260


48,072Income from continuing operations


45,155


49,623


52,490


35,204Net income


56,809


60,416


72,833


203,492Net income attributable to controlling interest


56,809


60,416


72,833


191,643Income per common share from continuing operations attributable to the controlling interest:Basic

$
0.75

$
0.83

$
0.87

$
0.50Diluted

$
0.75

$
0.83

$
0.87

$
0.50


In
the fourth quarter of 2009, we sold the Jacobs Ranch mine (see Note 4), completed our initial public offering and related IPO structuring transactions (see Note 2),
entered into debt financing transactions, including the issuance of our Senior Notes and the execution of our Credit Facility (see Note 9) and granted share-based compensation awards to our
employees and directors (see Note 15).

Our
fourth quarter 2009 operating results included a $3.6 million favorable adjustment to amortization expense related to an acquired coal supply contract that expires in 2010.
See Note 7. This adjustment increased fourth quarter income from continuing operations and net income by $2.5 million, and increased related diluted per share amounts by $0.01, with no
impact on related basic per share amounts.

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

None

Item 9A.Controls and Procedures.

Disclosure Controls and Procedures

An evaluation was performed by management, under the supervision and with the participation of our Chief Executive Officer and Chief
Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2010. Our Chief Executive Officer and Chief Financial Officer,
have concluded that our disclosure controls and procedures, which are designed to provide reasonable assurance that information required to be disclosed in reports filed under the Securities and
Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the specified time periods and accumulated and communicated to our management, including our Chief Executive
Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure, were effective at a reasonable assurance level as of December 31, 2010.

Our
management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all
error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the
inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected.

Management's Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange
Act Rule 13a-15(f). Internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer, and effected by
our Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for
external purposes in accordance with generally accepted accounting principles.

Because
of 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.

Management
conducted an evaluation of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) inInternal ControlIntegrated Framework. Based on this evaluation,
management concluded that the Company's internal control over financial reporting was effective as of December 31, 2010.

Our
independent registered public accounting firm, PricewaterhouseCoopers LLP, has audited the effectiveness of our internal control over financial reporting as of
December 31, 2010, as stated in their audit report included herein.

Remediation Steps to Address the Previously Disclosed Material Weaknesses

We previously reported material weaknesses in our internal controls over financial reporting related to maintaining a sufficient
complement of personnel with an appropriate level of accounting, taxation and financial reporting knowledge, experience and training in the application of U.S. GAAP

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Table of Contents

commensurate
with our financial reporting requirements on a stand-alone basis and the complexity of our operations and transactions. The previously reported material weaknesses also related to
maintaining an adequate system of processes and internal controls sufficient to support our financial reporting requirements and produce timely and accurate U.S. GAAP consolidated financial
statements consistent with being a stand-alone public company.

We
have implemented changes and improvements in our internal control over financial reporting to remediate the control deficiencies that gave rise to the material weaknesses. These
changes included:



We
completed the remedial procedures described above and have concluded that the steps taken were sufficient to eliminate the previously disclosed material weaknesses.

Changes in Internal Control Over Financial Reporting

As described above, there were changes in our internal control over financial reporting during the quarter ended December 31,
2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.Other Information.

We had a strong safety performance in 2010. According to MSHA data for our three owned and operated mines, we had one of the lowest
2010 all injury frequency rates (AIFR) among the ten largest U.S. coal producers of 0.58. For the three months ended December 31, 2010, the AIFR for our three owned and operated mines was 0.27
(calculated internally based on MSHA methodology). The AIFR is the number of reportable injuries suffered by employees per 200,000 hours worked.

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Quarterly Reporting Pursuant to Wall Street Reform and Consumer Protection Act Section 1503

As provided by Section 1503 of the Wall Street Reform and Consumer Protection Act, Cloud Peak Energy provides the following
safety-related information for our three operated mines:

Year Ended December 31, 2010Item

Antelope Mine

Cordero Rojo
Mine

Spring Creek
MineSection 104 S&S citations (#)(1)


15

8


Section 104(b) orders (#)(2)







Section 104(d) citations and orders (#)(3)







Section 110(b)(2) violations (#)(4)







Section 107(a) orders (#)(5)




1


Proposed MSHA assessments ($)(6)

$
23,264

$22,102

$
1,542Fatalities (#)(7)







Section 104(e) notices(8)







Pending Mine Safety Commission legal actions (including any contested penalties for citations issued)(9)




One pending
proceeding under
Section 105(c)(10)







Three Months Ended December 31, 2010Item

Antelope Mine

Cordero Rojo
Mine

Spring Creek
MineSection 104 S&S citations (#)(1)


2




Section 104(b) orders (#)(2)







Section 104(d) citations and orders (#)(3)







Section 110(b)(2) violations (#)(4)







Section 107(a) orders (#)(5)







Proposed MSHA assessments ($)(6)

$
319




Fatalities (#)(7)







Section 104(e) notices(8)







Pending Mine Safety Commission legal actions (including any contested penalties for citations issued)(9)




One pending
proceeding under
Section 105(c)(10)





(1)Total
number of violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a coal
mine safety or health hazard under section 104 of the Federal Mine Safety and Health Act of 1977 (30 U.S.C. 814) (the Act) for which we received a citation from MSHA.(2)Total
number of orders issued under section 104(b) of the Act (30 U.S.C. 814(b)).(3)Total
number of citations and orders for unwarrantable failure of Cloud Peak Energy to comply with mandatory health or safety standards under
section 104(d) of the Act (30 U.S.C. 814(d)).(4)Total
number of flagrant violations under section 110(b)(2) of the Act (30 U.S.C. 820(b)(2)).(5)Total
number of imminent danger orders issued under section 107(a) of the Act (30 U.S.C. 817(a)).


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(6)Total
dollar value of proposed assessments from MSHA under the Act (30 U.S.C. 801 et seq.).(7)Total
number of mining-related fatalities.(8)Any
coal mines owned and operated by us that received written notice from MSHA of (A) a pattern of violations of mandatory health or safety standards
that are of such nature as could have significantly and substantially contributed to the cause and effect of coal mine health or safety hazards under section 104(e) of such Act (30 U.S.C.
814(e)); or (B) the potential to have such a pattern.(9)Any
pending legal action before the Federal Mine Safety and Health Review Commission involving a coal mine owned and operated by us.(10)Docket
No. WEST 2010-1314-D in which a terminated employee claims that such termination constituted unlawful retaliation for
alleged safety-related statements made to the company.


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PART III

Item 10.Directors, Executive Officers and Corporate Governance.

The information required by Items 401, 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is
included under the caption Election of Class II Directors in our Proxy Statement to be distributed to our stockholders in connection with our 2011 annual meeting and in Part I of this
report under the caption Executive Officers of the Company. Such information is incorporated herein by reference. The information required by Items 405, 406 and 407(c)(3), (d)(4) and (d)(5) of
Regulation S-K is included under the captions Section 16(a) Beneficial Ownership Reporting Compliance, Corporate Governance and Executive Compensation, respectively, in our
Proxy Statement to be distributed to our stockholders in connection with our 2011 annual meeting under the caption Executive Compensation and is incorporated herein by reference.

Item 11.Executive Compensation.

The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K is included in our Proxy
Statement to be distributed to our stockholders in connection with our 2011 annual meeting under the caption Executive Compensation and is incorporated herein by reference.

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

The information required by Item 403 of Regulation S-K is included under the caption Security Ownership of
Management and Principal Stockholders in our Proxy Statement to be distributed to our stockholders in connection with our 2011 annual meeting and is incorporated herein by reference.

As
required by Item 201(d) of Regulation S-K, the following table provides information regarding our equity compensation plans as of December 31, 2010:

Plan Category

Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights

Weighted-average
exercise price of
outstanding options,
warrants and rights

Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))(a)

(b)

(c)Equity compensation plans approved by security holders


1,032,495

$
15.07


1,489,188Equity compensation plans not approved by security holders








Total


1,032,495

$
15.07


1,489,188


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

The information required by Item 404 of Regulation S-K is included under the captions Certain Relationships
and Related Transactions and Independence of Directors in our Proxy Statement and is incorporated herein by reference. The information required by Item 407(a) of
Regulation S-K is included under the caption Executive Compensation in our Proxy Statement to be distributed to our stockholders in connection with our 2011 annual meeting and is
incorporated herein by reference.

Item 14.Principal Accounting Fees and Services.

The information required by Item 9(e) of Schedule 14A is included under the caption Fees Paid to Independent Registered
Public Accounting Firm in our Proxy Statement to be distributed to our stockholders in connection with our 2011 annual meeting and is incorporated herein by reference.

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PART IV

Item 15.Exhibits and Financial Statement Schedules

(1)

Reports of Independent Registered Public Accounting FirmConsolidated Balance Sheets as of December 31, 2010 and 2009Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008Consolidated Statements of Equity for the Years Ended December 31, 2010, 2009 and 2008Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008Notes to Consolidated Financial Statements(2)

Reserved(3)

Exhibit List


The
following documents are filed as part of this annual report on Form 10-K. The Company will furnish a copy of any exhibit listed to requesting stockholders upon
payment of the Company's reasonable expenses in furnishing those materials.

Exhibit
Number

Description of Documents2.1

Membership Interest Purchase Agreement, dated as of March 8, 2009 by and between Rio Tinto Sage LLC and Arch Coal, Inc. (incorporated herein by reference to Exhibit 2.1 to Arch Coal, Inc.'s
Current Report on From 8-K filed on March 12, 2009), as amended by the first amendment, dated as of April 6, 2009 (incorporated herein by reference to Exhibit 2.3 to Arch Coal, Inc.'s Quarterly Report on Form 10-Q for the
quarter ended March 31, 2009), as amended by the second amendment, dated as of September 30, 2009 (Incorporated herein by reference to Exhibit 2.1 to Arch Coal, Inc.'s Current Report on Form 8-K filed on October 1,
2009)3.1

Amended and Restated Certificate of Incorporation of Cloud Peak Energy Inc. effective as of November 25, 2009 (Incorporated by reference to Exhibit 3.2 to Amendment No. 3 to the Company's
Form S-1 filed on November 2, 2009)3.2

Amended and Restated Bylaws of Cloud Peak Energy Inc. effective as of November 25, 2009 (Incorporated by reference to Exhibit 3.1 of the Company's current report on Form 8-K filed on
December 2, 2009)4.1

Form of stock certificate of Cloud Peak Energy Inc. (Incorporated by reference to Exhibit 4.1 of the Amendment No. 5 to Company's Form S-1 filed on November 16, 2009)4.2

Indenture, dated as of November 25, 2009, by and among CPE LLC (and its subsidiaries listed on the signature page), Cloud Peak Energy Finance Corp., Wilmington Trust Company and Citibank, N.A. (Incorporated
by reference to Exhibit 4.1 of the Company's current report on Form 8-K filed on December 2, 2009)


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Exhibit
Number

Description of Documents4.3

Registration Rights Agreement, dated as of November 25, 2009, by and among CPE LLC (and its subsidiaries listed on the signature page thereto), Cloud Peak Energy Finance Corp., and Morgan
Stanley & Co. Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets Corporation, as the representatives of the several purchasers (Incorporated by reference to Exhibit 4.2 of the Company's current report on
Form 8-K filed on December 2, 2009)10.1

Federal Coal Lease WYW-151643: Antelope Coal Mine (Incorporated by reference to Exhibit 10.1 of the Company's Form S-1 filed on August 12, 2009)10.2

Federal Coal Lease WYW-141435: Antelope Coal Mine (Incorporated by reference to Exhibit 10.2 of the Company's Form S-1 filed on August 12, 2009)10.3

Federal Coal Lease WYW-0321780: Antelope Coal Mine (Incorporated by reference to Exhibit 10.3 of the Company's Form S-1 filed on August 12, 2009)10.4

Federal Coal Lease WYW-0322255: Antelope Coal Mine (Incorporated by reference to Exhibit 10.4 of the Company's Form S-1 filed on August 12, 2009)10.5

State of Wyoming Coal Lease No. 0-26695: Antelope Coal Mine (Incorporated by reference to Exhibit 10.5 of the Company's Form S-1 filed on August 12, 2009)10.6

Federal Coal Lease WYW-8385: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.6 of the Company's Form S-1 filed on August 12, 2009)10.7

Federal Coal Lease WYW-23929: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.7 of the Company's Form S-1 filed on August 12, 2009)10.8

Federal Coal Lease WYW 174407: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.8 of the Company's Form S-1 filed on August 12, 2009)10.9

Federal Coal Lease WYW-154432: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.9 of the Company's Form S-1 filed on August 12, 2009)10.10

State of Wyoming Coal Lease No. 0-26935-A: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.10 of the Company's Form S-1 filed on August 12, 2009)10.11

State of Wyoming Coal Lease No. 0-26936-A: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.11 of the Company's Form S-1 filed on August 12, 2009)10.12

Federal Coal Lease MTM-88405: Spring Creek Mine (Incorporated by reference to Exhibit 10.12 of the Company's Form S-1 filed on August 12, 2009)10.13

Modified Federal Coal Lease MTM-069782: Spring Creek Mine (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed on June 18 2010)10.14

Federal Coal Lease MTM-94378: Spring Creek Mine (Incorporated by reference to Exhibit 10.14 of the Company's Form S-1 filed on August 12, 2009)10.15

State of Montana Coal Lease No. C-1101-00: Spring Creek Mine (Incorporated by reference to Exhibit 10.15 of the Company's Form S-1 filed on August 12, 2009)10.16

State of Montana Coal Lease No. C-1099-00: Spring Creek Mine (Incorporated by reference to Exhibit 10.16 of the Company's Form S-1 filed on August 12, 2009)10.17

State of Montana Coal Lease No. C-1100-00: Spring Creek Mine (Incorporated by reference to Exhibit 10.17 of the Company's Form S-1 filed on August 12, 2009)


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Exhibit
Number

Description of Documents10.18

State of Montana Coal Lease No. C-1088-05: Spring Creek Mine (Incorporated by reference to Exhibit 10.18 of the Company's Form S-1 filed on August 12, 2009)10.19

Agreement by and among Western Minerals, Inc., Wytana, Inc., Montana Royalty Company, Ltd. and Peter Kiewit Sons' Inc., dated September 1, 1970, as amended by supplement dated as of
January 1, 1974, amendment No. 2 dated as of December 1, 1977, amendment No. 3, dated as of August 24, 1978, amendment No. 4, dated as of January 1, 1982, amendment No. 5, dated as of July 9, 1983,
amendment No. 6, dated as of May 7, 1985, amendment No. 7, dated as of January 1, 1989, amendment No. 8, dated as of January 1, 1989, amendment No. 9, dated as of December 13, 1990 (sic), amendment No. 10,
dated as of January 1, 1999, and amendment No. 11, dated as of April 9, 2002 (Incorporated by reference to Exhibit 10.19 of the Company's Form S-1 filed on August 12, 2009)10.20

Master Separation Agreement, dated as of November 19, 2009, by and among Cloud Peak Energy Inc., Cloud Peak Energy Resources LLC, Rio Tinto America Inc., Rio Tinto Energy America Inc. and
Kennecott Management Services Company (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on November 25, 2009)10.21

Transition Services Agreement, dated as of November 19, 2009, by and among Cloud Peak Energy Inc., Cloud Peak Energy Resources LLC and Rio Tinto Services Inc. (Incorporated by reference to
Exhibit 10.2 to the Company's Current Report on Form 8-K filed on November 25, 2009)10.22

Registration Rights Agreement, dated as of November 19, 2009, by and among Cloud Peak Energy Inc., Cloud Peak Energy Resources LLC, Rio Tinto America Inc., Rio Tinto Energy America Inc., and
Kennecott Management Services Company (Incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed on November 25, 2009)10.23

Employee Matters Agreement, dated as of November 19, 2009, by and among Cloud Peak Energy Inc., Cloud Peak Energy Resources LLC, Rio Tinto America Inc., Rio Tinto Energy America Inc., Cloud
Peak Energy Services Company and, for a limited purpose, Rio Tinto plc and Rio Tinto Limited (Incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed on November 25, 2009)10.24

Third Amended and Restated Limited Liability Company Agreement, dated as of November 19, 2009, by and among Cloud Peak Energy Inc., Rio Tinto Energy America Inc. and Kennecott Management Services
Company (Incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed on November 25, 2009)10.25

Acquisition Agreement, dated as of November 19, 2009, by and between Cloud Peak Energy Inc. and Rio Tinto Energy America Inc. (Incorporated by reference to Exhibit 10.6 to the Company's Current
Report on Form 8-K filed on November 25, 2009)10.26

Promissory Note, dated as of November 19, 2009, by Cloud Peak Energy Inc. in favor of Rio Tinto Energy America Inc. (Incorporated by reference to Exhibit 10.7 to the Company's Current Report on
Form 8-K filed on November 25, 2009)10.27

Trademark Assignment Agreement, dated as of November 19, 2009, by and among Cloud Peak Energy Resources LLC and Rio Tinto Energy America Inc. (Incorporated by reference to Exhibit 10.8 to the
Company's Current Report on Form 8-K filed on November 25, 2009)10.28

Management Services Agreement, dated as of November 19, 2009, by and between Cloud Peak Energy Inc. and Cloud Peak Energy Resources LLC (Incorporated by reference to Exhibit 10.9 to the Company's
Current Report on Form 8-K filed on November 25, 2009)


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Table of Contents

Exhibit
Number

Description of Documents10.29

RTEA Coal Supply Agreement, dated as of November 19, 2009, by and between Cloud Peak Energy Resources LLC and Rio Tinto Energy America Inc. (Incorporated by reference to Exhibit 10.10 to the Company's
Current Report on Form 8-K filed on November 25, 2009)10.30

Tax Receivable Agreement, dated as of November 19, 2009, by and between Cloud Peak Energy Inc. and Rio Tinto Energy America Inc. (Incorporated by reference to Exhibit 10.11 to the Company's Current
Report on Form 8-K filed on November 25, 2009)10.31

Credit Agreement, dated as of November 25, 2009, by and among CPE LLC, Morgan Stanley Senior Funding, Inc., Credit Suisse AG, Cayman Islands Branch, RBC Capital Markets, Calyon New York Branch, JPMorgan
Chase Bank, N.A., The Bank of Nova Scotia, Societe Generale, and Wells Fargo Bank, National Association (Incorporated by reference to Exhibit 10.1 of the Company's current report on Form 8-K filed on December 2, 2009)10.32

Guarantee and Security Agreement, dated as of November 25, 2009, by and between CPE LLC (and its subsidiaries listed on the signature page) and Morgan Stanley Senior Funding, Inc. (Incorporated by
reference to Exhibit 10.2 of the Company's current report on Form 8-K filed on December 2, 2009)10.33

Escrow Agreement, dated as of November 25, 2009, by and among CPE LLC, Rio Tinto Energy America Inc., and SunTrust Bank (Incorporated by reference to Exhibit 10.3 of the Company's current report on
Form 8-K filed on December 2, 2009)10.34

Assignment Agreement between Rio Tinto Energy America Inc. and Cloud Peak Energy LLC dated October 29, 2009 (Incorporated by reference to Exhibit 10.42 to Amendment No. 3 to the Company's
Form S-1 filed on November 2, 2009)10.35

Cloud Peak Energy Inc. 2009 Long Term Incentive Plan (Incorporated by reference to Exhibit 10.32 to Amendment No. 5 to the Company's Form S-1 filed on November 16, 2009)10.36

Form of IPO Director Restricted Stock Agreement under the Cloud Peak Energy Inc. 2009 Long Term Incentive Plan (Incorporated by reference to Exhibit 10.44 to Amendment No. 5 to the Company's
Form S-1 filed on November 16, 2009)10.37

Form of IPO Nonqualified Stock Option Agreement under the Cloud Peak Energy Inc. 2009 Long Term Incentive Plan (Incorporated by reference to Exhibit 10.33 to Amendment No. 5 to the Company's
Form S-1 filed on November 16, 2009)10.38

Form of IPO Restricted Stock Agreement under the Cloud Peak Energy Inc. 2009 Long Term Incentive Plan (Incorporated by reference to Exhibit 10.34 to Amendment No. 5 to the Company's Form S-1 filed
on November 16, 2009)10.39

Form of Cloud Peak Energy Inc. Annual Incentive Plan (Incorporated by reference to Exhibit 10.35 to Amendment No. 5 to the Company's Form S-1 filed on November 16, 2009)10.40

Employment Agreement between Cloud Peak Energy Inc. and Colin Marshall dated as of November 14, 2009 (Incorporated by reference to Exhibit 10.40 to the Company's Annual Report on Form 10-K filed on
March 17, 2010)10.41

Employment Agreement between Cloud Peak Energy Inc. and Michael Barrett dated as of November 14, 2009 (Incorporated by reference to Exhibit 10.41 to the Company's Annual Report on Form 10-K filed
on March 17, 2010)10.42

Employment Agreement between Cloud Peak Energy Inc. and Adrian Nick Taylor dated as of November 14, 2009 (Incorporated by reference to Exhibit 10.42 to the Company's Annual Report on Form 10-K
filed on March 17, 2010)


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Exhibit
Number

Description of Documents10.43

Employment Agreement between Cloud Peak Energy Inc. and Gary Rivenes dated as of November 14, 2009 (Incorporated by reference to Exhibit 10.43 to the Company's Annual Report on Form 10-K filed on
March 17, 2010)10.44

Employment Agreement between Cloud Peak Energy Inc. and James Orchard dated as of November 14, 2009 (Incorporated by reference to Exhibit 10.44 to the Company's Annual Report on Form 10-K filed on
March 17, 2010)10.45

Employment Agreement between Cloud Peak Energy Inc. and Cary Martin dated as of November 14, 2009 (Incorporated by reference to Exhibit 10.45 to the Company's Annual Report on Form 10-K filed on
March 17, 2010)10.46

Employment Agreement between Cloud Peak Energy Inc. and Bryan Pechersky dated as of March 3, 2010 (Incorporated by reference to Exhibit 10.46 to the Company's Annual Report on Form 10-K filed on
March 17, 2010)10.47

Employment Agreement between Cloud Peak Energy Inc. and Todd Myers dated as of July 6, 2010 (Incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q filed on
August 5, 2010)10.48
*
Form of Director Restricted Stock Unit Agreement under the Cloud Peak Energy Inc. 2009 Long Term Incentive Plan21.1
*
List of subsidiaries of Cloud Peak Energy Inc.23.1
*
Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm23.2
*
Consent of J.T. Boyd Company31.1
*
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 200231.2
*
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 200232.1
*
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 200232.2
*
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


*Filed
or furnished herewith


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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.

CLOUD PEAK ENERGY INC.Date: February 24, 2011

By:

/s/ COLIN MARSHALL Colin Marshall Principal Executive Officer


Pursuant
to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities and on the dates indicated:

Name and Signatures

Title

Date/s/ COLIN MARSHALL Colin Marshall

(Principal Executive Officer and Director)

February 24, 2011/s/ MICHAEL BARRETT Michael Barrett

(Principal Financial Officer)

February 24, 2011/s/ HEATH HILL Heath Hill

(Principal Accounting Officer)

February 24, 2011/s/ KEITH BAILEY Keith Bailey

(Chairman of the Board of Directors)

February 24, 2011/s/ WILLIAM T. FOX III William T. Fox III

(Director)

February 24, 2011/s/ C. KEVIN MCARTHUR C. Kevin McArthur

(Director)

February 24, 2011/s/ STEVEN W. NANCE Steven W. Nance

(Director)

February 24, 2011/s/ WILLIAM F. OWENS William F. Owens

(Director)

February 24, 2011/s/ CHRIS TONG Chris Tong

(Director)

February 24, 2011


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Table of Contents

EXHIBIT INDEX

The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.

Exhibit
Number

Description of Documents2.1

Membership Interest Purchase Agreement, dated as of March 8, 2009 by and between Rio Tinto Sage LLC and Arch Coal, Inc. (incorporated herein by reference to Exhibit 2.1 to Arch Coal, Inc.'s
Current Report on From 8-K filed on March 12, 2009), as amended by the first amendment, dated as of April 6, 2009 (incorporated herein by reference to Exhibit 2.3 to Arch Coal, Inc.'s Quarterly Report on Form 10-Q for the
quarter ended March 31, 2009), as amended by the second amendment, dated as of September 30, 2009 (incorporated herein by reference to Exhibit 2.1 to Arch Coal, Inc.'s Current Report on Form 8-K filed on October 1,
2009)3.1

Amended and Restated Certificate of Incorporation of Cloud Peak Energy Inc. effective as of November 25, 2009 (Incorporated by reference to Exhibit 3.2 to Amendment No. 3 to the Company's
Form S-1 filed on November 2, 2009)3.2

Amended and Restated Bylaws of Cloud Peak Energy Inc. effective as of November 25, 2009 (Incorporated by reference to Exhibit 3.1 of the Company's current report on Form 8-K filed on
December 2, 2009)4.1

Form of stock certificate of Cloud Peak Energy Inc. (Incorporated by reference to Exhibit 4.1 of the Amendment No. 5 to Company's Form S-1 filed on November 16, 2009)4.2

Indenture, dated as of November 25, 2009, by and among CPE LLC (and its subsidiaries listed on the signature page), Cloud Peak Energy Finance Corp., Wilmington Trust Company and Citibank, N.A. (Incorporated
by reference to Exhibit 4.1 of the Company's current report on Form 8-K filed on December 2, 2009)4.3

Registration Rights Agreement, dated as of November 25, 2009, by and among CPE LLC (and its subsidiaries listed on the signature page thereto), Cloud Peak Energy Finance Corp., and Morgan
Stanley & Co. Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets Corporation, as the representatives of the several purchasers (Incorporated by reference to Exhibit 4.2 of the Company's current report on
Form 8-K filed on December 2, 2009)10.1

Federal Coal Lease WYW-151643: Antelope Coal Mine (Incorporated by reference to Exhibit 10.1 of the Company's Form S-1 filed on August 12, 2009)10.2

Federal Coal Lease WYW-141435: Antelope Coal Mine (Incorporated by reference to Exhibit 10.2 of the Company's Form S-1 filed on August 12, 2009)10.3

Federal Coal Lease WYW-0321780: Antelope Coal Mine (Incorporated by reference to Exhibit 10.3 of the Company's Form S-1 filed on August 12, 2009)10.4

Federal Coal Lease WYW-0322255: Antelope Coal Mine (Incorporated by reference to Exhibit 10.4 of the Company's Form S-1 filed on August 12, 2009)10.5

State of Wyoming Coal Lease No. 0-26695: Antelope Coal Mine (Incorporated by reference to Exhibit 10.5 of the Company's Form S-1 filed on August 12, 2009)10.6

Federal Coal Lease WYW-8385: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.6 of the Company's Form S-1 filed on August 12, 2009)10.7

Federal Coal Lease WYW-23929: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.7 of the Company's Form S-1 filed on August 12, 2009)


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Table of Contents

Exhibit
Number

Description of Documents10.8

Federal Coal Lease WYW 174407: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.8 of the Company's Form S-1 filed on August 12, 2009)10.9

Federal Coal Lease WYW-154432: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.9 of the Company's Form S-1 filed on August 12, 2009)10.10

State of Wyoming Coal Lease No. 0-26935-A: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.10 of the Company's Form S-1 filed on August 12, 2009)10.11

State of Wyoming Coal Lease No. 0-26936-A: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.11 of the Company's Form S-1 filed on August 12, 2009)10.12

Federal Coal Lease MTM-88405: Spring Creek Mine (Incorporated by reference to Exhibit 10.12 of the Company's Form S-1 filed on August 12, 2009)10.13

Modified Federal Coal Lease MTM-069782: Spring Creek Mine (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed on June 18, 2010)10.14

Federal Coal Lease MTM-94378: Spring Creek Mine (Incorporated by reference to Exhibit 10.14 of the Company's Form S-1 filed on August 12, 2009)10.15

State of Montana Coal Lease No. C-1101-00: Spring Creek Mine (Incorporated by reference to Exhibit 10.15 of the Company's Form S-1 filed on August 12, 2009)10.16

State of Montana Coal Lease No. C-1099-00: Spring Creek Mine (Incorporated by reference to Exhibit 10.16 of the Company's Form S-1 filed on August 12, 2009)10.17

State of Montana Coal Lease No. C-1100-00: Spring Creek Mine (Incorporated by reference to Exhibit 10.17 of the Company's Form S-1 filed on August 12, 2009)10.18

State of Montana Coal Lease No. C-1088-05: Spring Creek Mine (Incorporated by reference to Exhibit 10.18 of the Company's Form S-1 filed on August 12, 2009)10.19

Agreement by and among Western Minerals, Inc., Wytana, Inc., Montana Royalty Company, Ltd. and Peter Kiewit Sons' Inc., dated September 1, 1970, as amended by supplement dated as of
January 1, 1974, amendment No. 2 dated as of December 1, 1977, amendment No. 3, dated as of August 24, 1978, amendment No. 4, dated as of January 1, 1982, amendment No. 5, dated as of July 9, 1983,
amendment No. 6, dated as of May 7, 1985, amendment No. 7, dated as of January 1, 1989, amendment No. 8, dated as of January 1, 1989, amendment No. 9, dated as of December 13, 1990 (sic), amendment No. 10,
dated as of January 1, 1999, and amendment No. 11, dated as of April 9, 2002 (Incorporated by reference to Exhibit 10.19 of the Company's Form S-1 filed on August 12, 2009)10.20

Master Separation Agreement, dated as of November 19, 2009, by and among Cloud Peak Energy Inc., Cloud Peak Energy Resources LLC, Rio Tinto America Inc., Rio Tinto Energy America Inc. and
Kennecott Management Services Company (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on November 25, 2009)10.21

Transition Services Agreement, dated as of November 19, 2009, by and among Cloud Peak Energy Inc., Cloud Peak Energy Resources LLC and Rio Tinto Services Inc. (Incorporated by reference to
Exhibit 10.2 to the Company's Current Report on Form 8-K filed on November 25, 2009)10.22

Registration Rights Agreement, dated as of November 19, 2009, by and among Cloud Peak Energy Inc., Cloud Peak Energy Resources LLC, Rio Tinto America Inc., Rio Tinto Energy America Inc., and
Kennecott Management Services Company (Incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed on November 25, 2009)


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Table of Contents

Exhibit
Number

Description of Documents10.23

Employee Matters Agreement, dated as of November 19, 2009, by and among Cloud Peak Energy Inc., Cloud Peak Energy Resources LLC, Rio Tinto America Inc., Rio Tinto Energy America Inc., Cloud Peak
Energy Services Company and, for a limited purpose, Rio Tinto plc and Rio Tinto Limited (Incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed on November 25, 2009)10.24

Third Amended and Restated Limited Liability Company Agreement, dated as of November 19, 2009, by and among Cloud Peak Energy Inc., Rio Tinto Energy America Inc. and Kennecott Management Services
Company (Incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed on November 25, 2009)10.25

Acquisition Agreement, dated as of November 19, 2009, by and between Cloud Peak Energy Inc. and Rio Tinto Energy America Inc. (Incorporated by reference to Exhibit 10.6 to the Company's Current
Report on Form 8-K filed on November 25, 2009)10.26

Promissory Note, dated as of November 19, 2009, by Cloud Peak Energy Inc. in favor of Rio Tinto Energy America Inc. (Incorporated by reference to Exhibit 10.7 to the Company's Current Report on
Form 8-K filed on November 25, 2009)10.27

Trademark Assignment Agreement, dated as of November 19, 2009, by and among Cloud Peak Energy Resources LLC and Rio Tinto Energy America Inc. (Incorporated by reference to Exhibit 10.8 to the
Company's Current Report on Form 8-K filed on November 25, 2009)10.28

Management Services Agreement, dated as of November 19, 2009, by and between Cloud Peak Energy Inc. and Cloud Peak Energy Resources LLC (Incorporated by reference to Exhibit 10.9 to the Company's
Current Report on Form 8-K filed on November 25, 2009)10.29

RTEA Coal Supply Agreement, dated as of November 19, 2009, by and between Cloud Peak Energy Resources LLC and Rio Tinto Energy America Inc. (Incorporated by reference to Exhibit 10.10 to the
Company's Current Report on Form 8-K filed on November 25, 2009)10.30

Tax Receivable Agreement, dated as of November 19, 2009, by and between Cloud Peak Energy Inc. and Rio Tinto Energy America Inc. (Incorporated by reference to Exhibit 10.11 to the Company's Current
Report on Form 8-K filed on November 25, 2009)10.31

Credit Agreement, dated as of November 25, 2009, by and among CPE LLC, Morgan Stanley Senior Funding, Inc., Credit Suisse AG, Cayman Islands Branch, RBC Capital Markets, Calyon New York Branch, JPMorgan
Chase Bank, N.A., The Bank of Nova Scotia, Societe Generale, and Wells Fargo Bank, National Association (Incorporated by reference to Exhibit 10.1 of the Company's current report on Form 8-K filed on December 2, 2009)10.32

Guarantee and Security Agreement, dated as of November 25, 2009, by and between CPE LLC (and its subsidiaries listed on the signature page) and Morgan Stanley Senior Funding, Inc. (Incorporated by
reference to Exhibit 10.2 of the Company's current report on Form 8-K filed on December 2, 2009)10.33

Escrow Agreement, dated as of November 25, 2009, by and among CPE LLC, Rio Tinto Energy America Inc., and SunTrust Bank (Incorporated by reference to Exhibit 10.3 of the Company's current report on
Form 8-K filed on December 2, 2009)10.34

Assignment Agreement between Rio Tinto Energy America Inc. and Cloud Peak Energy LLC dated October 29, 2009 (Incorporated by reference to Exhibit 10.42 to Amendment No. 3 to the Company's
Form S-1 filed on November 2, 2009)10.35

Cloud Peak Energy Inc. 2009 Long Term Incentive Plan (Incorporated by reference to Exhibit 10.32 to Amendment No. 5 to the Company's Form S-1 filed on November 16, 2009)


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Table of Contents

Exhibit
Number

Description of Documents10.36

Form of IPO Director Restricted Stock Agreement under the Cloud Peak Energy Inc. 2009 Long Term Incentive Plan (Incorporated by reference to Exhibit 10.44 to Amendment No. 5 to the Company's Form S-1
filed on November 16, 2009)10.37

Form of IPO Nonqualified Stock Option Agreement under the Cloud Peak Energy Inc. 2009 Long Term Incentive Plan (Incorporated by reference to Exhibit 10.33 to Amendment No. 5 to the Company's
Form S-1 filed on November 16, 2009)10.38

Form of IPO Restricted Stock Agreement under the Cloud Peak Energy Inc. 2009 Long Term Incentive Plan (Incorporated by reference to Exhibit 10.34 to Amendment No. 5 to the Company's Form S-1 filed
on November 16, 2009)10.39

Form of Cloud Peak Energy Inc. Annual Incentive Plan (Incorporated by reference to Exhibit 10.35 to Amendment No. 5 to the Company's Form S-1 filed on November 16, 2009)10.40

Employment Agreement between Cloud Peak Energy Inc. and Colin Marshall dated as of November 14, 2009 (Incorporated by reference to Exhibit 10.40 to the Company's Annual Report on Form 10-K filed on
March 17, 2010)10.41

Employment Agreement between Cloud Peak Energy Inc. and Michael Barrett dated as of November 14, 2009 (Incorporated by reference to Exhibit 10.41 to the Company's Annual Report on Form 10-K filed
on March 17, 2010)10.42

Employment Agreement between Cloud Peak Energy Inc. and Adrian Nick Taylor dated as of November 14, 2009 (Incorporated by reference to Exhibit 10.42 to the Company's Annual Report on Form 10-K
filed on March 17, 2010)10.43

Employment Agreement between Cloud Peak Energy Inc. and Gary Rivenes dated as of November 14, 2009 (Incorporated by reference to Exhibit 10.43 to the Company's Annual Report on Form 10-K filed on
March 17, 2010)10.44

Employment Agreement between Cloud Peak Energy Inc. and James Orchard dated as of November 14, 2009 (Incorporated by reference to Exhibit 10.44 to the Company's Annual Report on Form 10-K filed on
March 17, 2010)10.45

Employment Agreement between Cloud Peak Energy Inc. and Cary Martin dated as of November 14, 2009 (Incorporated by reference to Exhibit 10.45 to the Company's Annual Report on Form 10-K filed on
March 17, 2010)10.46

Employment Agreement between Cloud Peak Energy Inc. and Bryan Pechersky dated as of March 3, 2010 (Incorporated by reference to Exhibit 10.43 to the Company's Annual Report on Form 10-K filed on
March 17, 2010)10.47

Employment Agreement between Cloud Peak Energy Inc. and Todd Myers dated as of July 6, 2010 (Incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q filed on
August 5, 2010)10.48
*
Form of Director Restricted Stock Unit Agreement under the Cloud Peak Energy Inc. 2009 Long Term Incentive Plan21.1
*
List of subsidiaries of Cloud Peak Energy Inc.23.1
*
Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm23.2
*
Consent of Consent of J.T. Boyd Company31.1
*
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 200231.2
*
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002


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Table of Contents

Exhibit
Number

Description of Documents32.1
*
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 200232.2
*
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


*Filed
or furnished herewith


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