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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, 2009oro

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(IRS 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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes o    No o

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

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

Large accelerated filer o

Accelerated filer o

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

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

DOCUMENTS INCORPORATED BY REFERENCE

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



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TABLE OF CONTENTS



PAGEPART IITEM 1

BUSINESS

7ITEM 1A

RISK FACTORS

31ITEM 1B

UNRESOLVED STAFF COMMENTS

61ITEM 2

PROPERTIES

61ITEM 3

LEGAL PROCEEDINGS

65ITEM 4

RESERVED

66PART IIITEM 5

MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

67ITEM 6

SELECTED FINANCIAL DATA

69ITEM 7

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

74ITEM 7A

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

104ITEM 8

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

105ITEM 9

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

152ITEM 9A

CONTROLS AND PROCEDURES

152ITEM 9B

OTHER INFORMATION

153PART IIIITEM 10

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

154ITEM 11

EXECUTIVE COMPENSATION

154ITEM 12

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

154ITEM 13

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

154ITEM 14

PRINCIPAL ACCOUNTING FEES AND SERVICES

154PART IVITEM 15

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

155


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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.

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

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

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

GW.Gigawatts.

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

Incident 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:



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

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

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

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

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

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

MSHA.Mine Safety and Health Administration.

NAAQ.National Ambient Air Quality.

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

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

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

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

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

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

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

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

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

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

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

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

Riverine habitat.A habitat occurring along a river.

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

SMCRA.Surface Mining Control and Reclamation Act of 1977.

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

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

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

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

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

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

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

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

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

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

History

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

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

GRAPHIC

Coal Characteristics

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

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Heat Value

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

Sulfur Content

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

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

Other

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

Moisture
content of coal varies by the type of coal and the region where it is mined. In general, high moisture content is associated with lower heat values and generally makes the coal
more expensive to transport. Moisture content in coal, on an as-sold basis, can range from approximately 2% to over 30% of the coal's weight. PRB coals have typical moisture content of 25%
to 35%.

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

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Coal Mining Methods

Surface Mining

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

Coal Preparation and Blending

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

Mining Operations

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

2009 As Delivered Average

Tons Sold
(in millions)Mine

Maximum
Production
Capacity(1)

Btu
per lb

Ash
Content(2)

Sulfur Content

2009

2008

2007(million tons)



(%)

(%)

(lbs SO2/mmBtu)

(million tons)Antelope


42


8,870


5.3


0.26


0.6


34.0


35.8


34.5Cordero Rojo


65


8,400


5.5


0.31


0.7


39.3


40.0


40.5Spring Creek


20


9,235


5.4


0.32


0.7


17.6


17.9


15.7Decker(3)


16


9,465


4.4


0.41


0.9


2.3


3.3


3.5Other(4)


N/A


N/A


N/A


N/A


N/A


10.1


8.1


8.1Total

















103.3


105.1


102.3


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


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(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 a Lease by Application, or LBA, a large coal tract adjacent to our existing
operation. The Bureau of Land Management, or BLM, will determine if the tract will be leased, and if so, the final boundaries of, and the coal tonnage for, this tract. Acquisition of this tract would
facilitate access to approximately 80 million tons of non-reserve coal deposits that we control. We currently expect the BLM will schedule this LBA for bid sometime in 2011. Other
potential large areas of unleased coal north and west of the mine are available for nomination by us or other mining operations or persons.

Cordero Rojo Mine

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

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

Spring Creek Mine

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

Decker Mine

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

Customers and Coal Contracts

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

Sales and Marketing

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



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

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Customers

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

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, 2009, approximately 6% of our committed tons were associated with contracts that had three years or more remaining on their term. Most of our supply contracts include a fixed price
for the term of the agreement or a pre-determined escalation in price for each year. Some of our agreements that extend for a four- or five-year term or longer may
include a variable pricing system. These contracts allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales price. For the year
ended December 31, 2009, approximately 97% of our revenues were derived from long-term supply contracts with a term of one year or greater. While most of our sales contracts are for
terms of one to five years, some are as short as one to six months, and other contracts have terms longer than ten years.

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

Our
coal is primarily sold on a mine-specific basis to utility customers through a request-for-proposal process. The terms of our coal sales
agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer, including base price adjustment features, price
re-opener terms, coal quality requirements, quantity parameters, permitted sources of supply, impact of future regulatory changes, extension options, force majeure, termination, assignment
and other provisions.

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

Price
re-opener and index provisions, which can be either renegotiated or based on a fixed formula, are present in contracts covering approximately 40% of our total future
tonnage commitments. These provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may
automatically set a new price based on prevailing market price or, in some instances, require us to negotiate a new price, sometimes between a specified range of prices. In some agreements, if the
parties do not agree on a new price, either party has an option to terminate the contract. Under some of our contracts, we have the right to match lower prices offered to our customers by other
suppliers. In addition, some of our contracts contain clauses which may allow customers to terminate the contract in the event of certain changes in environmental laws and regulations.

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

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

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

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

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

Broker Sales and Third-Party Sources

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

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

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

Transportation

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

Suppliers

Principal supplies used in our business include petroleum-based fuels, explosives, tires, steel and other raw materials, as well as
spare parts and other consumables used in the mining process. We use third-party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services and construction. We use
sole source suppliers for certain parts of our business such as dragline shovel parts and services and tires. We believe adequate substitute suppliers are available. For further discussion of our
suppliers, see Item 1A "Risk FactorsRisks Related to Our Business and Industry

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

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

Competition

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

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

Employees

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

Executive Officers of the Company

Set forth below is information concerning our current executive officers.

Name

Age

Position(s)Colin Marshall


45

President, Chief Executive Officer and DirectorMichael Barrett


41

Executive Vice President and Chief Financial OfficerGary Rivenes


40

Executive Vice President and Chief Operating OfficerCary Martin


57

Senior Vice President, Human ResourcesJames Orchard


49

Senior Vice President, Marketing and Government AffairsBryan Pechersky


39

Senior Vice President and General CounselA. Nick Taylor


59

Senior Vice President, Technical ServicesTerri Eggert


49

Vice President of Finance and Chief Accounting Officer


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

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

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

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

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

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

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

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

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

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

Environmental and Other Regulatory Matters

Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety,
permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the
discharge of materials into the environment and the effects of mining on surface and groundwater quality and availability. These laws and regulations have had, and will continue to have, a significant
effect on our production costs and our competitive position. Future laws, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or
orders, may require substantial increases in equipment and operating costs and delays, interruptions or a termination of operations, the extent of which we cannot predict. Future laws, regulations or
orders, including those dealing with climate change, may also cause coal to become a less attractive fuel source, thereby reducing coal's share of the market for fuels and other energy sources used to
generate electricity. As a result, future laws, regulations or orders may adversely affect our mining operations, cost structure or our customers' demand for coal.

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

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Mining Permits and Approvals

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

In
order to obtain mining permits and approvals from federal and state regulatory authorities, mine operators must submit a reclamation plan for restoring, upon the completion of mining
operations, the mined property to its prior condition, productive use or other permitted condition. Typically, we submit the necessary permit applications several months or even years before we plan
to begin mining a new area.

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

Surface Mining Control and Reclamation Act

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

SMCRA
permit provisions include a complex set of requirements, which include, among other things, coal prospecting, mine plan development, topsoil or growth medium removal and
replacement, selective handling of overburden materials, mine pit backfilling and grading, disposal of excess spoil, protection of the hydrologic balance, surface runoff and drainage control,
establishment of suitable post mining land uses and re-vegetation. We begin the process of preparing a mining permit application by collecting baseline data to adequately characterize the
pre-mining environmental conditions of the permit area. This work is typically conducted by third-party consultants with specialized expertise and typically includes surveys and/or
assessments of the following: cultural and historical resources; geology; soils; vegetation; aquatic organisms; wildlife; potential for threatened, endangered or other special status species; surface
and ground water hydrology; climatology; riverine and riparian habitat and wetlands. The geologic data and information derived from the surveys and/or assessments are used to develop the mining and
reclamation plans presented in the permit application. The mining and reclamation plans address the provisions and performance standards of the state's equivalent SMCRA

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regulatory
program, and are also used to support applications for other authorizations and/or permits required to conduct coal mining activities. Also included in the SMCRA permit application is
information used for documenting surface and mineral ownership, variance requests, access roads, bonding information, mining methods, mining phases, other agreements that may relate to coal, other
minerals, oil and gas rights, water rights, permitted areas and ownership and control information required to determine compliance with OSM's Applicant Violator System, including the mining and
compliance history of officers, directors and principal owners of the entity.

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

In
addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund, which was created by SMCRA, imposes a fee on all coal produced. The proceeds of the
fee are used to restore mines closed or abandoned prior to SMCRA's adoption in 1977. The current fee is $0.315 per ton of coal produced from surface mines. In 2009, we recorded $28.7 million of
expense related to these reclamation fees.

Surety Bonds

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

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

Mine Safety and Health

Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The
Federal Mine Safety and Health Act of 1977, or the Mine Act, significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining
operations. In addition to federal regulatory programs, all of the states in which we operate also have state programs for mine safety and health regulation and

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

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

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

Clean Air Act

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

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



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Climate Change

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

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

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

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

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

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

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

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

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

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

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

Clean Water Act

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

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





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Resource Conservation and Recovery Act

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

Comprehensive Environmental Response, Compensation and Liability Act

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

Endangered Species Act

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

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

Use of Explosives

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

Other Environmental Laws

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

Available Information

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

We
also make the documents listed above available without charge through our website, www.cloudpeakenergy.com, as soon as practicable after we file or furnish them with the SEC. You may
also request copies of the documents, at no cost, by telephone at (303) 713-5000 or by mail at Cloud Peak Energy Inc., 8051 East Maplewood Avenue, Greenwood Village, Colorado
80111, Attention: Vice President, Investor Relations. The information on our website is not part of this Annual Report on Form 10-K.

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Item 1A.Risk Factors.

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

Risks Related to Our Business and Industry

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

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

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

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

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



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

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

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



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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.

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

We compete with numerous other coal producers in various regions of the U.S. for domestic sales. International demand for U.S. coal
also affects competition within our industry. The demand for U.S. coal exports depends upon a number of factors, including the overall demand for electricity in foreign markets; currency exchange
rates; ocean freight rates; port and shipping capacity; the demand for foreign-produced steel, both in foreign markets and in the U.S. market; general economic conditions in foreign countries;
technological developments; and environmental and other governmental regulations. Foreign demand for eastern U.S. coal increased significantly during 2008 but declined during 2009. A further decline
in foreign demand for U.S. could cause competition among coal producers for sales in the U.S. to intensify, potentially resulting in significant additional downward pressure on domestic coal prices,
including in the PRB.

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

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

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

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

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

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

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

In 2009, we sold approximately 95% of our coal to domestic electric power generators. Domestic electric power generation accounted for
approximately 94% of all U.S. coal consumption in 2009, according to the Energy Information Administration, or EIA. The amount of coal consumed for U.S. electric power generation is affected by, among
other things:



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

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energy
sources. In addition, environmental activists concerned with climate change issues have attempted to use the regulatory and judicial processes to block the construction of new
coal-fired power plants or capacity expansions to existing plants. Further, state and federal mandates for increased use of electricity from renewable energy sources could have an impact
on the market for our coal. Many states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been
numerous proposals to establish a similar uniform, national standard. Although none of these federal proposals have been enacted to date, the Obama Administration has indicated its support for a
federal renewable energy standard, and federal legislation imposing such a mandate is currently under consideration by Congress. Possible advances in technologies and incentives, such as tax credits,
to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by U.S. electric power generators could reduce
the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

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

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

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



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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 greenhouse gas emissions from the new plants. Additionally, two U.S. federal appeals courts have reinstated lawsuits permitting individuals, state attorneys general and others to pursue
claims against major utility, coal, oil and chemical companies on the basis that those companies have created a public nuisance due to their emissions of carbon dioxide.

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

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

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

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

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

Our
ability to obtain additional coal reserves in the future could also be limited by the availability of cash we generate from our operations or available financing, restrictions under
our debt instruments, competition from other coal companies for properties, the lack of suitable acquisition or LBA

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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



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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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our
coal. Alternatively, less stringent air emissions limitations, particularly related to sulfur, to the extent enacted, could make low-sulfur coal less attractive, which could also have
a material adverse effect on the demand for, and prices received for, our coal.

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

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



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

New
legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the
protection of the environment that would further regulate and tax the coal industry, may also require us to change operations significantly or incur increased costs. Such changes could have a material
adverse effect on our financial condition and results of operations.

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

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

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

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

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

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

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

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

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

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

Mining companies must obtain a number of permits that impose strict regulations on various environmental and operational matters in
connection with coal mining. These include permits issued by various federal, state and local agencies and regulatory bodies. The permitting rules, and the interpretations of these rules, are complex,
change frequently and are often subject to discretionary interpretations by the regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of
ongoing operations or the development of future mining operations. The public, including non-governmental organizations, anti-mining groups and individuals, have certain
statutory rights to comment upon and submit objections to requested permits and EISs prepared in connection with applicable regulatory processes, and otherwise engage in the permitting process,
including bringing citizens' lawsuits to challenge the issuance of permits, the validity of EISs or performance of mining activities. Recently, environmental groups made extensive comments to an EIS
prepared in connection with one of our federal mining lease applications. These groups argued that the EIS failed to satisfactorily consider climate change risks. If this or any other permits or
leases are not issued or renewed in a timely fashion or at all, or if permits or leases issued or renewed are conditioned in a manner that restricts our ability to efficiently and economically conduct
our mining activities, we could suffer a material reduction in our production, and our cash flow or profitability could be materially and adversely affected.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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



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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Risks Related to Our Indebtedness

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

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



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

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

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

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

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

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

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

Risks Related to Our Corporate Structure and Our IPO Structuring Transactions

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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



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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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



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

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

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

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

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

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

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

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

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

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

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

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

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

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



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

Item 1B.Unresolved Staff Comments.

None

Item 2.Properties.

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

Coal Reserves

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

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

Mine

Proven
Preserves

Probable
Reserves

Total Proven
& Probable
Reserves

Assigned
Reserves

Reserves
Owned

Reserves
Leased(nearest million, in tons)

(%)

(nearest million, in tons)Antelope


281


11


292


100


0


292Cordero Rojo


318


92


410


100


38


372Spring Creek


258


42


300


100


0


300Decker(1)


1


0


1


100


0


1Total(2)


859


145


1,004





38


966


(1)Based
on our 50% interest in our 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, 2009:

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


292


8,850


0.24


0.54Cordero Rojo


410


8,400


0.29


0.69Spring Creek


300


9,350


0.33


0.71Decker(3)


1


9,400


0.40


0.85Total(4)


1,004


(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 our 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:



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

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

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

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

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

Reserve Acquisition Process

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

We
acquire a significant portion of our coal through the LBA process, and as a result, substantially all of our coal is held under federal leases. Under this process, before a mining
company can obtain new federal coal, the company must nominate a coal tract for lease and then win the lease through a competitive bidding process. The LBA process can last anywhere from two to five
years from the time the coal tract is nominated to the time a final bid is accepted by the BLM. After the LBA is awarded, the company then conducts the necessary testing to determine what amount can
be classified as reserves and begins the process to permit the coal for mining, which generally takes another two to five years.

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

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

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

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agencies
during this process, including state and federal agencies, surface management agencies, Native American tribes or bands, the U.S. Department of Justice or others as needed. The public comment
period for an analysis or impact statement typically occurs over a 60-day period.

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

Each
of our federal coal leases has an initial term of 20 years, renewable for subsequent 10-year periods and for so long thereafter as coal is produced in commercial
quantities. The lease requires diligent development within the first ten years of the lease award with a required coal extraction of 1% of the total coal under the lease by the end of that
10-year period. At the end of the 10-year development period, the lessee is required to maintain continuous operations, as defined in the applicable leasing regulations. In
certain cases, a lessee may combine contiguous leases into a logical mining unit, or LMU. This allows the production of coal from any of the leases within the LMU to be used to meet the continuous
operation requirements for the entire LMU. We currently have an LMU for our Antelope mine. We pay to the federal government an annual rent of $3.00 per acre and production royalties of 12.5% of gross
revenues on surface mined coal. The federal government remits approximately 50% of the production royalty payments to the state
after deducting administrative expenses. Some of our mines are also subject to coal leases with the states of Montana or Wyoming, as applicable, and have different terms and conditions that we must
adhere to in a similar way to our federal leases. Under these federal and state leases, if the leased coal is not diligently developed during the initial 10-year development period or if
certain other terms of the leases are not complied with, including the requirement to produce a minimum quantity of coal or pay a minimum production royalty, if applicable, the BLM or the applicable
state regulatory agency can terminate the lease prior to the expiration of its term.

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

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

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

Office Space

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

Item 3.Legal Proceedings.

MMS LitigationDecker

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

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

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

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

Caballo Coal Company LitigationSpring Creek

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

Other Legal Proceedings

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

Item 4.Reserved.

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PART II

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

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

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

Dividend Policy

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

Stock Performance Graph

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

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

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

GRAPHIC

November 20,
2009

November 30,
2009

December 31,
2009Cloud Peak Energy Inc.

$
100

$
90

$
97S&P MidCap 400

$
100

$
99

$
105Custom Composite Index (5 Stocks)

$
100

$
95

$
104


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

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Item 6.Selected Financial Data.

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

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

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

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

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Selected Consolidated Financial and Other Data

Year Ended December 31,2009

2008

2007

2006

2005(dollars in thousands, except per share amounts)Statement of Operations DataRevenues(1)

$
1,398,200

$
1,239,711

$
1,053,168

$
942,841

$
783,929Operating income(2)(3)


255,003


124,936


102,731


88,868


77,294Income from continuing operations


182,472


88,340


53,789


40,537


39,995Income (loss) from discontinued operations(4)


211,078


(25,215
)

(21,482
)

(2,599
)

336Net income


393,550


63,125


32,307


37,938


40,331Amounts attributable to controlling interest(5)Income from continuing operations


170,623


88,340


53,789


40,537


39,995Income (loss) from discontinued operations(4)


211,078


(25,215
)

(21,482
)

(2,599
)

336Net income


381,701


63,125


32,307


37,938


40,331Earnings per sharebasic(5)(6)Income from continuing operations

$
3.01

$
1.47

$
0.90

$
0.68

$
0.67Income (loss) from discontinued operations(4)

$
3.73

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

$
6.74

$
1.05

$
0.54

$
0.63

$
0.67Earnings per share attributable to controlling interestdiluted(5)(6)Income from continuing operations

$
2.97

$
1.47

$
0.90

$
0.68

$
0.67Income (loss) from discontinued operations(4)

$
3.52

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

$
6.49

$
1.05

$
0.54

$
0.63

$
0.67




December 31,2009

2008

2007

2006

2005(dollars in thousands)Balance Sheet DataCash and cash equivalents

$
268,316

$
15,935

$
23,616

$
19,585

$
11,355Property, plant and equipment, net


987,143


927,910


719,743


703,726


616,411Assets of continuing operations(4)


1,677,596


1,198,023


1,059,366


1,029,269


966,504Total assets


1,677,596


1,785,191


1,781,201


1,723,335


1,694,208Senior notes, net of unamortized discount


595,321











Other long-term debt(7)


178,367


209,526


571,559


665,735


601,450Liabilities of continuing operations(4)


1,232,118


672,805


1,176,191


1,163,493


1,079,166Total liabilities


1,232,118


800,025


1,446,240


1,433,480


1,411,898Controlling interest equity(5)


252,905


985,166


334,961


289,855


282,310Noncontrolling interest equity(5)


192,573














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Year Ended December 31,2009

2008

2007

2006

2005(dollars in thousands)Other DataEBITDA(8)

$
395,568

$
278,872

$
232,324

$
191,832

$
173,433Tons soldcompany owned and operated mines (millions)


90.9


93.7


90.7


88.2


80.8Tons soldDecker mine (millions)


2.3


3.3


3.5


3.6


3.5Tons soldtotal production (millions)


93.2


97.0


94.2


91.8


84.3Tons purchased and resold (millions)


10.1


8.1


8.1


8.1


6.7Total tons sold (millions)


103.3


105.1


102.3


99.9


91.0


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However,
using EBITDA as a performance measure has material limitations as compared to net income, or other financial measures as defined under U.S. GAAP, as it excludes certain recurring items
which may be meaningful to investors. 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.
Further, EBITDA excludes depreciation and depletion and amortization; however, as we use capital and intangible assets to generate revenues, depreciation, depletion and amortization are necessary
elements of our costs and ability to generate revenue. 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. Finally, EBITDA excludes income taxes; however, as
we are organized as a corporation, the payment of taxes is a necessary element of our operations. As a result of these exclusions from EBITDA, any measure that excludes interest expense, interest
income, depreciation and depletion, amortization, accretion and income taxes has material limitations as compared to net income. When using EBITDA as a performance measure, management compensates for
these limitations by comparing EBITDA to net income in each period, so as to allow for the comparison of the performance of the underlying core operations with the overall performance of the Company
on a full-cost, after-tax basis. Using both EBITDA and net income 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.

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Year Ended December 31,2009

2008

2007

2006

2005(dollars in thousands)Income from continuing operations

$
182,472

$
88,340

$
53,789

$
40,537

$
39,995Depreciation and depletion


97,869


88,972


80,133


59,352


50,130Amortization


28,719


45,989


34,512


34,957


35,645Accretion


12,587


12,742


12,212


10,088


8,391Interest expense


5,992


20,376


40,930


38,785


26,771Interest income


(320
)

(2,865
)

(7,302
)

(3,604
)

(1,493
)Income tax provision


68,249


25,318


18,050


11,717


13,994EBITDA

$
395,568

$
278,872

$
232,324

$
191,832

$
173,433


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

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

Overview

We are the third largest producer of coal in the U.S. and in the PRB based on 2009 coal production. We operate some of the safest mines
in the coal industry. For 2009, 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 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, 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.

As
of December 31, 2009, we controlled approximately 1.0 billion tons of proven and probable coal reserves. For the year ended December 31, 2009, we produced
93.3 million tons of coal and sold 103.3 million tons of coal.

Our
key business drivers include the following:



In
the longer term, we expect that costs related to the acquisition of federal coal leases will increase as they have become increasingly more competitive and expensive to obtain,
resulting in higher depletion expense as we increase our mining activities at more recently acquired federal coal leases. As is common in the PRB, coal seams at our existing mines naturally deepen at
a gradient ranging up to approximately 3%, consequently our mining costs per ton will correspondingly increase as mining advances.

In
2007, after having started 2006 with reduced stockpiles of PRB coal, our customers' inventories normalized and demand for our coal stabilized. During the period from 2006 to
mid-2008, we experienced an improving pricing environment as a result of an overall increase in prices for energy-based commodities, such as natural gas and crude oil. As a result, we
experienced an increase in our average revenue per ton of coal sold which contributed to the growth in our revenues. 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, has 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. Consequently, despite a decrease in tons sold
from 2008 to 2009, we experienced an increase in total revenues from sales of coal. As a result of the decreased demand for coal and increasing customer stockpiles of coal, some of

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our
customers have sought to reduce or delay delivery of tons under their contracts with us, leading to negotiations which, in certain cases, resulted in reduced tons, rolling over tons into future
periods, or customer buyouts of purchase commitments. 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 reduction efforts, which resulted in reducing utilization
of contractors, lowering employee overtime, and optimizing repairs and maintenance expense.

In
the first few months of 2010, as a result of economic conditions and increased natural gas prices and also due to normal seasonal changes in weather, there has been an increase in
coal consumption. In addition, the increased price of natural gas, an alternative to coal, may be an indication that consumers will revert back to higher coal consumption. Although coal stockpiles
remain at historically high levels, our customers have begun to draw down their stockpiles. As a result of the shorter term contracts we have entered into more recently, if the U.S. coal market
rebounds in the shorter term, we may not experience as much of a lag as we would have historically. If, however, the U.S. coal market remains depressed, our revenues could be adversely affected for a
prolonged period of time.

We
have one significant broker sales contract under which our subsidiary, Spring Creek Coal LLC, has agreed to sell purchased coal to a wholesale power generation company. Due to
the nature of the broker sales contract and the market conditions at the time Spring Creek Coal LLC executed the purchase contracts, our selling price for the coal is higher than our purchase
price. Final deliveries are expected to be made under the contract in early 2010, at which time we expect the contract to expire and the related contract rights intangible asset to be fully amortized.
This broker sales contract contributed $140.4 million, $135.1 million and $116.6 million of revenues for the years ended December 31, 2009, 2008 and 2007, respectively.
Income before tax related to this contract was $46.3 million, $38.4 million and $41.4 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, $33.3 million and $31.1 million, respectively. Our revenues and operating
income will be negatively impacted after the first quarter of 2010 as a result of the expiration of this contract.

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.

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Basis of Presentation

Initial Public Offering and IPO Structuring Transactions

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 and Related IPO Structuring Transactions" 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.

For
all periods presented, our historical consolidated financial statements include the accounts of CPE Resources and its subsidiaries. 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. 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. 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, the former parent company. Rio Tinto's remaining ownership interest in CPE Resources is reported as a
noncontrolling interest in our consolidated financial statements for periods following our IPO.

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.

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



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The
effects of our IPO and related structuring agreements on our financial condition and results of our operations are described further below. Read our Unaudited Pro Forma Consolidated
Statement of Operations provided within this Management's Discussion and Analysis of Financial Condition and
Results of Operations to better understand how our results and financial statement presentation are impacted by our IPO and related IPO Structuring Agreements.

Discontinued Operations

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.

Decker Mine

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

Revenues

We sell coal primarily to electricity generating utilities and industrial customers in the U.S. A substantial majority of our revenues
is comprised of sales of coal from our coal mines and from our 50% non-operating interest in the Decker coal mine. Coal produced from these mines accounted for 79.0% of our total revenues
for the year ended December 31, 2009. Our revenues also include the resale of purchased coal, or broker coal sales, which represented 13.3% of total revenues for the year ended
December 31, 2009. As discussed in "Overview" above, a single broker coal sales contract accounted for a substantial majority of our broker coal sales and 10% of our total revenues
in 2009. Delivery services to customers also is a component of our revenues, representing 6.9% of total revenues in 2009. Typically our customers contract directly with the third-party railroad
operators to transport

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coal
purchased from us, but in certain circumstances we arrange transportation and delivery services. Contract settlements and other revenues accounted for less than one percent of our revenues in
2009.

Our
coal sales revenues depend on the forward price at the time we contract to sell our coal. The pricing provisions of our contracts determine the price we are entitled to receive when
we deliver the coal under the contracts. We sell our coal predominantly under long-term contracts having a term of one year or greater, supplemented by short-term contracts
having a term of less than one year. At the start of 2009, we had entered into agreements to sell all of the planned 2009 production from our owned and operated mines; however, our actual shipments
were approximately 98% of our planned production for 2009 as a result of decreased demand. As of December 31, 2009, we had entered into contracts to sell substantially all of our 2010 planned
production. See Item 1 "BusinessCustomers and Coal ContractsLong-term Coal Sales Agreements" for a description of some of the common terms of our
long-term coal supply contracts.

Cost of Product Sold

Cost of product sold includes costs of coal production, costs of coal purchased and resold, and freight and handling costs associated
with the provision of transportation and delivery services. Coal production costs include costs of our owned and operated mines and our
share of costs of the Decker mine. The largest component of cost of coal production is royalties and production taxes incurred in selling the coal we produce. Royalties and production taxes are
comprised of federal and state royalties and approximately seven other federal, state and county taxes. A substantial portion of our royalties and taxes are levied as a percentage of gross revenues
from sales of coal we produced, with the remaining levied on a per-ton basis. Because such a large portion of our royalties and production taxes are levied on a percentage of gross
revenues, as our revenues increase, our royalty and production tax expenses similarly increase. Royalties and production taxes represented 29.0% of revenues from coal produced at our owned and
operated mines and 43.2% of the related cost of coal produced for the year ended December 31, 2009.

Cost
of coal production is sensitive to changes in diesel fuel prices. For our owned and operated mines, the weighted average cost of diesel fuel was $1.87 per gallon for the year ended
December 31, 2009, compared to $3.31 per gallon for the year ended December 31, 2008. However, the cost of diesel fuel rose during 2009, increasing from an average cost per gallon of
$1.53 for the first quarter of 2009 compared to $2.17 for the fourth quarter of 2009. Diesel fuel and lubricant expenses represented 7.8% of cost of coal production at our owned and operated mines for
the year ended December 31, 2009. Other major elements of cost of coal production include labor costs for our employees, repair and maintenance expenditures, explosives, external contractors,
tires, power and supplies. 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,
although in 2009 certain of these costs declined. We have not entered into any hedging or other arrangements to reduce the volatility in the price of diesel fuel for our operations, although we may do
so in the future. Also included in cost of coal production are exploration costs to survey, map, drill and evaluate deposits surrounding our mining areas. Prior to our IPO, we were allocated
corporate, general and administrative expenses incurred by Rio Tinto America and other Rio Tinto affiliates, of which $4.9 million was included in cost of product sold for the year ended
December 31, 2009.

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The
table below shows the major components of the cost of coal production for the mines we own and operate for the years ended December 31, 2009, 2008 and 2007:

Components of Cost of Coal Production
(Company owned and operated mines)

2009

2008

2007Royalties and taxes


43.2
%

39.7
%

40.2
%Labor


20.2
%

18.8
%

19.8
%Repairs and maintenance


14.4
%

13.8
%

15.0
%Fuel and lubricants


7.8
%

12.9
%

11.4
%Explosives


6.1
%

6.7
%

5.9
%Outside services


5.1
%

5.0
%

6.4
%Other mining costs (includes exploration, power and supplies)


3.2
%

3.1
%

1.3
%


Depreciation and Depletion

We depreciate our plant and equipment on a straight-line basis over its useful life or on a
units-of-production basis. We also recognize depletion expense as we mine coal from purchased coal leases. We acquire the right to mine coal from the Bureau of Land Management,
or BLM, under the LBA process. See Item 2 "PropertiesReserve Acquisition Process." We pay the BLM in five equal annual installments to acquire the coal lease. We recognize the
present value of these installments on our balance sheet in property, plant and equipment, and recognize depletion expenses in our statement of operations based on the tons of coal mined from the coal
lease. Federal coal leases are becoming increasingly more competitive and expensive to obtain, resulting in higher depletion expense as we increase our mining activities at more recently acquired coal
leases.

Amortization

We amortize intangible assets associated with acquired contract rights. The only intangible asset on our consolidated balance sheet as
of December 31, 2009 relates to a contract held by Spring Creek Coal LLC, which is explained above under "Overview." The intangible contract right asset is amortized as
deliveries are made. Final deliveries are expected to be made under the contract in March 2010, at which time we expect the contract to expire and the intangible asset to be fully amortized. As a
result, we anticipate that amortization expense will cease following the first quarter of 2010.

Accretion

We have an obligation to complete final reclamation and mine closure activities, including earthwork, revegetation and demolition,
which will be performed when our mines eventually exhaust their reserves and close. We record a liability for this obligation based on the net present value of the estimated costs to perform the work,
including the estimated timing of those costs.
Each year we get closer to the estimated end of the mine life and hence the net present value of the liability increases. We report this increase in the liability as accretion expense.

Selling, General and Administrative Expenses

Our historical selling, general and administrative expenses, or SG&A expenses, include the costs of our sales and marketing group as
well as general and administrative expenses incurred in our corporate headquarters. Prior to our IPO, our SG&A expenses also included allocations of Rio Tinto headquarters costs and expenses incurred
by Rio Tinto affiliates. Rio Tinto America through its subsidiaries had provided various services and other general corporate support to our company, including tax, treasury, corporate secretary,
procurement, information systems and technology and

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innovation,
community and external relations, human resources, accounting services and insurance/risk management in the ordinary course of business. We were charged for those 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 percentage of operating expenditures,
head count and revenues. SG&A expenses for the years ended December 31, 2009, 2008 and 2007 include allocations of expenses incurred by Rio Tinto America and other Rio Tinto affiliates of
$15.8 million (incurred prior to our IPO), $21.0 million and $20.3 million, respectively.

Many
of the allocations of general and administrative expenses relate to services provided to us under a shared services agreement with an affiliate of Rio Tinto America, some of which
will continue for a transition period of approximately nine months after our IPO under a transition services agreement. In place of the allocations of Rio Tinto headquarters costs, we are incurring
additional recurring costs related to being a stand-alone public company, including costs for financial reporting, tax, regulatory compliance, corporate governance, treasury, legal, internal audit,
investor relations, business development and human resources activities.

We
are implementing plans to replace shared services from Rio Tinto America and develop the internal functions that we need to operate effectively and fulfill our responsibilities as a
stand-alone public company. Our plans reflect recurring activities that are incremental to our historical activities, as well as certain nonrecurring activities that are required to complete our
transition to a stand-alone public company.

We
have estimated the incremental recurring annual costs related to being a stand-alone public company to be approximately $39 million, of which we expect to report approximately
$28 million and $11 million in SG&A expenses and cost of product sold, respectively. The significant assumptions
involved in determining the estimates of incremental recurring costs primarily include the cost of additional or more experienced personnel and related benefits, investments in information technology,
outside professional services and increased insurance and bonding costs.

We
have estimated the nonrecurring costs that we will incur during our transition to being a stand-alone public company to be approximately $21 million. We anticipate that
substantially all of these costs will be incurred during the period from July 1, 2009 through the third quarter of 2010. Our historical consolidated statement of operations for the year ended
December 31, 2009 includes approximately $12.2 million of such costs. These costs primarily include one-time legal, accounting and tax consulting costs, bonuses and
acceleration of share-based compensation associated with our IPO, personnel recruiting fees and costs associated with the relocation of certain functions and personnel. Our estimate also includes the
costs we expect to incur under the transition services agreement with Rio Tinto.

Although
we believe our estimates of incremental recurring costs and nonrecurring transition costs are reasonable based on the information we have to date, certain significant components
of our estimates are preliminary and subject to change.

Also
included in SG&A expenses for the years ended December 31, 2009 and 2008 is $18.3 million and $25.8 million, respectively, of legal, accounting and other costs
incurred as a result of efforts by Rio Tinto America to divest our business through a trade sale or an initial public offering.

Interest Expense

Prior to our IPO, our historical interest expense consisted primarily of interest related to our historical credit facility with Rio
Tinto America ("RTA Facility") and interest imputed on our annual installment payments due under our LBAs. On September 24, 2008, $547.4 million of debt owed under the RTA Facility was
contributed to capital and we ceased to incur interest on the RTA Facility. In connection with our IPO, we issued a total of $600.0 million in senior notes, $300.0 million of which

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bears
interest at 8.25% and matures in 2017 and $300.0 million of which bears interest at 8.5% and matures in 2019. As a result, we will incur increased interest expense going forward. In
addition, also in connection with our IPO, we entered into $400.0 million revolving credit facility, which provides for revolving loans and letters of credit. Borrowings under the credit
facility generally bear interest at the greater of the LIBOR or 2.50%, plus an applicable margin of between 3.25% and 4.25%, depending on CPE Resources' credit rating. To the extent that we draw on
the revolving credit facility, we will incur additional interest expense.

Income Tax

The provision for income taxes is determined using the asset and liability method, under which deferred tax assets and liabilities are
calculated based upon the temporary differences between the financial statement and income tax basis of assets and liabilities using currently enacted rates. For the purposes of our historical
consolidated financial statements for periods prior to our IPO, which were prepared on a carve-out basis, our current and deferred income taxes were calculated on a stand-alone income tax
return basis. Historical changes in the amount of the depletion deductions, relative to respective changes in pre-tax income, have been the primary drivers of changes to our effective tax
rate. Percentage depletion on a mine-by-mine basis can vary from year to year based on net income from mining activities and other limitations. Future differences in our
pre-tax income and taxable income from mining activities are expected to cause changes to our effective tax rate as compared to our prior years. Because RTEA was part of Rio Tinto
America's entire consolidated federal tax group, the tax strategies used were not necessarily reflective of tax strategies we would have followed, or will follow, as a stand-alone public company. As a
result, our effective tax rate going forward as a stand-alone public company may differ significantly from those in historical periods.

Cloud
Peak Energy Inc. is now required to file a separate federal corporate income tax return and is subject to income taxes on its share of CPE Resources'
pre-tax income. CPE Resources and its non-corporate subsidiaries are not income tax paying entities; however, CPE Resources owns certain corporate subsidiaries that may pay
nominal amounts of corporate income tax or may incur losses which cannot benefit other entities included in the consolidated financial results. Pre-tax income as reported in our
consolidated financial statements includes all of CPE Resources' income and expenses, including amounts attributable to the noncontrolling interest in CPE Resources. See "Noncontrolling
Interest" below. Income tax expense, however, is not recognized in our consolidated financial statements for the portion of CPE Resources pre-tax income that is attributable to the
noncontrolling interest. As a result of these changes in our structure, our effective income tax rate (consolidated income tax expense as a percentage of consolidated pre-tax income)
generally is lower than the amounts that would have been reported under the prior structure. Our IPO structuring transactions also will affect the calculation and impact of certain tax deductions,
such as percentage depletion deductions in excess of cost basis for tax purposes, that are accounted for as permanent differences and affect our consolidated effective income tax rate.

As
a result of our IPO structuring transactions, our tax basis in our share of CPE Resources assets, primarily property, plant and equipment used in our mining operations, has increased.
These increases in tax basis will result in increases to depreciation, amortization and depletion deductions and therefore reduce the amount of tax that we would otherwise be required to pay in the
future. We have recognized an increase in our deferred income tax assets, net of a valuation allowance, to reflect the estimated tax benefits that we expect to realize in the future as a result of the
increase in tax basis. We also recognized a deferred income tax asset for the liability under the Tax Receivable Agreement.

Pursuant
to the Tax Receivable Agreement, we are required to pay to RTEA approximately 85% of cash savings in income taxes that we realize as a result of the increase in the tax basis of
our interest in CPE Resources assets, including tax benefits attributable to payments made under the Tax Receivable Agreement. See Item 1A "Risk FactorsRisks Related to Our
Corporate Structure and

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Our
IPO Structuring TransactionsWe are required to pay RTEA for most of the tax benefits we may claim as a result of the tax basis step-up we received in connection with our
IPO and related structuring transactions. In certain cases, payments to RTEA may be accelerated or exceed our actual cash tax savings. These provisions may deter a change in control of our company."
We have recognized a liability under the Tax Receivable Agreement reflecting our estimate of the undiscounted amounts that we expect to pay to RTEA under this agreement, which we refer to generally as
the tax agreement liability.

Periodically,
we adjust our deferred tax assets and tax agreement liability based on updated estimates of the tax benefits we expect to realize and pay to RTEA in the future. These
changes in estimates may result in material adjustments to our future results of operations. See "Critical Accounting Policies and EstimatesIncome Taxes and Tax Agreement
Liability" below.

Noncontrolling Interest

Prior to our IPO, CPE Resources and its subsidiaries were wholly owned by RTEA, our predecessor for financial reporting purposes.
Accordingly, RTEA consolidated CPE Resources and included 100% of the net income or losses of CPE Resources and its subsidiaries in its historical results of operations. As a result of the acquisition
of a controlling interest in CPE Resources in connection with the structuring transactions, Cloud Peak Energy Inc. consolidates 100% of CPE Resources and its subsidiaries, but recognizes a
noncontrolling interest in its consolidated financial statements for Rio Tinto's remaining interest in CPE Resources. This noncontrolling interest is deducted in determining the portion of CPE
Resources' net income that is attributable to the controlling interest. In addition, certain of our expenses, including substantially all of our provision for income taxes and adjustments to the tax
agreement liability, are incurred directly by Cloud Peak Energy Inc. and therefore are not allocated to the noncontrolling interest. Because these components of our consolidated operating
results are not allocable to the noncontrolling interest, the percentage of our consolidated net income or loss that is attributable to our controlling interest will not be equal to our percentage
interest in the common membership units of CPE Resources. See "Initial Public Offering and Related IPO Structuring Transactions" in Note 2 of Notes to Consolidated Financial Statements in
Item 8.

Balance Sheet Overview

As of December 31, 2009, our total assets were approximately $1.68 billion. Our primary asset is property, plant and
equipment, which includes our coal reserves acquisition costs, and represents 58.8% of our total assets as of December 31, 2009. Other significant asset categories include deferred tax assets,
accounts receivable and inventories, which include parts, supplies and coal inventories.

We
had total liabilities of approximately $1.23 billion as of December 31, 2009, $595.3 million of which represented our senior notes, net of original issue
discount. Our liabilities also include asset retirement obligations, which comprise expected costs associated with mine reclamation and closure activities, and obligations for future federal coal
lease installment payments, which are included in other long-term debt.

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Results of Operations

The following table presents our operating results for the years ended December 31, 2009, 2008 and 2007 (in millions):

Year Ended December 31,2009

2008

2007Revenues

$
1,398.2

$
1,239.7

$
1,053.2Costs and expensesCost of product sold


933.5


894.0


755.3Depreciation and depletion


97.9


89.0


80.1Amortization


28.7


46.0


34.5Accretion


12.6


12.7


12.2Selling, general and administrative expenses


69.8


70.5


50.0Asset impairment charges


0.7


2.6


18.3Total costs and expenses


1,143.2


1,114.8


950.4Operating income


255.0


124.9


102.8Other income (expense)Interest income


0.3


2.9


7.3Interest expense


(6.0
)

(20.4
)

(40.9
)Other, net





1.7


0.2Total other expense


(5.7
)

(15.8
)

(33.4
)Income from continuing operations before income tax provision and earnings (losses) from unconsolidated affiliates


249.3


109.1


69.4Income tax provision


(68.2
)

(25.3
)

(18.1
)Earnings from unconsolidated affiliates, net of tax


1.4


4.5


2.5Income from continuing operations


182.5


88.3


53.8Income (loss) from discontinued operations


211.1


(25.2
)

(21.5
)Net income


393.6


63.1


32.3Less: Income attributable to noncontrolling interest


11.9





Income attributable to controlling interest

$
381.7

$
63.1

$
32.3


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



Revenues were approximately $1.40 billion for the year ended December 31, 2009, compared to approximately
$1.24 billion for the year ended December 31, 2008, an increase of $158.5 million or 12.8%.

Revenues
from the sale of coal produced at the mines that we own and operate is the largest portion of our revenue, and totaled $1.08 billion in 2009, compared to
$978.3 million in 2008. This $98.9 million or 10.1% increase 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

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not
taking all of their contracted purchases of coal. Our share of revenues from coal produced at the Decker mine decreased by $8.4 million or 23.7% in 2009, reflecting a decline in shipments
partially offset by higher average price per ton.

The
balance of our revenues, which consist primarily of broker coal sales and billings for transportation and delivery services, totaled $294.0 million and $226.1 million
for the years ended December 31, 2009 and 2008, respectively. These amounts include revenues from our significant broker sales contract that expires in 2010 (see "Overview" above)
of $140.4 million and $135.1 million, respectively. 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. We
consider the export business to be opportunistic based on factors such as the U.S. and international economic conditions and freight costs, and do not expect exports to be a consistent part of our
business. Other revenues, which in 2008 included $6.3 million from a Decker contract settlement, decreased $5.1 million in 2009.



Cost of product sold, excluding depreciation, depletion, amortization and accretion, was $933.5 million for the year ended
December 31, 2009, compared to $894.0 million for the year ended December 31, 2008, a $39.5 million or 4.4% increase. Cost of product sold was 66.8% and 72.1% of revenues
for those same periods, respectively.

The
largest component of cost of product sold is the cost of coal produced at the three mines that we own and operate, which totaled $722.7 million in 2009, compared to
$730.0 million in 2008, a decrease of approximately 1.0%. This 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 expires in
2010 (see "Overview" above) and $22.2 million for other broker sales, consistent with the related increase in broker sales revenues in 2009.



Depreciation and depletion expense was $97.9 million for the year ended December 31, 2009, compared to
$89.0 million for the year ended December 31, 2008, an increase of $8.9 million, or 10.0%. The increase is primarily attributable to a $7.9 million increase in depletion of
reclamation costs as a result of an increase in estimated reclamation costs for a mined-out portion of the Decker mine while the 2008 amount reflected a favorable adjustment upon the
addition of new coal reserves at the Cordero Rojo mine. In addition, depreciation increased $2.3 million as a result of a higher capital base, following increased investment and capital
expenditures in recent years. These increases were partially

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offset
by a decrease in depletion of $1.6 million resulting from fewer tons produced in 2009 as compared to 2008, as depreciation and depletion are calculated predominantly on a
units-of-production basis.



Amortization expense was $28.7 million and $46.0 million for the years ended December 31, 2009 and 2008,
respectively. The $17.3 million or 37.6% decrease was primarily attributable to the buy out of a long-term contract at the Decker mine in the first quarter of 2008, which resulted
in accelerated amortization of the intangible asset associated with the contract in 2008. In addition, this intangible asset was fully impaired later in 2008 as a result of a change in the Decker mine
plan during the fourth quarter, resulting in no amortization of the intangible asset being recognized during 2009. Further contributing to the decrease was a reduction in amortization related to a
coal supply contract that will expire in 2010.



Accretion expense was $12.6 million and $12.7 million for the years ended December 31, 2009 and 2008,
respectively. The nominal change reflects the lack of significant overall changes in our asset retirement obligations and the related discount rates.



Selling, general and administrative expenses were $69.8 million for the year ended December 31, 2009 compared to
$70.5 million for the year ended December 31, 2008. The small overall change from the prior year reflects several offsetting changes in components of SG&A expenses. Our employee
compensation costs increased $6.1 million reflecting an increase in the number of employees in 2009, including new hires in connection with our transition to a stand-alone public company. This
increase was offset by a $7.8 million decrease in expenses associated with our divestiture efforts.



Asset impairment charges were $698,000 and $2.6 million for the years ended December 31, 2009 and 2008, respectively. In
2009, we recognized an impairment charge of $698,000 for costs incurred on an abandoned time-keeping software project. In 2008, we recognized impairments of $4.6 million for
remaining contract rights related to Decker that were determined not to be recoverable and $1.0 million for costs incurred on an abandoned production cost efficiency project. These charges were
offset by a $3.0 million reduction of an asset impairment charge recognized in 2008 related to an information system project that was impaired during 2007.



Prior to our IPO, interest income consisted of interest earned on short-term investments made through a Rio Tinto America
cash management program. Subsequent to our IPO, interest income consisted of interest earned on cash invested by our treasury department. Interest income decreased $2.6 million to
$0.3 million for the year ended December 31, 2009, from $2.9 million for the year ended December 31, 2008. While the average amount of invested funds increased, interest
income decreased due to a decrease in the average rate earned to 0.1% in 2009 from 3.1% in 2008.

Interest
expense declined to $6.0 million during the year ended December 31, 2009 from $20.4 million for the year ended December 31, 2008. The decrease
resulted primarily from 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

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transactions
entered into on November 25, 2009. See "Liquidity and Capital ResourcesSenior Unsecured Notes and Senior Secured Revolving Credit Facility" below.



Income tax expense increased to $68.2 million for the year ended December 31, 2009 from $25.3 million for the year
ended December 31, 2008 due to higher income before taxes. The effective income tax rate increased to 27.4% for the year ended December 31, 2009 from 23.2% for the year ended
December 31, 2008. 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 12 of
Notes to Consolidated Financial Statements in Item 8.



Income from discontinued operations, net of income tax, was $211.1 million for the year ended December 31, 2009 compared
to a loss of $25.2 million for the year ended December 31, 2008. The favorable change 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 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.



Income attributable to noncontrolling interest of $11.9 million for the year ended December 31, 2009 represents Rio
Tinto's interest in CPE Resources net income for the period from November 20, 2009 through December 31, 2009, as a result of our IPO structuring transactions.



As a result of the factors discussed above, income attributable to controlling interest for the year ended December 31, 2009 was
$381.7 million, compared to net income of $63.1 million for the year ended December 31, 2008.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007



Revenues were approximately $1.24 billion for the year ended December 31, 2008 compared to approximately
$1.05 billion for the year ended December 31, 2007, a $186.5 million or 17.7% increase.

Revenues
from the sale of coal produced at the mines we own and operate totaled $978.3 million in 2008, compared to $841.1 million in 2007. This $137.2 million or
16.3% increase in revenues reflects a 12.6% increase in the average price per ton of coal sold, from $9.27 in 2007 to $10.44 in 2008, and a 3.3% increase in shipments, from 90.7 million tons in
2007 to 93.7 million tons in 2008. The increase in both the price per ton sold and in tonnage reflected a strengthening market for PRB coal at the time we entered into our coal supply contracts
that provided for deliveries in 2008. Our share of revenues from coal produced at the Decker mine added to the increase in revenue by $1.5 million or 4.3%.

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The
balance of our revenues, which consist primarily of broker coal sales and billings for transportation and delivery services totaled $226.1 million in 2008, compared to
$178.1 million in 2007. These amounts include revenues from our significant broker sales contract of $135.1 million and $116.6 million for the years ended December 31, 2008
and 2007, respectively. Other coal sales decreased by $3.9 million reflecting a decrease in tons sold, partially offset by an increase in the average selling price per ton. Revenues from
transportation and delivery services increased $41.8 million and reflects a higher volume of coal sold on a delivered basis, where we arranged and paid for the freight.



Cost of product sold was $894.0 million for the year ended December 31, 2008 compared to $755.3 million for the
year ended December 31, 2007, a $138.7 million or 18.4% increase. Cost of product sold was 72.1% and 71.7% of revenues for those same periods, respectively.

The
cost of coal produced at the three mines that we own and operate totaled $730.0 million in 2008 compared to $631.9 million in 2007, an increase of approximately 15.5%.
This increase reflects the 3.3% increase in tons sold and an 11.8% increase in the average cost per ton of coal produced, from $6.97 in 2007 to $7.79 in 2008. The increase in average cost per ton
primarily reflects a 30.6% increase in fuel and lubricant costs attributable to higher diesel fuel costs in 2008 and a 10.3% increase in royalties and production taxes in line with our increased coal
sales revenue for the same period. We also experienced moderate cost per ton increases in other costs, including labor, explosives, repairs and supplies. Additionally, our 50% share of Decker mine
production costs increased 6.2% from $28.4 million in 2007 to $30.1 million in 2008.

Cost
of product sold also increased in 2008 due to a greater volume of sales on a delivered basis where we arranged transportation, resulting in a $30.1 million increase in
freight and handling costs. In addition, the cost of purchased coal increased $8.8 million, including increases in costs related to our significant broker sales contract, resulting in an 11.7%
increase in the average cost per ton for purchased coal on a relatively flat volume of tons purchased.



Depreciation and depletion increased by 11.1% to $89.0 million for the year ended December 31, 2008 from
$80.1 million for the year ended December 31, 2007. This increase was primarily attributable to increased production from more recently acquired, higher cost coal deposits, resulting in
a higher depletion and also due to a higher capital base following increased investment and capital expenditures in recent years resulting in higher depreciation. The increase also resulted from
additional tons produced during 2008 as compared to 2007, as depreciation and depletion are calculated predominantly on a units-of-production basis.



Amortization expense was $46.0 million and $34.5 million for the years ended December 31, 2008 and 2007,
respectively. The $11.5 million increase is primarily attributable to the buy out of a long-term contract at the Decker mine in the first quarter of 2008, which resulted in
accelerated amortization of the intangible asset associated with the contract.



Accretion expense was $12.7 million and $12.2 million for the years ended December 31, 2008 and 2007,
respectively. The $0.5 million increase was primarily attributable to revised estimates of the future costs of our closure obligations as a result of increases in estimated costs associated
with fulfilling these obligations.

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Selling, general and administrative expenses increased by $20.4 million, or 40.7%, to $70.5 million for the year ended
December 31, 2008 from $50.1 million for the year ended December 31, 2007. The increase was primarily attributable to $25.8 million of legal, accounting and other costs
incurred in the year ended December 31, 2008 associated with efforts by Rio Tinto America to divest RTEA through a trade sale or an initial public offering. This increase was partially offset
by a $2.8 million decrease in share-based compensation due to the decrease in value of certain cash-settled awards based on general market conditions during 2008.



Asset impairment charges were $2.6 million and $18.3 million for the years ended December 31, 2008 and 2007,
respectively. As a result of changes in the Decker mine plan in 2008, which resulted in lower projected cash flows, the carrying amount of $4.6 million for remaining contract rights was
determined not to be recoverable. In addition, we recognized an impairment charge of $1.0 million for costs incurred on an abandoned production cost efficiency project. These impairment charges
were offset by a $3.0 million reduction of the asset impairment charge recognized in 2008 related to an information system impaired during 2007 due to a favorable outcome as compared to our
prior estimates and resolution of contingencies during 2008. Asset impairment charges in 2007 related to the write-off of capitalized costs, relating to an abandoned implementation of a
company-wide integrated financial system.



Interest income, which consisted of interest earned on short-term investments made through a Rio Tinto America cash
management program, decreased to $2.9 million for the year ended December 31, 2008 from $7.3 million for the year ended December 31, 2007 as a result of a decrease of
$13.6 million in average invested funds and a 3.8% decrease in the average rate earned to 3.1% in 2008 from 6.9% in 2007. The average invested funds were $78.0 million and
$91.6 million for the years ended December 31, 2008 and 2007, respectively.

Interest
expense, the largest component of which was our variable rate debt with Rio Tinto America, declined to $20.4 million for the year ended December 31, 2008 from
$40.9 million during the year ended December 31, 2007. The decrease primarily resulted from a 2.4% decrease in the average interest rate
in 2008 compared to 2007 as well as the contribution of the $547.4 million balance of the debt with Rio Tinto America to equity on September 24, 2008.



Income tax expense increased to $25.3 million for the year ended December 31, 2008 from $18.0 million for the year
ended December 31, 2007 due to higher income before taxes. The effective income tax rate decreased to 23.2% for the year ended December 31, 2008 from 26.0% for the year ended
December 31, 2007. The domestic manufacturing deduction in 2008 was greater than the deduction in 2007. This difference is due to differences in taxable income which drives the amount of
deduction recognized. The increased deduction realized in 2008 results in a more significant decrease in the effective rate for 2008 compared to 2007.



Loss from discontinued operations was $25.2 million for the year ended December 31, 2008 compared to $21.5 million
for the year ended December 31, 2009. The decrease was primarily attributable to an increase of $19.5 million in net losses incurred at the Colowyo mine offset by an increase of
$13.0 million in net income from Jacobs Ranch mine and the absence in 2008 of

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$6.6 million
of costs incurred during 2007 to evaluate potential operation of the uranium mining venture. Non-conforming coal quality resulted in reduced revenues for the Colowyo
mine which was compounded by unplanned maintenance and higher cost reserves. Jacobs Ranch mine net income improved from higher coal prices and an increase in tons sold.



As a result of the factors discussed above, net income for the year ended December 31, 2008 was $63.1 million compared to
net income of $32.3 million for the year ended December 31, 2007.

Unaudited Pro Forma Statement of Operations

The unaudited pro forma condensed consolidated statement of operations presented below has been derived from our audited historical
consolidated financial statements for the year ended December 31, 2009. This unaudited pro forma condensed consolidated financial information should be read in conjunction with
"Results of Operations" above in this Item 7 and our consolidated financial statements in Item 8.

The
unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2009 reflects adjustments to our historical financial statements to present
our results as if the IPO and related structuring transactions occurred on January 1, 2009. These adjustments include an increase in interest expense related to our senior notes, an increase in
the noncontrolling interest's share of net income, and a related decrease in income taxes applicable to the controlling interest's share of net income.

The
pro forma adjustments are based on assumptions that we believe are reasonable. The unaudited pro forma condensed consolidated financial information is for illustrative and
informational purposes only and is not intended to represent or be indicative of what our results of operations or financial position would have been had the IPO occurred on January 1, 2009.
The unaudited pro forma condensed consolidated financial information should not be considered representative of our future results of operations or financial position.

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Unaudited Pro Forma Condensed Consolidated Statement of Operations  Year Ended December 31, 2009  (dollars in thousands, except per share amounts)

Historical

Adjustments

Pro FormaRevenues

$
1,398,200

$


$
1,398,200Cost and expensesCost of product sold (exclusive of depreciation, depletion, amortization and accretion, shown separately)


933,489



(a)

933,489Depreciation, depletion, amortization and accretion


139,175





139,175Selling, general and administrative expenses


69,835



(a)

69,835Asset impairment charges


698





698Total costs and expenses


1,143,197





1,143,197Operating income


255,003





255,003Interest and other income (expense), net


(5,663
)

(44,124)
(b)

(49,787
)Income from continuing operations before income tax provision and earnings from unconsolidated affiliates


249,340


(44,124
)

205,216Income tax provision


(68,249
)

39,145
(c)

(29,104
)Earnings from unconsolidated affiliates, net of tax


1,381


383
(c)

1,764Income from continuing operations


182,472


(4,596
)

177,876Income from discontinued operations, net of tax


211,078


57,158
(c)

268,236Net income


393,550


52,562


446,112Less: Net income attributable to noncontrolling interest


11,849


247,494
(d)

259,343Net income attributable to controlling interest

$
381,701

$
(194,932
)
$
186,769Amounts attributable to controlling interest common shareholders:Income from continuing operations

$
170,623




$
77,670Income from discontinued operations


211,078





109,092Net income

$
381,701




$
186,762Earnings per common share attributable to controlling interest(e):BasicIncome from continuing operations

$
3.01




$
2.54Income from discontinued operations


3.73





3.56Net income

$
6.74




$
6.10Weighted-average shares outstandingbasic


56,616,986





30,600,000DilutedIncome from continuing operations

$
2.97




$
2.36Income from discontinued operations


3.52





3.52Net income

$
6.49




$
5.88Weighted-average shares outstandingdiluted


60,000,000





60,000,000


---

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The following table presents the calculation of pro forma basic and diluted income from continuing operations per share (amounts in thousands, except per share
amounts):

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

$
77,670Add back income from continuing operations attributable to the noncontrolling interest, net of estimated income taxes


64,128Numerator for diluted income from continuing operations per share

$
141,798Income from discontinued operations attributable to controlling interest shareholders, numerator for basic earnings per share from discontinued
operations

$
109,086Add back income from discontinued operations attributable to the noncontrolling interest, net of estimated income taxes


101,851Numerator for diluted income from discontinued operations per share

$
210,937Denominator for basic earnings per shareweighted-average shares outstanding


30,600Weighted-average common shares from assumed exchange of CPE Resources common membership units held by noncontrolling interest


29,400Denominator for diluted earnings per share


60,000Basic earnings per share from continuing operations

$
2.54Basic earnings per share from discontinued operations


3.56Basic earnings per share

$
6.10Diluted earnings per share from continuing operations

$
2.36Diluted earnings per share from discontinued operations


3.52Diluted earnings per share

$
5.88


Liquidity and Capital Resources

Total unrestricted cash and cash equivalents as of December 31, 2009 and 2008, was $268.3 million and
$15.9 million, respectively. We also maintained $80.2 million in restricted cash accounts as of December 31, 2009. The increased balances as of December 31, 2009 reflects
our retention of a portion of the proceeds from our senior notes, which were issued on November 25, 2009 and from cash from operations for the period after our IPO. Pursuant to the terms of the
master separation agreement between Rio Tinto and us, we retained $178.8 million in cash and $80.2 million in restricted cash, and used the remaining proceeds to pay transaction costs
and make a cash distribution to RTEA. 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. As a result, our cash balance as of December 31, 2008 consisted primarily of amounts held by Decker.

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, electricity demand, regulatory
changes impacting our

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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."

If
cash from our operations is lower than expected we may need to draw on our revolving credit facility. The borrowing capacity under our revolving credit facility is reduced by the
amount of letters of credit issued. As a result of our IPO and related structuring transactions we are a stand-alone entity and can no longer rely on Rio Tinto to secure our reclamation obligations.
Consequently, we are required to obtain new surety bonds and to provide collateral to partially secure these arrangements. We expect that this collateral will be in the form of restricted cash
collateral and letters of credit, both of which will reduce our available liquidity. Our $80.2 million balance of restricted cash at December 31, 2009 was used to collateralize
transitional arrangements provided by Rio Tinto which will expire in
March 2010. The entire balance of these surety arrangements is expected to be transitioned to us during March 2010 and will be collateralized by $176.5 million in restricted cash and
$51.8 million in letters of credit. As of December 31, 2009, our borrowing capacity under the revolving credit facility is $348.2 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, 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. We have nominated tracts of land
through the LBA process that we believe contain, as applied for, approximately 800 million tons of non-reserve coal deposits, according to our estimates and subject to final
determination by the BLM of the final boundaries and tonnage for these tracts. 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.

In
addition, our planned capital expenditures, which we expect will be between $80.0 million and $90.0 million (excluding federal coal lease payments) in 2010, include our
estimates of expenditures necessary to develop new coal leases to maintain our reserve position, including the addition of sufficient fleets of heavy mining equipment needed to mine the coal. Our
operating and capital expenditure plans also include our estimates of the necessary expenditures to keep our current fleets updated to maintain our mining productivity and competitive position.

We
are required to make semi-annual interest payments on our senior notes commencing on June 15, 2010. We also expect to make on-going payments to RTEA
under the Tax Receivable Agreement, which will impact our liquidity. Any distributions from CPE Resources to Cloud Peak Energy Inc. to satisfy these payment obligations will require CPE
Resources to make pro-rata distributions to the Rio Tinto members of CPE Resources as well.

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.



Net cash provided by operating activities from continuing operations was $456.6 million for the year ended December 31,
2009 compared to $150.0 million for the year ended December 31, 2008. This $306.6 million 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

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$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. Net cash provided by operating activities from continuing operations was $150.0 million for the year ended December 31,
2008 compared to $290.1 million for the year ended December 31, 2007. Contributing to the $140.1 million decrease in cash provided by operating activities from continuing
operations was a $186.4 million change in amounts due to affiliates, offset, in part, by a $30.1 million improvement in the collection of receivables.

Net
cash used in investing activities from continuing operations was $417.1 million for the year ended December 31, 2009 compared to $153.7 million for the year
ended December 31, 2008. The $263.4 million 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. Net cash used in investing activities from continuing
operations increased to $153.7 million for the year ended December 31, 2008 from $90.6 million for the year ended December 31, 2007. The $63.1 million increase in
cash used in investing activities from continuing operations is the result of increased purchases of property, plant and equipment during 2008 as compared to 2007 and increases in the cash invested
with Rio Tinto America treasury, as part of the cash management program, partially offset by the receipt of a $24.4 million refundable deposit related to an unsuccessful coal reserve
acquisition bid, which was paid during 2007.

Net
cash used in financing activities from continuing operations was $582.2 million for the year ended December 31, 2009 compared to $2.9 million for the year ended
December 31, 2008. This 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 used in financing activities from continuing operations
decreased to $2.9 million for the year ended December 31, 2008 from $147.6 million for the year ended December 31, 2007. This reduction in cash used in financing activities
from continuing operations primarily related to net borrowings on the RTA facility of $30.0 million during 2008 compared to payments on the facility of $120.0 million during 2007.



Net cash provided by operating activities from discontinued operations was $36.0 million, $50.3 million and
$30.8 million for the years ended December 31, 2009, 2008 and 2007, 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. The increase in net cash provided by operating
activities from discontinued operations in 2008 from 2007 was primarily attributable to an increase in accounts payable and accrued expenses related to cash management strategies partially offset by a
2008 payment for a reclamation trust fund related to the uranium mining venture.

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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 and $72.9 million for the years ended December 31, 2008 and 2007, respectively. 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. The decrease in net cash used in investing activities from discontinued operations from
2007 to 2008 is due primarily to decreased purchases of property, plant and equipment at the Jacobs Ranch mine for specific expansion projects offset, in part, by the absence of the receipts of
restricted cash and refundable deposits received in 2007.

Net
cash used in financing activities from discontinued operations was $10.2 million and $5.7 million for the years ended December 31, 2008 and 2007, respectively.
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. The increase in net cash used in financing activities from discontinued operations in 2008 from 2007 is due to a change in restricted cash held for the payment of collateralized bonds related
to the Colowyo mine.



Effective 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, 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, approximately $309.7 million of the net proceeds were distributed to RTEA during the fourth quarter of 2009. The remaining net
proceeds from the senior notes offering are being used for general corporate purposes, including the payment of fees under our revolving credit facility, cash reserves for securing our reclamation
obligations and for capital expenditure requirements.

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%
non-operating 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.

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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 certain of our domestic restricted subsidiaries. The credit facility matures on December 16, 2013. As of December 31, 2009, there were no amounts drawn under
the credit facility and $51.8 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% (4.00% at
December 31, 2009). 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 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 may not be the same as
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 2.5 to 1 through December 31, 2010, and
2.75 to 1 thereafter; a ratio of funded debt to EBITDA equal to or less than 3.75 to 1 through December 31, 2010, and 3.5 to 1 thereafter; 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.



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 $197.0 million, with $63.8 million due in 2010 and 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

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inception
of the lease. The outstanding principal balance of our federal coal lease obligations was $169.1 million as of December 31, 2009.

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 anticipate completing the replacement of surety bonds and letters of credit provided by Rio Tinto on our behalf during March 2010. These surety bonds are collateralized by an
increased restricted cash balance of $176.5 million, which we funded in February 2010.

As
of December 31, 2009, we used surety bonds and letters of credit to secure outstanding obligations as follows (in millions):

Surety
Bonds

Letters of
Credit

TotalReclamation obligations(1)

$
307.7

$
200.2

$
507.9Collateral for Decker surety bonds(2)





41.3


41.3Lease obligations(3)


25.3





25.3Other obligations(4)





0.1


0.1$
333.0

$
241.6

$
574.6


(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)Represents
letters of credit issued under our revolving credit facility collateralizing Decker's surety bonds.(3)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.(4)Other
obligations include amounts required for exploration permits, water well construction and monitoring and other miscellaneous items as mandated by the
applicable governing agencies.


Our
outstanding surety bonds and letters of credit in respect of our reclamation obligations, which at December 31, 2009, were $549.2 million (including our obligations
with respect to the Decker mine),

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are
required by law. State statutes regulate and determine the calculation of the amounts of the bonds and letters of credit 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 our near-term reclamation liability that assumes reclamation
activities will be performed 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
bonding costs 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 permitting regulations prescribe the specific methodology to be used in our bonding calculations and provide that the bond amounts must assume
certain 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.

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 $181.4 million at December 31, 2009, $5.5 million of which is payable in 2010. 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. 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 16 of Notes to Consolidated Financial Statements in Item 8.

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Contractual Obligations

As of December 31, 2009, we had the following contractual obligations (in millions):

Total

2010

2011-2012

2013-2014

2015 and
ThereafterSenior notes(1)

$
600.0

$


$


$


$
600.0Other long-term debt(2)


178.4


55.3


112.5


10.6


Interest related to long-term debt(3)


484.6


66.4


115.1


101.3


201.8Operating lease obligations


8.6


0.7


1.0


0.8


6.1Coal purchase obligations(4)


4.6


4.6








Capital expenditure obligations(4)


2.3


2.3








Total

$
1,278.5

$
129.3

$
228.6

$
112.7

$
807.9


(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, 2009. See Note 9 of Notes to Consolidated Financial Statements in
Item 8.(2)Other
long-term debt includes our discounted payment obligations under federal coal leases, private coal leases and land purchase notes. See
Note 9 of Notes to Consolidated Financial Statements in Item 8.(3)As
of December 31, 2009, we had outstanding commitments for interest related to our senior notes and other long-term debt. See
Note 9 of Notes to Consolidated Financial Statements in Item 8.(4)As
of December 31, 2009, we had outstanding commitments for coal purchases and capital expenditures which are not included on consolidated balance
sheet. See Note 16 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 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. We believe that substantially all the payments required under our AROs as of December 31, 2009 will be made subsequent to December 31, 2012. Based on our assumptions, the carrying
amount of our AROs as determined in accordance with U.S. GAAP is $181.4 million as of December 31, 2009, $5.5 million of which is payable in 2010. See Note 10 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 pursuant to which the seller may require us to pay a
purchase price of $23.7 million between April 2013 and 2018.

This
table does not include payments that we expect to make under the Tax Receivable Agreement. We have recognized a $54.5 million liability for our estimated payments to RTEA
under the Tax Receivable Agreement, of which $758,000 and $53.8 is classified as current and noncurrent, respectively, as of December 31, 2009. 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, 2009, we expect to make payments of $758,000 in 2010 and payments averaging approximately $7.7 million during 2011 to 2014. Cloud
Peak Energy Inc. is obligated to make these payments and expects to obtain funding for these payments by causing CPE Resources to

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distribute
cash on a pro-rata basis to its owners, which as of December 31, 2009 include Cloud Peak Energy Inc. holding a 51.7% interest and Rio Tinto members holding a 48.3%
interest. Accordingly, based on these ownership percentages, our total cash payments related to the Tax Receivable Agreement, including pro-rata distributions from CPE Resources to the Rio
Tinto members, would be nearly double the amounts that Cloud Peak Energy Inc. is directly obligated to pay. The Rio Tinto members may reduce their ownership in CPE Resources in an exchange of
their common membership units in CPE Resources for shares of Cloud Peak Energy Inc. common stock.
Such a decrease in ownership would reduce subsequent pro-rata distributions, but may result in additional increases in the tax basis of Cloud Peak Energy Inc.'s investment in CPE
Resources and require Cloud Peak Energy Inc. to make increased payments under the Tax Receivable Agreement. 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 Cloud Peak Energy Inc. 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 and related IPO structuring transactions. In certain cases, payments to RTEA may be accelerated or exceed our actual cash tax savings. These provisions may deter a
change in control of our company."

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 which 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 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

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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 the credit-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 the current
credit-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 the credit-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.

Impairment of Long-Lived Assets

We evaluate the recorded amounts of our long-lived assets, other than goodwill, whenever events or circumstances indicate
that the carrying amount of a particular asset may not be recoverable. An impairment loss is required to be recognized when the undiscounted estimated cash flows attributable to an asset are less than
the carrying amount of the asset. Goodwill is evaluated annually for impairment during the fourth quarter of the year, or more frequently if circumstances indicate an impairment may have occurred.

When
an impairment condition exists, the asset is written down to its fair value, which may be determined using discounted cash flow techniques. Such techniques involve estimating both
the amount and timing of the cash flows and require judgment in determining the appropriate discount rate. Significant adverse changes to our business environment, interest rates and future cash flows
could lead to the recognition of impairment charges in future periods, and those charges could be material.

Federal Coal Leases

Upon the effective date of federal coal leases, pursuant to which payments are required to be paid in five 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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Share-Based Compensation

We measure the cost of employee share-based awards based on fair value. This cost generally is recognized over the time period that the
recipient of a share-based compensation award is required to provide service, typically the vesting period. We estimate the fair value of certain share-based payment awards as of the grant date using
a Black-Scholes option valuation model. Estimates are required to determine inputs to the valuation model, such as the expected volatility of the underlying share price over the expected term of the
option, the expected term of the option, and the risk-free interest rate. Changing any of the model inputs could significantly change the valuation of the share-based award at the
applicable measurement date. We are required to estimate the awards that we ultimately expect to vest and to adjust share-based compensation expense for the effects of estimated forfeitures of awards
over the expense recognition period. See Note 14 of Notes to Consolidated Financial Statements in Item 8.

Income Taxes and Tax Agreement Liability

We provide for deferred income taxes for temporary differences between the financial statement carrying amounts and tax bases of assets
and liabilities 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 deferred tax asset may be reduced by a
valuation allowance when we, after assessing the probability of projected future taxable income and evaluating alternative tax planning strategies, determine it is more likely than not that the future
tax benefit may not be realized. Our consolidated deferred tax assets as of December 31, 2009 were $100.8 million, net of a $22.5 million a 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, updated forecasts of taxable income
over the remaining lives of our mines, the availability of tax planning strategies and other factors.

Pursuant
to the Tax Receivable Agreement, we are required to pay to RTEA approximately 85% of cash savings in income taxes that we realize as a result of the increase in the tax basis of
our interest in CPE Resources assets that resulted from the IPO structuring transactions, including tax benefits attributable to payments made under the Tax Receivable Agreement. 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.

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Recent Accounting Pronouncements

In June 2009, the FASB updated certain provisions of Accounting Standards Codification Topic 810. These provisions require an
enterprise to perform an analysis to determine whether the enterprise's variable interest or interests give it a controlling financial interest in a variable interest entity and to require ongoing
reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. These provisions are effective for our fiscal year ended beginning January 1, 2010. We are
currently evaluating the impact that the new standards may have 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. As of December 31, 2009, substantially all of our
planned 2010 production had been sold. As a result, our 2010 commodity price risk is limited, assuming our customers take and pay for the coal volumes as set forth in our contracts. 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. We believe that price risks associated with diesel fuel and explosives are significant because of the
recent price fluctuations for these commodities. If we assume that we use the same quantities of these commodities in 2010 as we did in 2009 and further assume that the average costs of diesel fuel
and explosives increase by 30%, we would incur additional fuel and explosive costs of approximately $14.9 million and $13.1 million in 2010. 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, 2009. To the extent that we borrow under the revolving credit facility, we may be subject to increased sensitivity to interest rate movements as they relate to CPE Resources'
ability to repay its debt. Any future debt arrangements that we enter into may also require borrowings at 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, based on our audits and the report of other auditors, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in
equity and cash flows present fairly, in all material respects, the financial position of Cloud Peak Energy Inc. and its subsidiaries (the "Company") at December 31, 2009 and 2008, and
the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United
States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did
not audit the financial statements of Decker Coal Company, a 50% joint venture, to which the Company applies proportional consolidation, which statements reflect total assets of $95,591,270 and
$96,516,919 as of December 31, 2009 and 2008, respectively, and total revenues of $59,681,540, $83,508,061 and $76,232,415 for each of the three years in the period ended December 31,
2009 (of which the Company reflects its 50% proportionate share of the joint venture in the accompanying consolidated financial statements). Those statements were audited by other auditors whose
report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for the Decker Coal Company, is based solely on the report of the other
auditors. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We
believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

/s/
PricewaterhouseCoopers LLP
Denver, Colorado
March 16, 2010

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Report of Independent Registered Public Accounting Firm

The
Venturers
Decker Coal Company (A Joint Venture):

We
have audited the balance sheets of Decker Coal Company (A Joint Venture) (the Company) as of December 31, 2009 and 2008, and the related statements of earnings and
comprehensive income, joint venture deficit, and cash flows for each of the years in the three-year period ended December 31, 2009. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We
conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.

In
our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Decker Coal Company (A Joint Venture) as of
December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally
accepted accounting principles.

/s/
KPMG LLP

Omaha,
Nebraska
February 5, 2010

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES        CONSOLIDATED BALANCE SHEETS  (dollars in thousands, except share data)

December 31,2009

2008ASSETSCurrent assetsCash and cash equivalents

$
268,316

$
15,935Restricted cash


80,180


Accounts receivable, net


82,809


79,451Due from related parties


8,340


Inventories, net


64,199


55,523Deferred income taxes


280


33,602Other assets


7,321


9,751Current assets of discontinued operations





56,979Total current assets


511,445


251,241Property, plant and equipment, net


987,143


927,910Intangible assets, net


3,197


31,916Goodwill


35,634


35,634Deferred income taxes


100,520


Other assets


39,657


8,301Noncurrent assets of discontinued operations





530,189Total assets

$
1,677,596

$
1,785,191LIABILITIES AND EQUITYCurrent liabilitiesAccounts payable

$
57,304

$
55,503Royalties and production taxes


102,912


96,060Accrued expenses


47,763


42,401Due to related parties





12,763Current portion of tax agreement liability


758


Current portion of other long-term debt


55,282


71,860Current liabilities of discontinued operations





65,258Total current liabilities


264,019


343,845Tax agreement liability, net of current portion


53,751


Senior notes


595,321


Other long-term debt, net of current portion


123,085


137,666Asset retirement obligations, net of current portion


175,940


164,234Deferred income taxes





86,320Other liabilities


20,002


5,998Noncurrent liabilities of discontinued operations





61,962Total liabilities


1,232,118


800,025Commitments and contingencies (Note 16)EquityCommon stock ($0.01 par value; 200,000,000 shares authorized; 31,449,002 and 1 shares issued and outstanding at December 31, 2009 and 2008,
respectively)


314


Additional paid-in capital


251,083


Retained earnings (deficit)


8,459


(116
)Former parent's equity





989,790Accumulated other comprehensive loss


(6,951
)

(4,508
)Total Cloud Peak Energy Inc. shareholders' equity


252,905


985,166Noncontrolling interest


192,573


Total equity


445,478


985,166Total liabilities and equity

$
1,677,596

$
1,785,191


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 OPERATIONS  (dollars in thousands, except per share amounts)

Year Ended December 31,2009

2008

2007Revenues

$
1,398,200

$
1,239,711

$
1,053,168Costs and expensesCost of product sold (exclusive of depreciation, depletion, amortization and accretion, shown separately)


933,489


894,036


755,280Depreciation and depletion


97,869


88,972


80,133Amortization


28,719


45,989


34,512Accretion


12,587


12,742


12,212Selling, general and administrative expenses


69,835


70,485


50,003Asset impairment charges


698


2,551


18,297Total costs and expenses


1,143,197


1,114,775


950,437Operating income


255,003


124,936


102,731Other income (expense)Interest income


320


2,865


7,302Interest expense


(5,992
)

(20,376
)

(40,930
)Other, net


9


1,715


274Total other expense


(5,663
)

(15,796
)

(33,354
)Income from continuing operations before income tax provision and earnings from unconsolidated affiliates


249,340


109,140


69,377Income tax provision


(68,249
)

(25,318
)

(18,050
)Earnings from unconsolidated affiliates, net of tax


1,381


4,518


2,462Income from continuing operations


182,472


88,340


53,789Income (loss) from discontinued operations, net of tax


211,078


(25,215
)

(21,482
)Net income


393,550


63,125


32,307Less: Net income attributable to noncontrolling interest


11,849





Net income attributable to controlling interest

$
381,701

$
63,125

$
32,307Amounts attributable to controlling interest common shareholders:Income from continuing operations

$
170,623

$
88,340

$
53,789Income from discontinued operations


211,078


(25,215
)

(21,482
)Net income

$
381,701

$
63,125

$
32,307Earnings (loss) per common share attributable to controlling interest:BasicIncome from continuing operations

$
3.01

$
1.47

$
0.90Income from discontinued operations


3.73


(0.42
)

(0.36
)Net income

$
6.74

$
1.05

$
0.54Weighted-average shares outstandingbasic


56,616,986


60,000,000


60,000,000DilutedIncome from continuing operations

$
2.97

$
1.47

$
0.90Income from discontinued operations


3.52


(0.42
)

(0.36
)Net income

$
6.49

$
1.05

$
0.54Weighted-average shares outstandingdiluted


60,000,000


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 STATEMENTS OF EQUITY  (dollars in thousands)

Common
Stock

Additional
Paid-In
Capital

Retained
Earnings
(Deficit)

Accumulated
Other
Comprehensive
Income (Loss)

Former
Parent's
Equity

Non-
controlling
Interest

TotalBalances at December 31, 2006

$


$


$


$
(1,851
)
$
291,706

$


$
289,855Comprehensive incomeNet income














32,307





32,307Decker pension adjustments, net of tax











113








113Total comprehensive income




















32,420Stock compensation, net of tax














1,727





1,727Cumulative effect of adoption of change in accounting principle














(280
)




(280
)Dividend to former parent














(2,466
)




(2,466
)Costs incurred by affiliates














13,705





13,705Balances 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, net of tax














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, net of tax





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


306


433,449








(433,755
)




Proceeds in excess of carrying amounts





(38,694
)







38,694





Restricted stock issuance


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

$
314

$
251,083

$
8,459

$
(6,951
)
$


$
192,573

$
445,478


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 31,2009

2008

2007Cash flows from continuing operationsOperating activitiesIncome from continuing operations

$
182,472

$
88,340

$
53,789Adjustments to reconcile income to net cash provided by operating activities:Depreciation and depletion


97,869


88,972


80,133Amortization


28,719


45,989


34,512Accretion


12,587


12,742


12,212Asset impairment charges


698


2,551


18,297Earnings from unconsolidated affiliates


(1,381
)

(4,518
)

(2,462
)Distributions of income from equity investments


4,000


4,750


Deferred income taxes


13,595


(18,697
)

4,645Expenses paid by affiliates





31,216


13,705Stock compensation expense


1,919


727


644Interest expense converted to principal





16,755


33,816Other, net


750


1,336


(247
)Changes in operating assets and liabilities:Accounts receivable, net


(3,358
)

12,609


(17,519
)Inventories, net


(7,638
)

(5,707
)

(7,045
)Due to or from related parties


103,414


(129,252
)

57,162Other assets


(1,097
)

(4,377
)

681Accounts payable and accrued expenses


28,890


9,715


10,216Asset retirement obligations


(4,855
)

(3,151
)

(2,448
)Net cash provided by operating activities from continuing operations


456,584


150,000


290,091Investing activitiesPurchases of property, plant and equipment


(119,742
)

(138,104
)

(91,499
)Payment on refundable deposit





(11,806
)

(24,397
)Return of refundable deposit





33,156


Restricted cash deposit


(80,180
)




Change in cash advances to affiliate


(217,468
)

(35,025
)

22,850Other, net


313


(1,880
)

2,469Net cash used in investing activities from continuing operations


(417,077
)

(153,659
)

(90,577
)Financing activitiesBorrowings on long-term debt


595,284


40,000


Repayments on other long-term debt


(68,583
)

(39,415
)

(145,175
)Payment of debt issuance costs


(26,585
)




Proceeds from issuance of common stock


433,755





Distributions to Rio Tinto America


(1,516,058
)

(3,448
)

(2,465
)Net cash used in financing activities from continuing operations


(582,187
)

(2,863
)

(147,640
)Net cash provided by (used in) continuing operations


(542,680
)

(6,522
)

51,874Cash flows from discontinued operationsNet cash from operating activities


36,029


50,320


30,795Net cash from investing activities


759,032


(41,231
)

(72,923
)Net cash from financing activities





(10,248
)

(5,715
)Net cash provided by (used in) discontinued operations


795,061


(1,159
)

(47,843
)Net increase (decrease) in cash and cash equivalents


252,381


(7,681
)

4,031Cash and cash equivalents at beginning of year


15,935


23,616


19,585Cash and cash equivalents at end of year

$
268,316

$
15,935

$
23,616


See Note 20 for supplemental cash flow information.

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

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. At
December 31, 2009, CPE Inc. held a 51.7% controlling interest in CPE Resources, and RTEA and an affiliate held the remaining 48.3% noncontrolling 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, 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.

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.

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Basis of Presentation (Continued)

("U.S. GAAP").
All intercompany balances and transactions have been eliminated in the consolidated financial statements.

Initial Public Offering and Related IPO Structuring Transactions

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 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 provides for CPE Inc., as managing member, to control the
activities of CPE Resources. RTEA and its affiliate retained certain protective rights to approve certain activities that are not in the ordinary course of business, but these rights do not preclude
CPE Inc.'s ability 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. The following transactions resulted in a $3.8 million net charge to former parent's equity:



CPE Inc.'s
use of the net IPO proceeds to repay a promissory note that was issued on November 19, 2009 to acquire a 51.0% interest in CPE Resources resulted in an increase
in the income tax basis of such interest. 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,

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Basis of Presentation (Continued)

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 16. CPE Inc. recognized a
$54.5 million liability for the amounts it expects to pay RTEA under this agreement. The increase in tax basis and 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 was credited to several components of accumulated other comprehensive income, and the remainder of $46.4 million, which was
credited to additional paid-in capital.

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.

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 is 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 is 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.

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 be the primary beneficiary of the VIE. The primary

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beneficiary
generally is the entity that will receive a majority of the VIE's expected losses, receive a majority of the VIE's expected residual returns or both.

Prior
to our IPO, RTEA was the primary beneficiary of CPESC, which was a 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 now consolidate CPESC based on voting control.

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.

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, $25.4 million and $24.4 million for the years ended December 31, 2009, 2008 and 2007, respectively. Of these amounts, $15.8 million,
$21.0 million and $20.3 million for the years ended December 31, 2009, 2008 and 2007, respectively, are included in selling, general and administrative expenses. The remaining
$4.9 million, $4.4 million and $4.2 million, for the years ended December 31, 2009, 2008 and 2007, 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.

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Reclassifications

Certain amounts in the 2008 and 2007 consolidated financial statements have been reclassified to conform to the 2009 presentation.

3. Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements 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, and the recognition and measurement of income tax benefits and related deferred tax asset valuation allowances. Actual results could differ materially from those estimates.

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 the receivable. Based on our
assessment of the above criteria, there was no allowance for doubtful accounts at December 31, 2009 and 2008.

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Inventories, Net

Materials and Supplies

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.

Stockpiles and Finished Product ("Coal Inventory")

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

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


Capitalization of Interest

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

Mine Development Costs

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 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

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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.

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 a credit-adjusted, risk-free interest 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 credit-adjusted, risk-free interest 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.

Coal Reserves and Mineral Rights

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

Repairs and Maintenance

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.

Exploration Costs

We expense as incurred all costs incurred directly in identifying new resources and in converting existing resources to reserves at
development and production stage projects. Exploration costs of

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$1.2 million,
$1.4 million and $816,000 for the years ended December 31, 2009, 2008 and 2007, respectively, are included in cost of product sold.

Impairment

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. The remaining weighted-average
amortization period at December 31, 2009 is less than one year. 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.

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 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

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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 this plan in accordance with U.S. GAAP requirements for postretirement benefits other than pension 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

Litigation

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 assess the potential liability and
revise our estimates.

Workers' Compensation

For our employees in Wyoming, workers' compensation insurance is provided through a state fund program. We contribute to this program
through our payroll function by applying the assessed state rate to gross payroll, 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 self-insured workers' compensation program. Our insurance coverage generally
provides that we assume a portion of the risk in the form of a deductible. We accrue the estimated cost of our self-insurance retentions for workers' compensation based on historical data,
adjusted for actual claim settlements and reported claims.

Share-Based Compensation

We measure compensation 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

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IPO,
the awards granted by Rio Tinto became vested in accordance with the employee separation provisions contained in the original terms of the awards.

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 years ended December 31, 2008 and 2007, income taxes recognized in the carve-out consolidated financial
statements exceeded income taxes pursuant to the tax sharing agreement by $29.6 million and $509,000, respectively. These amounts are presented as capital contributions within former parent's
equity, as the amounts will not be paid by us.

Tax Agreement Liability

In connection with our IPO structuring transactions (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, or more frequently when there are significant changes in circumstances, such as
the acquisition of additional coal reserves. Changes in our estimated tax agreement liability are recognized in other expense in our consolidated statement of operations. There were no changes in the
tax agreement liability during the period from November 19, 2009 (Tax Receivable Agreement execution date) to December 31, 2009.

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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 at
destination.

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 recognized as gross amounts in revenues.

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coal production. We produce low sulfur, steam coal
from surface mines located in the Powder River Basin in Wyoming and Montana that we sell to electric utilities and industrial customers. We have determined that we have one operating segment,
primarily based on our chief operating decision maker assessing our performance and allocating resources based on our consolidated financial information.

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

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potential
dilutive common shares related to CPE Resources common membership units that are convertible to CPE Inc. common shares.

Recent Accounting Pronouncements

In June 2009, the FASB updated certain provisions of Accounting Standards Codification Topic 810. These provisions require an
enterprise to perform an analysis to determine whether the enterprise's variable interest or interests give it a controlling financial interest in a VIE and require ongoing reassessments of whether an
enterprise is the primary beneficiary of a VIE. These provisions are effective for our fiscal year beginning January 1, 2010. We are currently evaluating the impact that the new standards may
have on our consolidated financial statements.

4. Discontinued Operations

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, $17.7 million and $12.1 million for the years ended December 31, 2009, 2008 and 2007, 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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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

2008

2007Jacobs Ranch MineRevenues

$
368,640

$
478,039

$
378,695Costs and expenses


304,030


482,863


405,544Income (loss) from discontinued operations, before gain on sale and income taxes


64,610


(4,824
)

(26,849
)Gain on sale


264,767





Income tax (expense) benefit


(118,299
)

685


9,688Income (loss) from discontinued operations, net of taxes

$
211,078

$
(4,139
)
$
(17,161
)Colowyo and Uranium Mining VentureRevenues

$


$
90,678

$
138,919Costs and expenses





124,336


149,418Loss from discontinued operations, before income taxes





(33,658
)

(10,499
)Income tax benefit





12,582


6,178Loss from discontinued operations, net of taxes

$


$
(21,076
)
$
(4,321
)Total Discontinued OperationsRevenues

$
368,640

$
568,717

$
517,614Costs and expenses


304,030


607,199


554,962Income (loss) from discontinued operations, before gain on sale and income taxes


64,610


(38,482
)

(37,348
)Gain on sale


264,767





Income tax (expense) benefit


(118,299
)

13,267


15,866Income (loss) from discontinued operations, net of taxes

$
211,078

$
(25,215
)
$
(21,482
)


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The
table below summarizes the assets and liabilities of the Jacobs Ranch mine classified as discontinued operations in the consolidated balance sheet as of December 31, 2008 (in
thousands):

AssetsCurrent assetsAccounts receivable, net

$
23,894Inventories, net


17,851Other


15,234Current assets of discontinued operations


56,979Property, plant and equipment, net


525,281Other


4,908Noncurrent assets of discontinued operations


530,189Total assets of discontinued operations

$
587,168LiabilitiesCurrent liabilitiesTrade accounts payable

$
21,370Accrued and other liabilities


43,888Current liabilities of discontinued operations


65,258Asset retirement obligations


40,747Deferred income taxes


21,215Noncurrent liabilities of discontinued operations


61,962Total liabilities of discontinued operations

$
127,220


5. Inventories

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

2009

2008Materials and supplies, net

$
60,868

$
53,680Coal stockpiles and finished product


3,331


1,843$
64,199

$
55,523


Materials
and supplies are stated net of an obsolescence allowance of $1.3 million and $1.2 million as of December 31, 2009 and 2008, respectively. The Company
recognized a provision to increase the allowance by $973,000, $356,000 and $656,000, and charged inventory costs to the allowance of $897,000, $325,000 and $189,000, for the years ended
December 31, 2009, 2008 and 2007, respectively.

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6. Property, Plant and Equipment

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

2009

2008Land, improvements and mineral rights

$
862,890

$
763,862Mining equipment


701,084


636,350Construction in progress


13,413


41,916Other equipment


99,949


97,280Buildings and improvements


69,124


52,8801,746,460


1,592,288Less: accumulated depreciation and depletion


(759,317
)

(664,378
)$
987,143

$
927,910


At
December 31, 2009 and 2008, the carrying amount of coal reserves, included in land, improvements and mineral rights above, totaled $478.2 million and
$429.0 million, respectively. These amounts included mineral rights of $295.5 million and $253.9 million at December 31, 2009 and 2008, 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 $15.5 million, $6.6 million and $1.8 million for the years ended December 31,
2009, 2008 and 2007, respectively.

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.

In
2007, upon the announcement that Rio Tinto was exploring options to sell the Company, we abandoned our involvement in Rio Tinto's aligning business systems project, which included
implementation of an information technology software and hardware system. An asset impairment charge for costs incurred on the project totaling $18.3 million, including estimated accruals for
certain unbilled and contingent costs, was recognized in the year ended December 31, 2007. 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.

7. Intangible Assets

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

2009

2008Acquired long-term coal supply contracts

$
349,358

$
349,358Less: accumulated amortization


(346,161
)

(317,442
)$
3,197

$
31,916


At
December 31, 2009 and 2008, acquired long-term coal supply contracts consisted of a contract acquired in 1993 that expires in 2010. We expect the
$3.2 million unamortized balance of the contract to be amortized in 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Intangible Assets (Continued)

In
March 2008, a Decker contract, in which we had a 50% interest, 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 $4.5 million and $6.4 million at December 31, 2009 and 2008, respectively.
Investments at December 31, 2009 and 2008 consist of our 50% equity investment in Venture Fuels Partnership, a coal marketing company. During the year ended December 31, 2007, we also
held a 26.5% equity interest in NeuCo Inc. and insignificant investments in two other entities. In October 2008, we disposed of our investment in NeuCo Inc. and recognized a $199,000
loss on disposal, net of tax, which is included in earnings (losses) from unconsolidated affiliates.

The
following is condensed financial information for these equity method investments as of and for the years ended December 31 (in thousands):

2009

2008

2007Revenues

$
83,993

$
89,060

$
66,105Net income


4,335


16,530


6,363Total current assets


9,305


12,937


22,289Total noncurrent assets








7,880Total current liabilities


211


179


12,689Total noncurrent liabilities








746


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Long-Term Debt

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

2009

20088.25% Senior Notes due 2017, net of $2,176 unamortized discount

$
297,824

$
8.50% Senior Notes due 2019, net of $2,503 unamortized discount


297,497


Total senior notes

$
595,321

$
Federal coal leases

$
169,058

$
206,250Other


9,309


3,276Total other long-term debt


178,367


209,526Less: current portion of other long-term debt


(55,282
)

(71,860
)Other long-term debt

$
123,085

$
137,666


Senior Notes

Effective 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, 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.

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 $14.1 million were included in noncurrent other assets at
December 31, 2009.

The
Senior Notes are required to be 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Long-Term Debt (Continued)

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.

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, 2009, letters of credit totaling
$51.8 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 16.

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 $15.5 million were included in noncurrent other assets at December 31, 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, 2009). 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 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
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 2.5 to 1 through
December 31, 2010, and 2.75 to 1 thereafter; a ratio of funded debt to EBITDA equal to or less than 3.75 to 1 through December 31, 2010, and 3.5 to 1 thereafter; 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Long-Term Debt (Continued)

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, 2009, we were in compliance with the covenants contained in our Credit Facility.

Other Long-Term Debt

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 31Payment Dates

Annual
Payment

Imputed
Interest
Rate

2009

2008March 1, 2005 - 2009

$
29,262


5.5
%
$


$
27,751December 1, 2007 - 2011


3,980


6.8
%

7,220


10,490August 1, 2008 - 2012


50,160


7.5
%

130,447


168,009May 1, 2009 - 2013


9,620


8.7
%

31,391


$
169,058

$
206,250


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, 2009, 2008 and 2007 was $14.2 million, $7.9 million and $3.7 million, respectively, of which,
$14.1 million, $5.8 million and none, respectively, was capitalized as we prepared to mine the related coal deposits.

Other

Other long-term debt consists of obligations incurred in connection with the acquisitions of land and mineral rights. At
December 31, 2009 and 2008, other long-term debt includes obligations of $3.3 million and $3.2 million, respectively, which bear interest at rates ranging from 6% to
8% and are due upon demand by the respective holder. As a result, the amounts outstanding at December 31, 2009 and 2008 are included in current portion of other long-term debt on
the consolidated balance sheets. At December 31, 2009, other long-term debt also includes $6.0 million representing the present value at an imputed interest rate of 6.2% of
payments due in 2010 through 2013 under contracts for the purchase of mineral rights.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Long-Term Debt (Continued)

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 and
$37.4 million for the years ended December 31, 2008 and 2007, respectively. 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.

Future Maturities

Aggregate future maturities of long-term debt as of December 31, 2009 are as follows (in thousands):

2010

$
55,2822011


56,1342012


56,4032013


10,5482014 and thereafter


600,000778,367Less discount on senior notes


4,679Total long term debt

$
773,688


Interest
expense under financing arrangements, net of amounts capitalized, totaled $6.0 million, $20.4 million and $40.9 million for the years ended
December 31, 2009, 2008 and 2007, respectively.

The
approximate fair values of our Senior Notes and federal coal leasing obligations were $603.8 million and $179.7 million, respectively, at December 31, 2009. The
fair value of the Senior Notes is based on market quoted prices as of December 31, 2009. 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. The fair value of other long-term debt
approximates its carrying amount at December 31, 2009.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. Asset Retirement Obligations

Changes in the carrying amount of the Company's asset retirement obligations were as follows for the years ended December 31 (in thousands):

2009

2008Balance at January 1

$
167,272

$
162,105Accretion expense


12,587


12,742Revisions to estimated cash flows


6,415


(4,424
)Payments


(4,855
)

(3,151
)Balance at December 31


181,419


167,272Less current portion


5,479


3,038Asset retirement obligation, net of current portion

$
175,940

$
164,234


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, 2009 and 2008. 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 and was recognized as a reduction of depreciation and depletion expense for the year
ended December 31, 2008. This change in estimated cash flows resulted in a $3.0 million increase in income from continuing operations and net income for the year ended
December 31, 2008.

11. 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):

2009

2008

2007Cloud Peak Energy plans:Defined contribution retirement plans

$
757

$


$
Retiree medical plan


359





1,116





Rio Tinto America plans:Defined contribution retirement plans


6,414


6,384


3,999Defined benefit pension plan


2,608


2,943


4,218Retiree medical plan


1,373


1,505


2,04110,395


10,832


10,258Decker pension plan


892


44


67Total

$
12,403

$
10,876

$
10,325


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Employee Benefit Plans (Continued)

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 do not include Decker employees, and we implemented the plan (the "Retiree Medical Plan") effective January 1, 2010. 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.

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 13). 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. We expect to recognize $1.3 million over the next twelve months. 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. We used the following assumptions in the measurement of the APBO at November 19 and December 31, 2009:

December 31,
2009

November 19,
2009Discount rate


6.04%


5.82%Health care cost trend rate assumed for next year


9.00%


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 as of December 31, 2009. Assumed health care cost trend rates have a
significant effect

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Employee Benefit Plans (Continued)

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
$54,000 and $2.1 million, respectively, and a one-percentage-point decrease in the rate would decrease net periodic postretirement benefit cost and the APBO by $45,000 and
$1.8 million, respectively, as of December 31, 2009.

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):

2010

$
202011


552012


1092013


1822014


2772015 - 2019


4,371


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.

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 $2.5 million and
$3.8 million at December 31, 2009 and 2008, 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. 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 and Related IPO Structuring Transactions" 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 to date has consisted solely of its share (approximately 51.7% as of
December 31, 2009) of CPE Resources pre-tax 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.

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

2009

2008

2007Current:Federal

$
52,309

$
44,154

$
9,266State


1,495


1,262


265Total current


53,804


45,416


9,531Deferred:Federal


14,044


(19,540
)

8,283State


401


(558
)

236Total deferred


14,445


(20,098
)

8,519Total income tax provision

$
68,249

$
25,318

$
18,050


134

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. 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):

2009

2008Deferred income tax assets:Accrued expenses and liabilities

$


$
27,597Pension and other postretirement benefits





18,183Investment in joint venture partnerships





4,219Accrued reclamation and mine closure costs





38,363Investment in CPE Resources


103,639


Tax agreement liability


19,623


Total deferred income tax assets


123,262


88,362Less valuation allowance


(22,462
)

Net deferred income tax asset


100,800


88,362Deferred income tax liabilities:Inventories





(8,259
)Property, plant and equipment





(120,537
)Contract rights





(11,463
)Other





(821
)Total deferred income tax liabilities





(141,080
)Net deferred income tax assets (liabilities)

$
100,800

$
(52,718
)


Deferred
income taxes as of December 31, 2008 consisted of amounts recognized by RTEA based on the tax bases of assets and liabilities reported in the consolidated income tax
return for RTEA's consolidated federal tax group. As a result of CPE Inc.'s acquisition of a controlling interest in CPE Resources, RTEA's deferred tax assets and liabilities were eliminated
from our consolidated balance sheet as of November 19, 2009. Deferred income taxes as of December 31, 2009 consisted of amounts recognized by CPE Inc. based on the tax bases of
assets and liabilities to be reported in CPE Inc.'s income tax return. CPE Inc.'s principal deferred tax asset relates to its investment in CPE Resources, which reflects an increase in
tax basis in connection with our IPO structuring transactions. 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.

Deferred
income taxes related to continuing operations are classified in the consolidated balance sheets at December 31 as follows (in thousands):

2009

2008Current deferred income tax assets

$
280

$
33,602Noncurrent deferred income tax assets


100,520


Noncurrent deferred income tax liabilities





(86,320
)Net deferred income tax assets (liabilities)

$
100,800

$
(52,718
)


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Income Taxes (Continued)

The
future realization of deferred income tax assets that resulted from the increased tax basis of our investment in CPE Resources 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 $100.8 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 $22.5 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:

2009

2008

2007United States federal statutory income tax rate


35.0
%

35.0
%

35.0
%State income taxes, net of federal tax benefit


0.8


0.6


0.7Depletion


(5.6
)

(9.8
)

(10.1
)Section 468 imputed interest





0.5


0.7Section 199 domestic manufacturing deduction


(1.6
)

(3.3
)

(1.2
)Noncontrolling interest


(1.5
)




Other


0.3


0.2


0.9Effective tax rate


27.4
%

23.2
%

26.0
%


The
effective tax rate for 2009 reflects a reduction related to the noncontrolling interest in the pre-tax income of CPE Resources for the post-IPO period, for
which no income taxes were recognized in the consolidated statement of operations.

As
of December 31, 2008, RTEA had approximately $2.3 million of total gross unrecognized tax benefits and $358,000 of accrued interest recorded as noncurrent other
liabilities. These RTEA liabilities were eliminated from our consolidated balance sheet as a result of our IPO transaction. CPE Inc. does not expect to take any positions on its tax returns or
have any tax exposures that would require it to recognize liabilities for unrecognized tax benefits. A reconciliation of the beginning and ending amounts of gross unrecognized tax benefits for the
year ended December 31, 2009 is as follows (in thousands):

Gross unrecognized tax benefits at January 1, 2009

$
2,277Additions for tax positions of previous years


301Elimination of RTEA unrecognized tax benefits


(2,578
)Gross unrecognized tax benefits at December 31, 2009

$



13. 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 and Related
Structuring Transactions" 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Equity and Comprehensive Income (Continued)

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 14). These restricted stock grants increased the total common
membership units issued and outstanding to 60,849,002 at December 31, 2009 of which 31,449,002 were owned by CPE Inc., causing our ownership in CPE Resources to increase to approximately
51.7%.

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.

Comprehensive
income includes net income and other comprehensive income arising from activity related to our defined benefit employee benefit plans (see Note 11). 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
)




(397
)Retiree 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


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13. Equity and Comprehensive Income (Continued)

The
following table summarizes the noncontrolling interest share of CPE Resources' net income for the period from November 19, 2009, the effective date of our IPO, to
December 31, 2009 (in thousands):

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

$
24,559Earnings (losses) from unconsolidated affiliates before income taxes


(35
)Income from continuing operations before income tax provision


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

$
11,849


RTEA
and its affiliate have 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. has 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.

14. 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 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 in our consolidated statements of operations was as follows for the years ended December 31 (in thousands):

2009

2008

2007Rio Tinto sponsored plans

$
2,288

$
(55
)
$
2,729Cloud Peak Energy sponsored plan


785





Total share-based compensation expense

$
3,073

$
(55
)
$
2,729


As
of December 31, 2009, the total unrecognized compensation cost related to nonvested awards was $19.6 million, which is expected to be recognized over 2.9 years.

Rio Tinto Plans

Prior to our IPO, certain of our employees participated in Rio Tinto share-based compensation plans, as
follows:



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14. Share-Based Compensation (Continued)



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 and Related IPO Structuring Transactions" in Note 2.

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).

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14. Share-Based Compensation (Continued)

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


15.00


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. There is no intrinsic value for the outstanding options as of December 31, 2009, and no options vested during the
year then ended.

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








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. 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. 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.

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14. Share-Based Compensation (Continued)

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

Weighted average fair value (per option)

$8.85Assumptions:Risk-free interest rate

2.9%Expected option life

6.5 yearsExpected volatility

59%Dividend yield

0%


15. 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.

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

2009

2008

2007Amounts attributable to controlling interest common shareholders:Income from continuing operations

$
170,623

$
88,340

$
53,789Income (loss) from discontinued operations


211,078


(25,215
)

(21,482
)Net income

$
381,701

$
63,125

$
32,307Earnings per share from continuing operations

$
3.01

$
1.47

$
0.90Earnings per share from discontinued operations


3.73


(0.42
)

(0.36
)Basic earnings per share

$
6.74

$
1.05

$
0.54Weighted-average shares outstanding


56,617


60,000


60,000


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15. Earnings Per Share (Continued)

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 14) and common shares that may be issued in exchange for CPE Resources common membership units held by Rio Tinto members (see Note 13). 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 assume 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 increase the numerator to include CPE Resources income attributable to the noncontrolling interest and decrease 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%.

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

2009

2008

2007Numerator for calculation of diluted earnings per share:Income from continuing operations attributable to controlling interest shareholders

$
170,623

$
88,340

$
53,789Add 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


178,206


88,340


53,789Income (loss) from discontinued operations


211,078


(25,215
)

(21,482
)Numerator for diluted net income per share

$
389,284

$
63,125

$
32,307Denominator for basic income per shareweighted-average shares outstanding


56,617


60,000


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


60,000


60,000


60,000Diluted earnings per share from continuing operations

$
2.97

$
1.47

$
0.90Diluted earnings (loss) per share from discontinued operations


3.52


(0.42
)

(0.36
)Diluted earnings per share

$
6.49

$
1.05

$
0.54


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.

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16. Commitments and Contingencies

Commitments

Operating Leases

We occupy various facilities and lease certain equipment under various lease agreements. The minimum rental commitments under
non-cancelable operating leases, with lease terms in excess of one year subsequent to December 31, 2009, are as follows (in thousands):

2010

$
7392011


5042012


4892013


4442014


369Thereafter


6,056$
8,601


Rental
expense for the years ended December 31, 2009, 2008 and 2007, was $2.2 million, $1.4 million and $2.0 million, respectively.

Purchase Commitments

As of December 31, 2009, we had outstanding capital purchase commitments of $2.3 million and coal purchase commitments of
$4.6 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 2010.

In
April 2008, we entered into an agreement to purchase land whereby the seller may require us to pay a purchase price of $23.7 million between April 2013 and April 2018.

Tax Receivable Agreement

We have recognized a $54.5 million liability for our estimated payments to RTEA under the Tax Receivable Agreement, of which
$758,000 and $53.8 million is classified as current and noncurrent, respectively, as of December 31, 2009. See "Tax Agreement Liability" in Note 3. 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, 2009, we expect to make payments of $758,000 in 2010 and payments averaging approximately $7.7 million during
2011 to 2014. CPE Inc. is obligated to make these payments and expects to obtain funding for these payments by causing CPE Resources to distribute cash on a pro-rata basis to its
owners, which currently include CPE Inc. holding a 51.7% interest and Rio Tinto members holding a 48.3% interest. Accordingly, based on current ownership percentages, our total cash payments
related to the Tax Receivable Agreement, including pro-rata distributions from CPE Resources to the Rio Tinto members, would be nearly double the amounts that CPE Inc. is directly
obligated to pay. The Rio Tinto members may reduce their ownership in CPE Resources in an exchange of their common membership units in CPE Resources for

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16. Commitments and Contingencies (Continued)

shares
of CPE Inc. common stock (see Note 13). Such a decrease in ownership would reduce subsequent pro-rata distributions, but may result in additional increases in the tax
basis of CPE Inc.'s investment in CPE Resources and require CPE Inc. to make increased payments under the Tax Receivable Agreement. 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 does not believe those prices represent the results of arm's length negotiation. MMS based this conclusion on the facts that those entities were both
affiliates of KCP, Inc., formerly known as Kiewit Coal Properties, Inc., which is also a 50% owner of Decker, and that the sales were contingent on Big Horn's and Black Butte's ability
to resell the coal to Commonwealth Edison, which did not leave Big Horn and Black Butte at market risk. Instead, the MMS assessed Decker's royalties based on the higher prices set under Big Horn's and
Black Butte's separate long-term contracts with Commonwealth Edison.

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

With
respect to the period 1993-2001, the MMS has not issued a final decision concerning Decker's challenge to the assessment. On January 5, 2009, the Interior Board
of Land Appeals, or IBLA, issued a decision affirming the MMS's decision requiring Decker to pay additional royalties.. On February 16, 2010, the United States District Court for the District
of Montana vacated the IBLA decision and remanded the matter to the MMS for further administrative review in light of the District Court's holding in Decker I. As of December 31, 2009, the
estimated additional assessed royalties (inclusive of interest) for the period 1993-2001 were approximately $11.0 million. Decker estimates that even if the assessment for the
1993-2001 period were to be upheld, MMS's eventual recovery may be nothing but could be up to $11.0 million.

We
have not accrued a liability in our consolidated financial statements with respect to this matter as any potential losses are not considered to be probable and reasonably estimable.
In addition to its substantive challenges to the assessments, Decker believes that it has contractual price escalation protection from any increased assessments for 1993-2001; that, in
addition, Commonwealth Edison has indemnified Black Butte with respect to the 1993-2001 assessment, and that in furtherance of that

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16. Commitments and Contingencies (Continued)

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



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.

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 84%, 69% and 64% of our revenues for the years ended December 31, 2009, 2008 and 2007, respectively, were under
multi-year contracts which specify pricing terms. While the majority

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16. Commitments and Contingencies (Continued)

of
the contracts are fixed-price contracts, certain contracts have escalation provisions for determining periodic price changes. One customer accounted for revenues of $140.4 million,
$135.1 million and $116.6 million for the years ended December 31, 2009, 2008 and 2007, 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, 2009, we had $241.6 million of standby of letters of credit and $333.0 million of performance bonds outstanding (including our proportional share of Decker) to secure
certain of our obligations to reclaim lands used for mining and to secure coal lease obligations.

17. 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. In February 2010, Rio Tinto released the restricted cash in
connection with the issuance of replacement bonds in March 2010 (see Note 22). Interest expense includes guarantee fees charged by Rio Tinto in connection with these arrangements of
$1.2 million, $1.6 million and $1.3 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Cash Management Arrangement and Reimbursed Overhead

Prior to our IPO, we participated in a cash management arrangement with a Rio Tinto affiliate, in which we transferred cash to and from
the affiliate on a regular basis for investment purposes. Prior to the third quarter of 2008, these transactions bore interest at the same rate as the RTA Facility (see Note 9), which was 4.3%
as of June 30, 2008. Effective July 2008, balances resulting from these transactions bore interest at bank overnight short-term deposit rates. Amounts due from related parties

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17. Related Party Transactions (Continued)

as
of December 31, 2008 resulting from these transactions are included in the table below and the cash flows related to this account are reported in investing activities in the consolidated
statements of cash flows. Interest income related to the cash management agreement totaled $237,000, $2.4 million and $6.3 million for the years ended December 31, 2009, 2008 and
2007, respectively.

Also
prior to our IPO, Rio Tinto affiliates funded certain overhead expenses which were included in due to related parties. These amounts, which were non-interest bearing,
are included in the table below and the cash flows related to this account are reported in operating activities in the consolidated statements of cash flows. In connection with our IPO structuring
transactions, due from (to) related parties were cancelled. See "Initial Public Offering and Related IPO Structuring Transactions" in Note 2.

Due
from (to) related parties reflected arrangements with Rio Tinto affiliates, as follows at December 31, 2008 (in thousands):

Cash management arrangement

$
117,753Reimbursed overhead


(100,983
)Income tax sharing agreement


(26,866
)Other


(2,667
)$
(12,763
)


Other

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 $367,000, $651,000 and $690,000 for the years ended December 31, 2009, 2008 and
2007, 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 and $1.9 million for the years ended December 31, 2009 and 2008, respectively. These transitional services were terminated in March 2009.

Included
in revenues were $21.4 million, $13.6 million and $12.6 million for the years ended December 31, 2009, 2008 and 2007, respectively, for sales of coal
to Venture Fuels Partnership, a 50% owned coal marketing company.

For
additional related party transactions, see "Initial Public Offering and Related IPO Structuring Transactions" and "Pre-IPO Expense Allocations" in Note 2.

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18. Segment Information

Our management reviews, manages and operates our business as a single operating segment, coal production. We produce low sulfur, steam coal from surface mines, located in the Western
region of the U.S. within the PRB, which we sell to electric utilities and industrial customers. We have determined that we have one reportable segment primarily based on our chief operating decision
maker assessing our performance and allocating resources based on a measure derived from our consolidated EBITDA financial measurement. We define EBITDA as income from continuing operations plus
interest expense, depreciation and depletion, accretion, amortization and income tax provision, less interest income. Prior to our IPO, management used an adjusted EBITDA measure in assessing our
performance. The primary differences between the adjusted EBITDA and EBITDA was that adjusted EBITDA included discontinued operations and excluded asset impairment charges, environmental liability
expenses, overburden stripping costs, pension and postretirement healthcare costs and certain costs allocated from other Rio Tinto companies.

The
following table presents a reconciliation of EBITDA to income from continuing operations for the years ended December 31 (in thousands):

2009

2008

2007EBITDA

$
395,568

$
278,872

$
232,324Depreciation and depletion


(97,869
)

(88,972
)

(80,133
)Amortization


(28,719
)

(45,989
)

(34,512
)Accretion


(12,587
)

(12,742
)

(12,212
)Interest income


320


2,865


7,302Interest expense


(5,992
)

(20,376
)

(40,930
)Income tax provision


(68,249
)

(25,318
)

(18,050
)Income from continuing operations

$
182,472

$
88,340

$
53,789


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

2009

2008

2007United States

$
1,271,738

$
1,183,299

$
1,028,075Foreign


126,462


56,412


25,093Total revenues from external customers

$
1,398,200

$
1,239,711

$
1,053,168


We
attribute revenue to individual countries based on the location of the customer.

As
of December 31, 2009 and 2008, all of our long-lived assets were located in the U.S. All of our revenues for the years ended December 31, 2009, 2008 and 2007
originated in the U.S. Our segment revenue and segment total assets equal the consolidated amounts in the consolidated financial statements.

148

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CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. Summary Unaudited Quarterly Financial Information

A summary of the unaudited quarterly results of operations for the years ended December 31, 2009 and 2008 is presented below (in thousands). CPE Inc. common stock is listed
on the New York Stock Exchange under the symbol "CLD."

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




Year Ended December 31, 2008First
Quarter

Second
Quarter

Third
Quarter

Fourth
QuarterRevenues

$
301,664

$
281,706

$
321,257

$
335,084Operating income


36,485


18,675


28,078


41,698Income from continuing operations


22,270


10,357


22,383


33,330Net income


8,291


864


16,666


37,304Net income attributable to controlling interest


8,291


864


16,666


37,304Income per common share from continuing operations attributable to the controlling interest:Basic

$
0.37

$
0.17

$
0.37

$
0.56Diluted

$
0.37

$
0.17

$
0.37

$
0.56


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 14).

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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Table of Contents

CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. Supplemental Cash Flow Information

Year Ended December 31,2009

2008

2007Supplemental cash flow disclosures for continuing operations:Interest paid

$
17,606

$
4,410

$
6,066Income taxes paid (refunded), net


79,089


(348
)

2,437Supplemental noncash investing and financing activities from continuing operations:Long-term debt incurred to acquire federal coal leases and other mineral rights

$
37,424

$
168,009

$
13,553Conversion of debt to equity





547,382


Noncash capital contributions from Rio Tinto America


158,400


46,078


13,705


21. 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 year ended December 31, 2009 and for the period from July 31, 2008 (date of inception) to December 31, 2008.

Condensed Balance Sheets

December 31,2009

2008(in thousands)ASSETSCurrent assetsDeferred income taxes

$
280

$
Other assets


891


Total current assets


1,171


Deferred income taxes


100,520


Investment in Cloud Peak Energy Resources LLC


205,995


Total assets

$
307,686

$
LIABILITIES and SHAREHOLDERS' EQUITYCurrent liabilitiesDue to related party

$
106

$
116Current portion of tax agreement liability


758


Accrued expenses


166


Total current liabilities


1,030


116Tax agreement liability, net of current portion


53,751


Total liabilities


54,781


116Total shareholders' equity (deficit)


252,905


(116
)Total liabilities and shareholders' equity

$
307,686

$



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Table of Contents

CLOUD PEAK ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Condensed Statements of Operations

Period Ended December 31,2009

2008(in thousands)Revenues

$
475

$
Costs and expensesGeneral and administrative expenses


475


116Total costs and expenses


475


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





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


12,791


Income tax provision


4,216


Net income (loss)

$
8,575

$
(116
)


Condensed Statements of Cash Flows

Period Ended
December 31,2009

2008(in thousands)Operating activitiesNet income (loss)

$
8,575

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


(8,575
)

116Net cash used in operating activities





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





Cash and cash equivalents at beginning of period





Cash and cash equivalents at end of period

$


$



22. Subsequent Events

In February 2010, we increased our restricted cash balances to $176.5 million to collateralize the issuance of $443.7 million in surety bonds in connection with the
replacement of surety bonds and letters of credit provided by Rio Tinto on our behalf, primarily associated with our reclamation obligations. The issuance of the replacement surety bonds is expected
to be completed during March 2010, at which time Rio Tinto will be released of any liability associated with our obligations.

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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

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

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

In
connection with our IPO, we have begun implementing changes and improvements in our internal control over financial reporting to remediate the control deficiencies that gave rise to
the material weaknesses. These changes include:



These
remedial steps will need to be placed in operation for a sufficient period of time before we can evaluate the overall effectiveness of our remediation plan and be able to conclude
that the material weaknesses have been remediated.

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, 2009. The previously identified material weaknesses were not yet remediated as of December 31, 2009. As such,
our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has 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

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Table of Contents

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 ineffective as of December 31, 2009.

Notwithstanding
the identified material weaknesses, management concluded that the financial statements and other financial information included in this Annual Report on
Form 10-K fairly present, in all material respects, the financial condition, results of operations and cash flows of Cloud Peak Energy Inc. as of and for the periods
presented in conformity with U.S. GAAP.

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.

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,
2009, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

This
annual report does not include a report on management's assessment regarding internal control over financial reporting or an attestation report of the registered public accounting
firm due to a transition period established by rules of the SEC for newly public companies.

Item 9B.Other Information.

None

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Table of Contents

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 I Directors in our Proxy Statement to be distributed to our stockholders in connection with our 2010 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 2010 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 2010 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 2010 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, 2009
(in thousands):

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


1,011,951

$
15.00


1,539,047Equity compensation plans not approved by security holders


N/A


N/A


N/ATotal


1,011,951

$
15.00


1,539,047


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 2010 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 2010 annual meeting and is incorporated herein by reference.

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PART IV

Item 15.Exhibits and Financial Statement Schedules



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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Table of Contents

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 WYW174407: 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

Federal Coal Lease MTM-069782: Spring Creek Mine (Incorporated by reference to Exhibit 10.13 of the Company's Form S-1 filed on August 12, 2009)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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Table of Contents

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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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, 200910.41*

Employment Agreement between Cloud Peak Energy Inc. and Michael Barrett dated as of November 14, 200910.42*

Employment Agreement between Cloud Peak Energy Inc. and Adrian Nick Taylor dated as of November 14, 200910.43*

Employment Agreement between Cloud Peak Energy Inc. and Gary Rivenes dated as of November 14, 2009


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Exhibit
Number

Description of Documents10.44*

Employment Agreement between Cloud Peak Energy Inc. and James Orchard dated as of November 14, 200910.45*

Employment Agreement between Cloud Peak Energy Inc. and Cary Martin dated as of November 14, 200910.46*

Employment Agreement between Cloud Peak Energy Inc. and Bryan Pechersky dated as of March 3, 201021.1*

List of subsidiaries of Cloud Peak Energy Inc.23.1*

Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm23.2*

Consent of KPMG LLP, Independent Registered Public Accounting Firm31.1*

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


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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.By:

/s/ COLIN MARSHALLDate: March 16, 2010



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)

March 16, 2010/s/ MICHAEL BARRETT Michael Barrett

(Principal Financial Officer)

March 16, 2010/s/ TERRI EGGERT Terri Eggert

(Principal Accounting Officer)

March 16, 2010/s/ KEITH BAILEY Keith Bailey

(Chairman of the Board of Directors)

March 16, 2010/s/ PRESTON CHIARO Preston Chiaro

(Director)

March 16, 2010/s/ WILLIAM T. FOX III William T. Fox III

(Director)

March 16, 2010/s/ C. KEVIN MCARTHUR C. Kevin McArthur

(Director)

March 16, 2010/s/ STEVEN W. NANCE Steven W. Nance

(Director)

March 16, 2010


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Name and Signatures

Title

Date/s/ WILLIAM F. OWENS William F. Owens

(Director)

March 16, 2010/s/ CHRIS TONG Chris Tong

(Director)

March 16, 2010


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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)10.8

Federal Coal Lease WYW174407: Cordero-Rojo Mine (Incorporated by reference to Exhibit 10.8 of the Company's Form S-1 filed on August 12, 2009)


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Table of Contents

Exhibit Number

Description of Documents10.9

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

Federal Coal Lease MTM-069782: Spring Creek Mine (Incorporated by reference to Exhibit 10.13 of the Company's Form S-1 filed on August 12, 2009)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)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)


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Table of Contents

Exhibit Number

Description of Documents10.24

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)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)


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Table of Contents

Exhibit Number

Description of Documents10.38

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, 200910.41*

Employment Agreement between Cloud Peak Energy Inc. and Michael Barrett dated as of November 14, 200910.42*

Employment Agreement between Cloud Peak Energy Inc. and Adrian Nick Taylor dated as of November 14, 200910.43*

Employment Agreement between Cloud Peak Energy Inc. and Gary Rivenes dated as of November 14, 200910.44*

Employment Agreement between Cloud Peak Energy Inc. and James Orchard dated as of November 14, 200910.45*

Employment Agreement between Cloud Peak Energy Inc. and Cary Martin dated as of November 14, 200910.46*

Employment Agreement between Cloud Peak Energy Inc. and Bryan Pechersky dated as of March 3, 201021.1*

List of subsidiaries of Cloud Peak Energy Inc.23.1*

Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm23.2*

Consent of KPMG LLP, Independent Registered Public Accounting Firm31.1*

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


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