UNITED STATES ~~SECURITIES AND EXCHANGE COMMISSION~~

SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)
x		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the year ended December 31, 2010
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

(Mark One)

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

For the fiscal year ended December 31, 2013

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

For the transition period from to

Commission File Number: 001-34547

Commission File Number: 333-168639

Cloud Peak Energy Inc.

Cloud Peak Energy Resources LLC

(Exact name of registrant as specified in its charter)

Delaware		26-3088162
Delaware		26-4073917
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

505 S. Gillette Ave., Gillette, Wyoming		82716
(Address of principal executive offices)		(Zip Code)

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

~~(Registrant’s~~Securities ~~telephone~~Registered ~~number,~~Pursuant ~~including~~to ~~area code~~Section 12(b) of the Act:

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

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

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

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

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

~~Indicate~~Cloud byPeak ~~check~~Energy ~~mark~~Inc. ifYesx ~~the~~Noo ~~registrant~~Cloud isPeak ~~not~~Energy ~~required~~Resources toLLC ~~file~~Yesx ~~reports pursuant to Section 13 or Section 15(d) of the Act Yes o No x~~Noo

Indicate by check mark ~~whether~~if the registrant ~~(1) has~~is ~~filed~~not ~~all reports~~ required to befile ~~filed~~reports bypursuant to Section 13 or Section 15(d) of the ~~Securities Exchange~~ Act ~~of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days~~. ~~Yes x No o~~

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

Indicate by check mark ifwhether ~~disclosure~~the ofregistrant ~~delinquent~~(1) has ~~filers~~filed ~~pursuant~~all reports required to ~~Item~~be filed by Section ~~405~~13 ofor ~~Regulation~~15(d) ~~S-K~~of isthe ~~not~~Securities ~~contained~~Exchange ~~herein,~~Act ~~and~~of ~~will~~1934 ~~not~~during bethe ~~contained,~~preceding to12 months ~~the~~(or ~~best~~for ofsuch ~~registrant’s~~shorter ~~knowledge,~~period inthat ~~definitive~~the ~~proxy~~registrant orwas ~~information~~required ~~statements~~to ~~incorporated~~file bysuch ~~reference~~reports), inand ~~Part~~(2) ~~III~~has ofbeen ~~this~~subject ~~Form 10-K~~to orsuch ~~any~~filing ~~amendment~~requirements tofor ~~this~~the ~~Form~~past 90 ~~10-K~~days. x

~~Indicate~~Cloud byPeak ~~check~~Energy ~~mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company~~Inc. ~~See~~ ~~the~~Yesx ~~definitions~~Noo ofCloud ~~“large~~Peak ~~accelerated~~Energy ~~filer,”~~Resources ~~“accelerated~~LLC ~~filer,”~~Yesx ~~and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):~~Noo

~~Large~~Indicate ~~accelerated~~by ~~filer~~check omark ~~Accelerated~~whether ~~filer~~the oregistrant ~~Non~~has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-~~accelerated~~T ~~filer~~(§232.405 xof ~~Smaller~~this ~~reporting~~chapter) ~~company~~during othe preceding 12 months (Door ~~not~~for ~~check~~such ifshorter aperiod ~~smaller~~that ~~reporting~~the ~~company~~registrant was required to submit and post such files).

~~Indicate~~Cloud byPeak ~~check~~Energy ~~mark~~Inc. ~~whether~~Yesx ~~the~~Noo ~~registrant~~Cloud isPeak aEnergy ~~shell~~Resources ~~company~~LLC ~~(as~~Yesx ~~defined in Rule 12b-2 of the Exchange Act) Yes o No x~~Noo

AtIndicate ~~February~~by check mark if disclosure of delinquent filers pursuant to Item ~~28,~~405 ~~2011~~of Regulation S-K is not contained herein, ~~all~~and ofwill ~~the~~not ~~outstanding~~be ~~common~~contained, ~~membership~~to ~~units~~the best of ~~Cloud~~registrant’s ~~Peak~~knowledge, ~~Energy~~in ~~Resources~~definitive ~~LLC~~proxy ~~were~~or ~~held~~information statements incorporated by ~~Cloud~~reference ~~Peak~~in ~~Energy~~Part III ~~Inc~~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.

	Large accelerated filer	Accelerated filer	Non-accelerated filer (Do not check if a smaller reporting company)	Smaller reporting company
Cloud Peak Energy Inc.	x	o	o	o
Cloud Peak Energy Resources LLC	o	o	x	o

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

Cloud Peak Energy Inc.		Yeso Nox
Cloud Peak Energy Resources LLC		Yeso Nox

As of June 28, 2013, the last business day of Cloud Peak Energy Inc.’s most recently completed second fiscal quarter, the aggregate market value of the voting and nonvoting common stock held by non-affiliates of Cloud Peak Energy Inc. was approximately $1,003 million based on the closing price of Cloud Peak Energy Inc.’s common stock as reported that day on the New York Stock Exchange of $16.48 per share. In determining this figure, Cloud Peak Energy Inc. has assumed that all of its directors and executive officers are affiliates. Such assumptions should not be deemed conclusive for any other purpose.

Number of shares outstanding of Cloud Peak Energy Inc.’s common stock, as of the latest practicable date: Common stock, $0.01 par value per share, 60,896,479 shares outstanding as of January 31, 2014. 100% of the common membership units of Cloud Peak Energy Resources LLC outstanding as of January 31, 2014 are held by Cloud Peak Energy Inc.

This combined Form 10-K is separately filed by Cloud Peak Energy Inc. and Cloud Peak Energy Resources LLC. Cloud Peak Energy Resources LLC meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

DOCUMENTS INCORPORATED BY REFERENCE

~~None~~Portions of Cloud Peak Energy Inc.’s proxy statement to be filed with the Securities and Exchange Commission in connection with Cloud Peak Energy Inc.’s 2014 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.

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

Table of Contents

CLOUD PEAK ENERGY INC. AND

CLOUD PEAK ENERGY RESOURCES LLC

TABLE OF CONTENTS

			PAGE
		Page
~~PART I~~	PART I
ITEM 1	BUSINESS	~~BUSINESS~~1	7
ITEM 1A	RISK FACTORS	~~RISK FACTORS~~22	29
ITEM 1B	UNRESOLVED STAFF COMMENTS	~~UNRESOLVED STAFF COMMENTS~~43	51
ITEM 2	PROPERTIES	~~PROPERTIES~~43	51
ITEM 3	LEGAL PROCEEDINGS	~~LEGAL PROCEEDINGS~~47	55
ITEM 4	MINE SAFETY DISCLOSURES	~~RESERVED~~48	56
~~PART II~~	PART II
ITEM 5	MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS	~~MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS~~49	57
ITEM 6	SELECTED FINANCIAL DATA	~~SELECTED FINANCIAL DATA~~50	57
ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~56	61
ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~79	77
ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	~~FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA~~81	79
ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	~~CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE~~138	~~118~~
ITEM 9A	CONTROLS AND PROCEDURES	~~CONTROLS AND PROCEDURES~~138	~~118~~
ITEM 9B	OTHER INFORMATION	~~OTHER INFORMATION~~139	~~119~~
~~PART III~~	PART III
ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	~~DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE~~140	~~121~~
ITEM 11	EXECUTIVE COMPENSATION	~~EXECUTIVE COMPENSATION~~140	~~121~~
ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	~~SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS~~140	~~121~~
ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	~~CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE~~140	~~121~~
ITEM 14	PRINCIPAL ACCOUNTING FEES AND SERVICES	~~PRINCIPAL ACCOUNTING FEES AND SERVICES~~141	~~121~~
~~PART IV~~	PART IV
ITEM 15	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	~~EXHIBITS AND FINANCIAL STATEMENT SCHEDULES~~141	~~121~~

Explanatory Note

This combined Form 10-K is filed by Cloud Peak Energy Inc. and Cloud Peak Energy Resources LLC. Each Registrant hereto is filing on its own behalf all of the information contained in this report that relates to such Registrant. Each Registrant hereto is not filing any information that relates to such other Registrant, and therefore makes no representation as to any such information. Cloud Peak Energy Resources LLC is the sole direct subsidiary of Cloud Peak Energy Inc., providing 100% of Cloud Peak Energy Inc.’s total consolidated revenue for the year ended December 31, 2013 and constituting nearly 100% of Cloud Peak Energy Inc.’s total consolidated assets as of December 31, 2013.

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

Table of Contents

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that involve substantial risks and uncertainties. You can identify these statements by forward-looking words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “should,” “will,” “would,” or similar words. You should read statements that contain these words carefully because they discuss our current plans, strategies, prospects, and expectations concerning our business, operating results, financial condition, and other similar matters. ~~There~~While we believe that these forward-looking statements are reasonable as and when made, there may be events in the future, ~~however,~~ that we are not able to predict accurately or control, and there can be no assurance that future developments affecting our business will be those that we anticipate. Additionally, all statements concerning our expectations regarding future operating results are based on current forecasts for our existing operations and do not include the potential impact of any future acquisitions. The factors listed under “Risk Factors,” as well as any cautionary language in this report, ~~provide~~describe ~~examples~~the ofknown material risks, uncertainties, and events that may cause our actual results to differ materially and adversely from the expectations we describe in our forward-looking statements. Additional factors or events that ~~could~~may ~~cause~~emerge ~~our~~from ~~actual~~time ~~results~~to time, or those that we currently deem to ~~differ~~be ~~may~~immaterial, ~~emerge~~could ~~from~~cause ~~time~~our actual results to ~~time~~differ, and it is not possible for us to predict all of them. You are cautioned not to place undue reliance on the forward-looking statements contained herein. We undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events, or otherwise, except as required by law. The following factors are among those that may cause actual results to differ materially and adversely from our forward-looking statements:

· ~~future~~the ~~economic~~prices ~~conditions~~we receive for our coal and our ability to effectively execute our forward sales strategy;

· competition with other producers of coal, including the ~~contract~~impacts ~~prices~~of wecurrency ~~receive~~exchange ~~for~~rate ~~coal~~fluctuations and ~~our~~government ~~customers’~~energy ~~ability~~and totax ~~honor~~policies ~~contract~~that ~~terms~~make foreign coal producers more competitive for international transactions;

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

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

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

· ~~safety and environmental laws and regulations, including those directly affecting~~ our ~~coal~~ability ~~mining~~to ~~and~~maintain ~~production,~~ and ~~those~~grow ~~affecting~~ our ~~customers’~~export ~~coal usage, gaseous emissions or ash handling as well as related costs and liabilities~~sales;

· ~~future legislation~~railroad, ~~changes~~export interminal ~~regulations~~and orother ~~governmental~~transportation ~~policies or changes in interpretations thereof~~performance, costs and ~~third-party regulatory challenges~~availability, including ~~with~~development ~~respect~~of toadditional ~~carbon~~export ~~emissions,~~terminal ~~safety~~capacity ~~standards~~ and ~~regulatory~~our ~~processes~~ability ~~and approvals required~~ to ~~lease~~access ~~and~~additional ~~obtain~~capacity ~~permits~~on ~~for~~commercially ~~coal~~reasonable ~~mining operations or to transport coal to domestic and foreign customers~~terms;

· ~~our~~domestic ~~ability to produce coal at existing~~ and ~~planned~~international ~~volumes~~economic ~~and costs~~conditions;

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

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

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

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

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

· timing of reductions or increases in customer coal inventories;

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

· risks inherent to surface coal mining;

· ~~weather~~our ~~conditions~~ability orto ~~catastrophic~~successfully ~~weather-related~~acquire ~~damage~~coal and appropriate land access rights at attractive prices and in a timely manner and our ability to effectively resolve issues with conflicting mineral development that may impact our mine plans;

~~· changes in energy policy;~~ii

Table of Contents

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

· ~~the~~our ~~availability~~plans and ~~cost~~objectives offor ~~competing~~future ~~energy~~operations ~~resources,~~and ~~including changes in~~ the ~~price~~development of ~~crude~~additional ~~oil~~coal ~~and natural gas generally~~reserves, asincluding ~~well~~risks asassociated ~~subsidies~~with ~~to encourage use of alternative energy sources~~acquisitions;

· ~~railroad~~the impact of current and future environmental, ~~export~~health, ~~terminal~~safety ~~capacity~~and other laws, regulations, treaties or governmental policies, or changes in interpretations thereof, and third-party regulatory challenges, including those affecting our coal mining operations or our customers’ coal usage, carbon and other gaseous emissions or ash handling, or the logistics, transportation, ~~performance~~or terminal industries, as well as related costs and ~~availability~~liabilities;

· ~~disruptions~~the inimpact ~~delivery~~of orrequired ~~changes~~regulatory inprocesses ~~pricing~~and ~~from~~approvals ~~third-party~~to ~~vendors~~lease ofand ~~raw~~obtain ~~materials~~permits ~~and~~for ~~other~~coal ~~consumables~~mining ~~which~~operations ~~are~~or ~~necessary~~to ~~for~~transport ~~our~~coal ~~operations,~~to ~~such~~domestic asand ~~explosives,~~foreign ~~petroleum-based fuel~~customers, ~~tires,~~including ~~steel~~third-party ~~and~~legal ~~rubber~~challenges;

· ~~our~~any ~~assumptions~~increases ~~concerning~~in ~~coal~~rates ~~reserve~~or ~~estimates~~changes in regulatory interpretations or assessment methodologies with respect to royalties or severance and production taxes;

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

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

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

· ~~liquidity~~disruptions ~~constraints,~~in ~~including~~delivery ~~those~~or ~~resulting~~increases ~~from~~in ~~the~~pricing ~~cost~~from orthird-party ~~unavailability~~vendors of ~~financing~~raw ~~due~~materials toand ~~credit~~other ~~market~~consumables ~~conditions~~which are necessary for our operations, such as explosives, petroleum-based fuel, tires, steel, and rubber;

· our ~~liquidity,~~assumptions ~~results~~concerning ofcoal ~~operations~~reserve ~~and financial condition, including amounts of working capital that are available~~estimates; ~~and~~

· our relationships with, and other ~~factors~~conditions affecting, our customers (including ~~those~~our ~~discussed~~largest incustomers ~~“Risk~~who ~~Factors.”~~account for a significant portion of our total revenue) and other counterparties, including economic conditions and the credit performance and credit risks associated with our customers and other counterparties, such as traders, brokers, and lenders under our credit agreement and financial institutions with whom we maintain accounts or enter hedging arrangements;

2· the results of our hedging strategies for commodities, including our current hedging programs for coal sales and diesel fuel costs;

· the terms and restrictions of our indebtedness;

· liquidity constraints, including those resulting from the cost or unavailability of financing due to credit market conditions or our compliance with the financial covenants in our debt agreements;

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

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

· other factors, including those discussed in Item 1A of this Form 10-K.

iii

Table of Contents

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~~remain ~~contained~~after inthe combustion of coal. The composition of the ash can affect the burning characteristics of coal.

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

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

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

BNSF. Burlington Northern Santa Fe Railroad.

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

CAIR. Clean Air Interstate Rule.

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

CPE Inc. Cloud Peak Energy Inc., a Delaware corporation.

CPE Resources. Cloud Peak Energy Resources LLC, a Delaware limited liability company, formerly known as Rio Tinto Sage LLC, which is the sole direct subsidiary of CPE Inc.

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

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

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

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

CSAPR. Cross-State Air Pollution Rule.

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.~~iv

EIS. Environmental impact statement.

Table of Contents

EIA. Energy Information Administration.

EIS. Environmental Impact Statement.

EPA. United States Environmental Protection Agency.

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

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

GHG. Greenhouse gas.

GW. Gigawatts.

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

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

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

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

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

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

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

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

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

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

MSHA. Mine Safety and Health Administration.

NAAQ. National Ambient Air Quality.

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

Non-reserve coal deposits. Non-reserve coal deposits are coal bearing bodies that have been sufficiently sampled and analyzed in trenches, outcrops, drilling and underground workings to assume continuity between sample points, and therefore warrant further exploration work. However, this coal does not qualify as commercially viable coal reserves as prescribed by the Securities and Exchange Commission (the “SEC”) standards until a final comprehensive evaluation based on unit cost per ton, recoverability and other material factors concludes legal and economic feasibility. Non-reserve coal deposits may be classified as such by either limited property control or geologic limitation, or both.

Table of Contents

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

Non-reserve coal deposits. Non-reserve coal deposits are coal bearing bodies that have been sufficiently sampled and analyzed in trenches, outcrops, drilling, and underground workings to assume continuity between sample points, and therefore warrant further exploration work. However, this coal does not qualify as commercially viable coal reserves as prescribed by the Securities and Exchange Commission, or SEC, standards until a final comprehensive evaluation based on unit cost per ton, recoverability, and other material factors concludes legal and economic feasibility. Non-reserve coal deposits may be classified as such by either limited property control or geologic limitation, or both.

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

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

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

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

Probable reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, 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~~Rio ~~habitat~~Tinto. ~~Areas~~Rio ~~adjacent~~Tinto plc toand ~~rivers~~Rio Tinto Limited and ~~streams~~their ~~with~~direct aand ~~differing~~indirect ~~density~~subsidiaries, ~~diversity~~including ~~and~~Rio ~~productivity~~Tinto ofEnergy ~~plant~~America Inc. (“RTEA”), our predecessor for accounting purposes; Kennecott Management Services Company (“KMS”); and ~~animal~~Rio ~~species~~Tinto ~~relative~~America toInc. ~~nearby~~(“RTA”), ~~uplands~~which is the owner of RTEA and KMS.

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

Riverine habitat. A habitat occurring along a river.

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

SMCRA. Surface Mining Control and Reclamation Act of 1977.

Table of Contents

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

~~Steam~~Subbituminous coal. ~~Coal~~Black ~~used~~coal bythat ~~power~~ranks ~~plants~~between lignite and ~~industrial~~bituminous ~~steam~~coal. Subbituminous ~~boilers~~coal toproduced ~~produce~~from ~~electricity~~the orPRB ~~process~~has ~~steam. It~~a ~~generally~~moisture iscontent ~~lower~~between in20% ~~Btu~~to ~~heat~~over ~~content~~30% by weight, and ~~higher~~its inheat ~~volatile~~content ~~matter~~ranges ~~than~~from ~~metallurgical~~8,000 ~~coal~~to 9,500 Btus.

~~Sub-bituminous coal~~Sulfur. ~~Black~~One ~~coal~~of ~~that~~the ~~ranks~~elements ~~between~~present ~~lignite~~in ~~and~~varying ~~bituminous~~quantities ~~coal. Sub-bituminous~~in coal ~~produced~~that ~~from~~contributes ~~the~~to ~~PRB~~environmental ~~has~~degradation awhen ~~moisture~~coal ~~content~~is ~~between~~burned. Sulfur ~~20%~~dioxide to(“SO2”) ~~over~~is ~~30%~~produced byas ~~weight,~~a ~~and~~gaseous ~~its~~by-product ~~heat~~of ~~content~~coal ~~ranges from 8,000 to 9,500 Btus~~combustion.

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.

Table of Contents

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~~Tax ~~“short”~~agreement ~~or net ton is equal to 2,000 pounds~~liability. AThe ~~“long”~~undiscounted orestimated ~~British~~future ~~ton~~liability isowed ~~2,240~~by ~~pounds. A~~CPE ~~“metric” tonne is approximately 2,205 pounds~~Inc. ~~The~~ ~~short~~to ~~ton~~Rio isTinto under the ~~unit~~Tax ofReceivable ~~measure referred to in this document~~Agreement.

Tax Receivable Agreement. We and RTEA entered into a Tax Receivable Agreement in connection with the IPO and the acquisition of our membership units of CPE Resources. The Tax Receivable Agreement requires us to pay to RTEA 85% of the amount of cash tax savings, if any, that we realize as a result of the increases in tax basis that we obtained in connection with the initial acquisition of our interest in CPE Resources and our subsequent acquisition of RTEA’s remaining units in CPE Resources.

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

Tonnes. A “metric” ton, equal to 2,205 pounds.

Tons. A “short” or net ton, equal to 2,000 pounds.

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

Union Pacific or UP. Union Pacific Railroad.

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

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

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

· “IPO Structuring Agreements” refers to the following agreements entered into in connection with Holdings’s initial public offering (the “IPO”): The master separation agreement, the acquisition agreement, the assignment agreement, the agency contract, the promissory note, the employee matters agreement, the escrow agreement, the CPE Resources limited liability company agreement, the management services agreement, registration rights agreement, the Rio Tinto Energy America coal supply agreement, the software license agreement, the tax receivable agreement, the trademark assignment agreement, the trademark license agreement, and the transition services agreement. We refer generally to the transactions we entered into in connection with these IPO Structuring Agreements as IPO structuring transactions or structuring transactions. See “Initial Public Offering, Related IPO Structuring Transactions, and Secondary Offering” in Note 2 of Notes to Consolidated Financial Statements in Item 8; and

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

Table of Contents

PART I

Item 1. Business.

Overview

WeCPE ~~are~~Inc. ~~the~~is ~~third~~one of the largest ~~producer~~producers of coal in the United States of America (“U.S.”) and in the ~~Powder River Basin, or~~ PRB, based on our ~~2010~~2013 coal ~~production of 95~~sales.~~3 million tons.~~ We ~~had revenues from our continuing operations of $1.4 billion in 2010. We~~ operate some of the safest mines in the coal industry. According to ~~Mine Safety and Health Administration, or~~ MSHA, data, in ~~2010~~2013, we had one of the lowest employee all injury incident ~~rate~~rates among the 10 largest U.S. coal producing companies. We operate solely in the PRB, the lowest cost coal producing region of the major coal producing regions in the U.S., and operate two of the four largest coal mines in the region and in the U.S. Our operations include three wholly-owned surface coal mines, two of which are in Wyoming and one of which is in Montana. We also own a 50% interest in a fourth surface coal mine in Montana. We produce sub-bituminous steam coal with low sulfur content and sell our coal primarily to domestic electric utilities, supplying approximately 47 customers with over 108 domestic plants. We do not produce any metallurgical coal. Steam coal is primarily consumed by electric utilities and industrial consumers as fuel for electricity generation. In 2010, the coal we produced generated approximately 4% of the electricity produced in the U.S. As of December 31, 2010, we controlled approximately 970 million tons of proven and probable reserves.

We ~~are~~currently aoperate ~~wholly-owned~~solely ~~subsidiary~~in ofthe ~~Cloud~~PRB, ~~Peak~~the ~~Energy~~lowest ~~Inc. Cloud~~cost ~~Peak~~region ~~Energy~~of ~~Inc.,~~the amajor ~~Delaware~~coal ~~corporation~~producing ~~organized~~regions onin ~~July 31,~~the ~~2008~~U.S., iswhere awe ~~holding~~operate ~~company~~three ~~that~~wholly-owned ~~has~~surface nocoal ~~business~~mines, ~~operations~~the orAntelope ~~material assets other than its ownership interest as of December 31~~mine, ~~2010 of 100% of~~ the ~~common~~Cordero ~~membership~~Rojo ~~units~~mine inand ~~CPE~~the ~~Resources~~Spring asCreek ~~discussed more fully in “History” below~~mine. ~~Holdings’s~~We ~~only~~also ~~source~~have oftwo ~~cash~~major ~~flow~~development ~~from~~projects, ~~operations~~the isYoungs ~~distributions~~Creek ~~from~~project usand ~~pursuant to~~ the ~~CPE~~Crow ~~Resources~~project ~~limited~~and ~~liability~~own ~~company~~a ~~agreement. Holdings~~50% ~~also~~non-operating ~~receives~~interest ~~management~~in ~~fees pursuant to~~ a ~~management~~fourth ~~services~~surface ~~agreement~~mine, ~~between~~the usDecker ~~and Holdings as reimbursement of certain administrative expenses~~mine.

~~History~~Our Antelope and Cordero Rojo mines are located in Wyoming and are two of the four largest coal mines in the U.S. Our Spring Creek mine is located in Montana. Our mines produce subbituminous thermal coal with low sulfur content, and we sell our coal primarily to domestic and foreign electric utilities. We do not produce any metallurgical coal. Thermal coal is primarily consumed by electric utilities and industrial consumers as fuel for electricity generation and steam output. In 2013, the coal we produced generated approximately 4% of the electricity produced in the U.S. As of December 31, 2013, we controlled approximately 1.2 billion tons of proven and probable reserves.

WeDuring ~~were formed as Rio Tinto Sage LLC~~2012, awe ~~Delaware~~acquired ~~limited~~rights ~~liability~~to ~~company~~substantial ~~formed~~undeveloped ascoal aand ~~wholly-owned~~complementary ~~subsidiary~~surface ofassets ~~RTEA~~in onthe ~~August 19,~~Northern ~~2008. RTEA~~PRB is(“Youngs ~~our~~Creek ~~predecessor for accounting purposes~~project”). ~~RTEA,~~In ~~a Delaware corporation~~January 2013, ~~formerly~~we ~~known~~entered asan ~~Kennecott~~option ~~Coal~~to ~~Company,~~lease ~~was~~agreement ~~formed~~(“Option asAgreement”) ~~a wholly-owned subsidiary of Rio Tinto America on March 1, 1993. Between 1993~~ and ~~1998,~~a ~~RTEA~~corresponding ~~acquired~~exploration ~~the~~agreement ~~Antelope,~~(“Exploration ~~Colowyo,~~Agreement”) ~~Jacobs~~with ~~Ranch and Spring Creek coal mines and~~ the ~~Cordero~~Crow ~~and~~Tribe ~~Caballo~~of ~~Rojo coal mines~~Indians, which ~~are~~were ~~operated~~approved ~~together~~by as the ~~Cordero~~Department ~~Rojo~~of ~~coal mine, and a 50% interest in~~ the ~~Decker~~Interior ~~coal~~on ~~mine~~June 14, ~~which is operated by a third-party mine operator~~2013. InThis ~~December 2008, RTEA contributed Rio Tinto America’s western U.S.~~ coal ~~business~~project ~~to CPE Resources~~ (~~other~~“Crow ~~than~~project”) ~~the Colowyo mine, which~~ is ~~now~~located ~~owned~~on ~~indirectly~~the byCrow ~~Rio~~Indian ~~Tinto~~Reservation ~~America). On~~in ~~October 1,~~southeast ~~2009~~Montana, ~~CPE~~near ~~Resources~~our ~~sold~~Spring ~~the~~Creek ~~Jacobs Ranch~~ mine ~~to Arch Coal, Inc.~~ and ~~distributed~~Youngs ~~the~~Creek ~~proceeds to Rio Tinto~~project. OnWe ~~November 19,~~are ~~2009,~~in ~~Cloud~~the ~~Peak~~process ~~Energy~~of ~~Inc.~~evaluating ~~acquired~~the ~~from~~development ~~RTEA~~options ~~approximately~~for ~~51.0% of~~ the ~~common~~Youngs ~~membership~~Creek ~~units~~project inand ~~CPE~~the ~~Resources~~Crow inproject, ~~exchange~~and ~~for~~believe athat ~~promissory~~their ~~note~~proximity ~~and~~to the ~~SEC~~Spring ~~declared~~Creek ~~effective~~mine ~~Cloud~~represents ~~Peak~~an ~~Energy~~opportunity ~~Inc.’s~~to ~~Registration~~optimize ~~Statement~~our onmine ~~Form S-1~~developments ~~(File~~in ~~No. 333-161293) for~~ the ~~IPO~~Northern PRB. AsFor apurposes ~~result~~ of ~~these~~this ~~transactions~~report, ~~Cloud~~the ~~Peak~~term ~~Energy~~“Northern ~~Inc.~~PRB” ~~became~~refers to the ~~sole~~area ~~managing~~within ~~member~~the ofPRB ~~CPE~~that ~~Resources~~lies ~~with~~within aMontana ~~controlling~~and ~~interest~~the innorthern ~~CPE~~part ~~Resources~~of ~~and~~Sheridan ~~its~~County, ~~subsidiaries~~Wyoming. ~~Cloud~~Our ~~Peak~~Spring ~~Energy~~Creek ~~Inc.~~mine, ~~used~~ the ~~proceeds~~Decker ~~from~~mine, the ~~IPO~~Youngs toCreek ~~repay~~project and the ~~promissory~~Crow ~~note~~project ~~upon~~are ~~the~~located ~~completion~~in of the ~~IPO~~Northern ~~on November 25, 2009~~PRB.

OnSince ~~December 15~~2008, ~~2010,~~we ~~Cloud~~have ~~Peak~~grown ~~Energy~~our ~~Inc.~~sales ~~priced~~of aPRB ~~secondary~~coal ~~offering~~into ofthe 29Asian export market. In 2013,~~400,000~~ ~~shares~~our oflogistics ~~its~~business ~~common~~was ~~stock~~the onlargest ~~behalf~~U.S. exporter of ~~Rio~~thermal ~~Tinto~~coal ~~(the~~into ~~“Secondary~~South ~~Offering”)~~Korea. InWe ~~connection~~continue ~~with~~to ~~the~~seek ~~Secondary~~ways ~~Offering~~to increase our future export capacity through existing and proposed Pacific Northwest export terminals, ~~Cloud~~including ~~Peak~~our ~~Energy~~option ~~Inc~~agreement with SSA Marine. This ~~exchanged~~throughput ~~29,400,000~~option ~~shares~~agreement ofwith ~~common~~SSA ~~stock~~Marine provides us with an option for ~~the~~up ~~common~~to ~~membership~~16 ~~units~~million tonnes of ~~CPE~~capacity ~~Resources~~per ~~held~~year bythrough ~~Rio~~the ~~Tinto~~planned ~~and~~dry ~~completed~~bulk ~~the~~cargo ~~Secondary~~Gateway ~~Offering,~~Pacific ~~resulting~~Terminal at Cherry Point in athe ~~divestiture~~State of ~~100%~~Washington. Our potential share of ~~Rio~~capacity ~~Tinto’s~~will ~~holdings~~depend inupon ~~CPE~~the ~~Resources~~ultimate capacity of the terminal and is subject to the terms of the option agreement. AsThe aterminal ~~result~~will ofaccommodate ~~this~~cape ~~transaction,~~size ~~CPE~~vessels. Our ~~Resources~~option is ~~now~~exercisable afollowing ~~wholly-owned~~the ~~subsidiary~~successful completion of ~~Cloud~~the ~~Peak~~ongoing ~~Energy~~permit ~~Inc~~process for the terminal, which is uncertain.

7For information regarding our revenue and long-lived assets by geographic area, as well as revenue from external customers, Adjusted EBITDA and total assets by segment, please see Note 22 of Notes to Consolidated Financial Statements in Item 8.

Segment Information

We have reportable segments of Owned and Operated Mines, Logistics and Related Activities, and Corporate and Other.

Our Owned and Operated Mines segment is characterized by the predominant focus on thermal coal production where the sale occurs at the mine site and where title and risk of loss pass to the customer at that point. This segment includes our Antelope mine, Cordero Rojo mine, and Spring Creek mine. Sales in this segment are primarily to domestic electric utilities; although a portion is made to our Logistics and Related Activities segment. Our mines utilize surface mining extraction processes and are all located in the PRB. The gains and losses resulting

Table of Contents

~~The~~from ~~following~~our ~~condensed~~domestic ~~diagram~~coal ~~depicts~~futures ~~our~~contracts ~~organizational~~and ~~structure~~West asTexas ofIntermediate ~~December 31,~~(“WTI”) ~~2010:~~collar derivative financial instruments are reported within this segment.

~~(1) Operated~~Our ~~together~~Logistics asand Related Activities segment is characterized by the ~~Cordero~~services ~~Rojo~~we provide to our international and domestic customers where we deliver coal to the customer at a terminal or the customer’s plant or other delivery point, remote from our mine site. Services provided include: the purchase of coal from third parties or from our owned and operated mines as well as the contracting and coordination of the transportation and other handling services from third-party operators — typically rail and terminal companies. Title and risk of loss are retained by the Logistics and Related Activities segment through the transportation and delivery process. Title and risk of loss pass to the customer in accordance with the contract and typically occur at a vessel loading terminal, a vessel unloading terminal or an end use facility. Risk associated with rail and terminal take-or-pay agreements is also borne by the Logistics and Related Activities segment. The gains and losses resulting from our international coal forward derivative financial instruments are reported within this segment.

Our Corporate and Other segment includes results relating to broker activity, our share of the Decker mine operations, and unallocated corporate costs and assets. All corporate costs, except Board of Directors related expenses, are allocated to the segments based upon their relative percentage of certain financial metrics.

Eliminations represent the purchase and sale of coal between reportable segments and the associated elimination of intercompany profit or loss in inventory. Sales between reportable segments are priced based on prevailing market prices.

History

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

Our business operations are conducted by CPE Resources, formerly known as Rio Tinto Sage LLC, a Delaware limited liability company formed as a wholly-owned subsidiary of RTEA on August 19, 2008. RTEA is our predecessor for accounting purposes. RTEA, a Delaware corporation, formerly known as Kennecott Coal Company, was formed as a wholly-owned subsidiary of RTA on March 1, 1993. Between 1993 and 1998, RTEA acquired the Antelope, Colowyo, Jacobs Ranch and Spring Creek coal mines and the Cordero and Caballo Rojo coal mines, which are operated together as the Cordero Rojo coal mine, and a 50% non-operating interest in the Decker coal mine. In December 2008, RTEA contributed RTA’s western U.S. coal business to CPE Resources (other than the Colowyo mine). On October 1, 2009, CPE Resources sold the Jacobs Ranch mine to Arch Coal, Inc. and distributed the proceeds to Rio Tinto.

CPE Inc. acquired approximately 51% and the managing member interest in CPE Resources in exchange for a promissory note which was repaid with proceeds from the initial public offering of its common stock (“IPO”) on November 19, 2009. Rio Tinto retained ownership of the remaining 49% until December 15, 2010, when CPE Inc. priced a secondary offering of its common stock on behalf of Rio Tinto. In connection with the secondary offering, CPE Inc. exchanged shares of common stock for the 49% common membership units of CPE Resources held by Rio Tinto and completed the secondary offering on behalf of Rio Tinto (the “Secondary Offering”), resulting in our acquisition of 100% of Rio Tinto’s holdings in CPE Resources. As a result of this transaction, CPE Resources became a wholly-owned subsidiary of CPE Inc., and Rio Tinto no longer holds an interest in CPE Resources.

Coal Characteristics

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

~~Heat Value~~2

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.

Table of Contents

Heat Value

The heat value of coal is commonly measured in Btus. Subbituminous coal from the PRB has a typical heat value that ranges from 8,000 to 9,500 Btus. Subbituminous coal from the PRB is used primarily by electric utilities and by some industrial customers for steam generation. Coal found in other regions in the U.S., including the eastern and Midwestern regions, tends to have a higher heat value than coal found in the PRB, other than lignite coal which has lower heat value than subbituminous coal but is typically only used to supply coal to utilities that are directly adjacent to the mine.

Sulfur Content

Federal and state environmental regulations, including regulations that limit the amount of sulfur dioxide that may be emitted as a result of combustion, have affected and may continue to affect the demand for certain types of coal. See “Environmental and Other Regulatory Matters—Clean Air Act.” The sulfur content of coal can vary from seam to seam and within a single seam. The ~~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, such as scrubbers, which can reduce sulfur dioxide emissions by up to 90%. ~~PRB~~According to the EPA, in 2012, out of utilities with a coal ~~typically~~generating ~~has~~capacity of approximately 320 GW, utilities accounting for a ~~lower~~capacity ~~sulfur~~of ~~content~~over ~~than~~190 ~~eastern~~GW Uhad been retrofitted with scrubbers.S. Furthermore, ~~coal~~any ~~and~~new ~~generally~~coal-fired ~~emits~~generation noplants ~~greater~~built ~~than~~in 0the U.8S. ~~pounds~~are ofexpected ~~sulfur~~to ~~dioxide~~use ~~per~~some ~~million~~type ~~Btus~~of sulfur-reduction technology. ~~All~~The ofdemand ~~our~~or ~~reserves~~price ~~are~~for ~~compliance~~lower sulfur coal ~~under~~may ~~the~~decrease ~~Clean~~with ~~Air~~widespread ~~Act~~implementation of sulfur-reduction technology.

~~Higher~~PRB ~~sulfur noncompliance~~ coal ~~can~~typically behas ~~burned~~a inlower ~~plants equipped with~~ sulfur~~-reduction~~ ~~technology,~~content ~~such~~than aseastern scrubbers, which can reduce sulfur dioxide emissions by up to 90%, and in facilities that blend compliance and noncompliance coal. In 2009, out of utilities with a coal generating capacity of approximately 314 GW, utilities accounting for a capacity of over 168 GW had been retrofitted with scrubbers. Furthermore, all new coal-fired generation plants built in the U.S. ~~are~~coal ~~expected~~and togenerally ~~use~~emits ~~some~~no ~~type~~greater ofthan ~~sulfur-reduction technology~~1. ~~The~~2 ~~demand~~pounds orof ~~price for lower~~ sulfur ~~coal~~dioxide ~~may~~per ~~decrease~~million ~~with widespread implementation of sulfur-reduction technology~~Btus.

Other

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

Moisture content of coal varies by the type of coal and the region where it is mined. In general, high moisture content is associated with lower heat values and generally makes the coal more expensive to transport. Moisture content in coal, on an as-sold basis, can range from approximately 2% to over 35% of the coal’s weight. PRB coals have typical moisture content of 2520% to 3530%.

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

Coal Mining Methods

Surface Mining

All of our mines are surface mining operations utilizing both dragline and truck-and-shovel mining methods. Surface mining is used when coal is found relatively close to the surface. Surface mining typically involves the removal of topsoil, and drilling and blasting the overburden (earth and rock covering the coal) with explosives. The overburden is then removed with draglines, trucks, shovels, and dozers. Trucks and shovels then remove the coal. The final step involves replacing the overburden and topsoil after the coal has been excavated, reestablishing vegetation ~~and plant life~~ into the natural habitat and making other changes designed to provide local community benefits. We typically recover 9290% or more of the economic coal seam for the mines we operate.

~~Coal Preparation and Blending~~3

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

Table of Contents

~~may~~Coal bePreparation ~~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.Blending

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

Mining Operations

We currently operate solely in the PRB. Two of the mines we operate are located in Wyoming and one is located in Montana. We also own a 50% non-operating interest in the Decker mine, which is located in Montana. The ~~and~~other ~~operated~~50% bymine aowner ~~third-party~~has ~~mine~~responsibility ~~operator~~for the day-to-day operations. We currently own the majority of the equipment utilized in our mining operations, excluding the Decker mine. We employ preventative maintenance and rebuild programs and upgrade our equipment as part of our efforts to ensure that it is productive, well -maintained, and cost -competitive. Our maintenance programs also utilize procedures designed to enhance the efficiencies of our operations. The following table provides summary information regarding our mines as of December 31, ~~2010~~2013.

	Annual Maximum	2010 As Delivered Average				Tons Sold (in millions)
	2013 As Delivered Average				Tons Sold
Mine	Production Capacity(1)	Btu per lb	Ash Content(2)	Sulfur Content		2010	2009	2008
	Btu	Ash
	(million tons)		(%)	(%)	(lbs SO2/mmBtu)	(million tons)
Mine	per lb	Content	Sulfur Content		2013	2012	2011
Antelope	42	8,858	5.4	0.26	0.59	35.9	34.0	35.8
		(%)	(%)	(lbs SO2/mmBtu)	(million tons)
Cordero Rojo	65	8,389	5.4	0.31	0.74	38.5	39.3	40.0
Antelope	8,897	5.20	0.22	0.49	31.4	34.3	37.1
Spring Creek	24	9,262	5.2	0.32	0.69	19.3	17.6	17.9
Cordero Rojo(1)	8,476	5.42	0.29	0.68	36.7	39.2	39.5
Decker(3)	16	9,482	4.5	0.42	0.89	1.5	2.3	3.3
Spring Creek	9,283	4.96	0.33	0.71	18.0	17.2	19.1
Other(4)	N/A	N/A	N/A	N/A	N/A	1.7	10.1	8.1
Decker(2)	9,455	4.69	0.41	0.87	1.5	1.4	1.5
Total						96.9	103.3	105.1
Other(3)	N/A	N/A	N/A	N/A	1.5	0.9	1.5
Total					89.1	93.0	98.7

(1) ~~Based~~ We onhave ~~the~~announced ~~respective~~that ~~mine’s~~we ~~current~~are ~~air~~currently ~~quality~~evaluating ~~permit~~reducing ~~restrictions~~Cordero Rojo production by approximately 10 million tons per year starting in 2015.

(2) ~~Post-combustion~~ Tons ~~ash~~sold ~~from~~numbers ~~Spring~~reflect ~~Creek~~our ~~coal contains an average of approximately 8~~50% ~~sodium oxide. Earthen materials can be selectively blended with the coal within the crushing facility to reduce the post~~non-~~combustion~~operating ~~sodium level and enable the production of a range of products tailored for customers requiring lower sodium levels~~interest.

(3) ~~Tons~~ The ~~sold~~tonnage ~~numbers~~shown ~~reflect~~for “Other” represents our ~~50%~~purchases ~~interest~~from inthird-party ~~the~~sources ~~Decker~~that ~~mine~~we have resold. See “—Customers and Coal Contracts—Broker Sales and Third-Party Sources.”

~~(4) The~~Our ~~tonnage~~Antelope ~~shown~~and ~~for~~Cordero ~~“Other”~~Rojo ~~represents~~mines ~~our~~are ~~purchases~~served ~~from~~by ~~third-party~~the ~~sources~~BNSF ~~that~~and weUP ~~have~~railroads. Our ~~resold,~~Spring ~~including~~Creek ~~coal~~mine ~~we have purchased~~ and ~~resold from~~ the ~~Jacobs~~Decker ~~Ranch~~ mine, ~~which~~are ~~our~~served ~~predecessor~~solely ~~used~~by tothe ~~own.~~BNSF ~~See “—Customers and Coal Contracts—Broker Sales and Third-Party Sources~~railroad.”

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.4

Table of Contents

The following map shows the locations of our mining operations:

Antelope Mine

The Antelope mine is located in the southern end of the PRB approximately 60 miles south of Gillette, Wyoming. The mine extracts ~~steam~~thermal coal from the Anderson and Canyon Seams, with up to 44 and 36 feet, respectively, in thickness. WeTwo ~~have~~of ~~nominated~~our asfederal ancoal ~~LBA,~~leases afor ~~large~~the ~~coal~~Antelope ~~tract~~mine ~~adjacent~~have tobeen ~~our~~subject ~~existing~~to ~~operation. The~~legal ~~BLM~~challenges ~~will~~against ~~determine~~the ifU.S. ~~the~~Bureau ~~tract~~of ~~will~~Land beManagement ~~leased,~~(“BLM”) and ~~if so,~~ the ~~final~~Secretary ~~boundaries~~ of, ~~and~~ the ~~coal~~Interior ~~tonnage~~by ~~for,~~environmental ~~this tract~~organizations. ~~Acquisition~~See ofItem ~~this~~3 ~~tract~~“Legal ~~would~~Proceedings—West ~~facilitate~~Antelope ~~access~~II toLBA ~~approximately~~Challenges.” 80Significant ~~million~~areas ~~tons~~ of ~~non-reserve~~unleased coal ~~deposits~~north ~~that~~and wewest ~~control. We~~of ~~currently expect~~ the ~~BLM~~mine ~~will~~are ~~schedule~~available ~~this LBA~~ for ~~bid~~nomination ~~sometime~~by inus ~~2011,~~or ~~subject~~other tomining ~~the~~operations ~~outcome~~or ofpersons. Based ~~legal~~on ~~challenges~~the ~~filed~~average insulfur ~~2010~~content ~~against~~of ~~the~~0.52 ~~BLM~~lbs ~~and~~SO2/mmBtu, the ~~Secretary~~reserves ofat ~~the~~our ~~Interior~~Antelope bymine ~~environmental~~are ~~organizations~~considered ~~with respect~~ to ~~the~~be ~~EIS~~compliance ~~and~~coal ~~other~~under ~~matters associated with~~ the ~~West~~Clean ~~Antelope~~Air IIAct, ~~LBA. Other~~and ~~potential~~this ~~large areas of unleased~~ coal ~~north~~is ~~and~~some ~~west~~ of the ~~mine~~lowest ~~are~~sulfur ~~available~~coal ~~for~~produced ~~nomination~~in bythe ~~us or other mining operations or persons~~PRB.

Cordero Rojo Mine

The Cordero Rojo mine is located approximately 25 miles south of Gillette, Wyoming. The mine extracts ~~steam~~thermal coal from the Wyodak Seam, which ranges from approximately 55 to 70 feet in thickness. We ~~have~~previously nominated as an LBA a large coal tract adjacent to our existing operation,. ~~which~~The weBLM ~~now~~divided ~~believe~~this ~~the~~LBA ~~BLM~~into ~~will~~two ~~schedule~~tracts, ~~for~~Maysdorf ~~lease~~II inNorth ~~2011~~and orMaysdorf ~~2012~~II South. The ~~BLM~~Maysdorf ~~will~~II ~~determine~~North ~~if the~~ tract ~~will~~was beoffered ~~leased,~~in August 2013 and ifno ~~so,~~bids ~~the~~were ~~final~~submitted. Our ~~boundaries~~decision not to bid was made in light of, current market conditions and access issues to the coal. The ~~tonnage~~BLM ~~for,~~is ~~this~~expecting to delay any future lease sale on the Maysdorf II South tract for up to two years due to current weak markets. Significant additional areas of unleased coal are potentially available for nomination by us or other mining operations or persons adjacent to our current operations. Based on the average sulfur content of 0.69 lbs SO2/mmBtu, the reserves at our Cordero Rojo mine are considered to be compliance coal under the Clean Air Act.

Table of Contents

Spring Creek Mine

The Spring Creek mine is located in Montana approximately 35 miles north of Sheridan, Wyoming. The mine extracts ~~steam~~thermal coal from the Anderson-Dietz Seam, which averages approximately 80 feet in thickness. The location of the mine relative to the Great Lakes is attractive to our customers in the northeast because of lower transportation costs. The location of the Spring Creek mine also provides access to export terminals in the Pacific ~~northwest~~Northwest, providing ana geographic advantage relative to other PRB mines. As a result, interest from foreign buyers in coal from our Spring Creek mine continues, and, in ~~2010~~2013, we shipped approximately 34.37 million tons of Spring Creek coal through ~~the~~terminals ~~Westshore~~located ~~terminal. In~~in ~~June 2010~~British Columbia, ~~we entered into a Modified Coal Lease (the “Lease Modification”) with the BLM~~Canada. ~~The~~We ~~Lease~~continue ~~Modification~~to ~~modified~~seek ~~Coal~~opportunities ~~Lease MTM-069782 (the “Existing Lease”) and added approximately 48 million tons of proven and probable reserves~~ to ~~the Existing Lease.~~increase

Table of Contents

our port capacity in the Pacific Northwest. Based on the average sulfur content of 0.73 lbs SO2/mmBtu, the reserves at our Spring Creek mine are considered to be compliance coal under the Clean Air Act.

Decker Mine

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

~~Customers~~For ~~and~~2014 ~~Coal~~deliveries, ~~Contracts~~Decker is currently planning to sell up to approximately 3.8 million tons, of which our 50% share would be 1.9 million tons. Some of these potential sales remain subject to entering definitive contracts.

WeAn ~~focus~~October 2013 onaudit ~~building~~report ~~long-term~~related ~~relationships~~to ~~with~~the ~~customers~~other ~~through~~50% ~~our~~owner’s ~~reliable~~ultimate ~~performance~~parent ~~and~~company ~~commitment~~stated tothat ~~customer~~if ~~service. We~~planned ~~supply~~funding ~~coal~~or toalternative ~~over~~sources ~~47 electric utilities and over 91%~~ of ~~our~~capital ~~sales~~are ~~were~~not toobtained, ~~customers~~there ~~with~~exists ana ~~investment~~material ~~grade~~uncertainty ~~credit~~whether ~~rating~~Ambre asEnergy ofLimited ~~December 31,~~and ~~2010. Furthermore,~~its ~~over~~controlled ~~72%~~entities ofwould ~~our~~be ~~2010~~able ~~sales were~~ to ~~customers~~continue ~~with~~as ~~whom~~a wegoing ~~have had relationships for more than 10 years~~concern.

~~Sales~~Development ~~and Marketing~~Projects

WeYoungs ~~have~~Creek ~~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:~~Project

~~· Sales~~The Youngs Creek project is a permitted but undeveloped surface mine project in the Northern PRB region located 13 miles north of Sheridan, Wyoming, contiguous with the Wyoming-Montana state line. The Youngs Creek project is approximately seven miles south of our Spring Creek mine and ~~Marketing~~seven miles from the mainline railroad, and is near the Crow project (described below). We acquired the Youngs Creek project in June 2012. The coal located at the Youngs Creek project is similar quality to that of our Spring Creek mine and offers lower sodium levels. The Youngs Creek project mining permit covers 287 million tons of non-reserve coal deposits, of which ~~focuses~~approximately 272 million tons benefit from a royalty rate of 8.0% of the coal sales price free on ~~traditional~~board ~~requests~~at ~~for~~the ~~proposals~~mine site, ~~constituting~~payable to the ~~majority~~sellers, which is below the normal 12.5% royalty rate payable on federal coal. We also control additional leased and private coal related to the Youngs Creek project that has not been evaluated and is not in any mine plan. We also acquired approximately 38,800 acres of surface rights which includes land extending north to our ~~sales;~~Spring Creek mine, onto the Crow Indian Reservation to the west, and abuts the Decker mine to the east. We are in the process of evaluating the development options for this project, and believe that its proximity to the Spring Creek mine and the Crow project represent an opportunity to optimize our mine developments in the Northern PRB region.

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

~~· Customer~~In ~~Service~~January 2013, we entered an Option Agreement and a corresponding Exploration Agreement with the Crow Tribe of Indians. These agreements were approved by the Department of the Interior on June 14, 2013. This coal project is located on the Crow Indian Reservation in southeast Montana, near our Spring Creek mine and Youngs Creek project in the Northern PRB region. We paid the Crow Tribe $3.75 million for the Option Agreement. We will make annual option payments throughout the term of the Option Agreement, which, ~~provides~~during ~~contract~~the initial option period could total up to $10 million. The Option and ~~after~~Exploration Agreements provide for exploration rights and exclusive options to lease three separate coal deposits on the Crow Indian Reservation over an initial five-year term, with two extension periods through 2035 if certain conditions are met. Upon the exercise of an option or options to lease, we would pay the Crow Tribe an amount equal to $0.08 per ton to $0.15 per ton, depending on the lease area and coal deposit and subject to adjustment for inflation. The agreements also set forth adjustable royalty rates, ranging from 7.5% to 15% of the coal sales ~~support~~price free on board at the mine site and contain standard coal production taxes to be paid to the Crow Tribe. The coal located at the Crow project is similar quality to that of our ~~customers~~Spring Creek mine and offers lower sodium levels. We are undertaking the exploration program and evaluating the development options for this project, and believe that its proximity to the Spring Creek mine and the Youngs Creek project represents an opportunity to optimize our mine developments in the Northern PRB region.

~~As of December 31, 2010, we had 17 employees in our sales and marketing department.~~6

Table of Contents

~~Customers~~The map below shows where the Youngs Creek project and Crow project are located relative to our Spring Creek mine.

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

We focus on building long-term relationships with customers through our reliable performance and commitment to customer service. We supply coal to 79 domestic and foreign electric utilities and over 81% of our sales were to customers with an investment grade credit rating as of December 31, 2013. Furthermore, over 79% of our 2013 sales were to customers with whom we have had relationships for more than 10 years. During 2013, approximately 44% of our consolidated revenue was derived from our top ten customers. No customer accounted for 10% or more of our total revenue in 2013. A significant portion of our revenue for the Logistics and Related Activities segment is derived from entities owned or controlled by Korea Electric Power Corporation. We believe we could make up the loss of any sales caused by the loss of one or more of these entities; however, we cannot guarantee that the prices we would receive from any replacement sales would be at a price as favorable as the original sales price.

The following map shows the percentage of our tons sold by state of destination during 2013 from coal produced at the three mines we own and operate. Our coal supplies fueled approximately 4% of the electricity generated in the U.S. in 2013. We also supplied approximately 6% of the tons produced at our mines to customers outside of the U.S. in 2013.

Table of Contents

We categorize our customers by how we sell coal to them. Our mine customers purchase coal directly from our mine sites, where the sale occurs at the mine site and where title and risk of loss pass to the customer at that point. Mine customers arrange for and bear the costs of transporting their coal from our mines to their plants or other specified discharge points. Our mine customers are typically domestic utility companies primarily located in the mid-west and south central U.S., although we also sell to other domestic utility companies, as well as to third-party brokers.

Our logistics customers purchase coal from us, along with our logistics services to deliver the coal to the customer at a terminal or the customer’s plant or other delivery point, remote from our mine site. Title and risk of loss pass to the customer at the remote delivery point. Our logistics services include the purchase of coal from third parties or from our owned and operated mines as well as the contracting and coordination of the transportation and other handling services from third-party operators — typically rail and terminal companies. Often these rail and terminal contracts involve significant take-or-pay commitments. Logistics customers are primarily foreign and domestic utility companies as well as third-party brokers. With respect to our international sales, at present, we are primarily focused on end-user customers; however a small portion of our sales are made to international traders who sell on to end-user customers. In 2013, we were the largest U.S. exporter of thermal coal into South Korea.

Mine Customers

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 mine customers. ~~Multiple~~Contracts year contracts usually have specific and possibly different volume and pricing arrangements for each year of the contract. As of December 31, 2010, approximately 64% of our committed tons were associated with ~~contracts that had three years or more remaining on their term. Most of~~ our ~~supply~~mine ~~contracts~~customers ~~include~~generally ahave ~~fixed~~terms ~~price for the term~~ of ~~the~~one ~~agreement~~to ~~or a pre-determined escalation in price for each year. Some of our agreements that extend for a four- or~~ five~~-year~~ ~~term~~years, oralthough ~~longer~~some ~~may~~are ~~include~~as ashort ~~variable~~as ~~pricing~~one ~~system. These contracts allow customers~~ to ~~secure~~six amonths ~~supply for their future needs~~ and ~~provide~~others usmay ~~with~~be ~~greater~~longer ~~predictability~~than often ~~sales volume and sales price~~years. For the year ended December 31, ~~2010~~2013, approximately 9783% of our ~~revenues~~total ~~were~~revenue attributable to our Owned and Operated Mines segment was derived from long-term supply contracts with a term of one year or greater~~. While~~ ~~most~~and approximately 55% of our ~~sales~~committed ~~contracts~~tons ~~are for terms of one~~ to ~~five~~mine ~~years,~~customers ~~some~~was ~~are~~associated aswith ~~short~~contracts asthat ~~one~~had tothree ~~six~~years ~~months,~~or ~~and~~more ~~other~~remaining ~~contracts~~on ~~have~~their ~~terms longer than 10 years~~term.

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.

13Our coal supply contracts typically contain “hardship” provisions to adjust the base price due to new statutes, ordinances or regulations that affect our costs related to performance of the agreement. Additionally, some of our contracts contain provisions that allow for the recovery of costs incurred as a result of modifications or changes in the interpretations or application of any applicable statute by local, state or federal government authorities. These provisions only apply to the base price of coal contained in these supply contracts. In some circumstances, a significant adjustment in base price can lead to termination of the contract. In addition, a small number of our contracts contain clauses that may allow customers to terminate the contract in the event of significant changes in environmental laws and regulations which result in the customer being unable to perform under the terms of the contract.

Most of our coal supply contracts to mine customers include a fixed price for the term of the agreement or a pre-determined escalation in price for each year. Some of these contracts that extend for a four- or five-year term or longer may include variable pricing. These price re-opener and index provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on prevailing market price or, in some instances, require us to negotiate a new price, sometimes between a specified range of prices. In some agreements, 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.

Quality and volumes for the coal are stipulated in coal supply contracts. Some customers are allowed to vary the amount of coal taken under the contract. Most of our coal supply contracts contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics, such as heat content, sulfur, ash and ash fusion temperature. Our contracts also typically attempt to account for the low sulfur content of our coal by reflecting a market adjustment for the low sulfur in the contract price or through an adjustment calculated based on the as-

Table of Contents

~~Our~~delivered ~~supply~~average ~~contracts~~sulfur ~~typically~~content ~~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~~coal, ~~state~~ or ~~federal government authorities~~both. ~~These~~Failure ~~provisions only apply~~ to ~~the~~meet ~~base~~these ~~price~~specifications ofcan ~~coal~~result ~~contained~~ in ~~these~~economic ~~supply contracts. In some circumstances~~penalties, asuspension ~~significant~~or ~~adjustment~~cancellation inof ~~base~~shipments ~~price~~or ~~can lead to~~ termination of the ~~contract~~contracts.

~~Price~~Contracts ~~re-opener~~with ~~and~~our ~~index~~mine ~~provisions,~~customers ~~which~~also ~~can~~typically becontain ~~either~~force ~~renegotiated~~majeure orprovisions ~~based~~allowing ontemporary asuspension ~~fixed~~of ~~formula,~~performance ~~are~~by ~~present~~us inor ~~certain~~our ~~contracts~~customers ~~covering~~for ~~future~~the ~~tonnage~~duration ~~commitments. These~~of ~~provisions~~specified ~~may~~events ~~allow~~beyond ~~either~~the control of the affected party, toincluding ~~commence~~events asuch ~~renegotiation~~as ofstrikes, ~~the~~adverse ~~contract~~mining ~~price~~conditions, atmine aclosures ~~pre-determined~~or ~~time. Price~~serious ~~re-opener~~transportation ~~provisions~~problems ~~may~~that ~~automatically~~affect ~~set~~us aor ~~new~~unanticipated ~~price~~plant ~~based~~outages onthat ~~prevailing~~may ~~market~~affect ~~price~~the ~~or,~~buyer. These incontracts ~~some~~generally ~~instances,~~provide ~~require~~that usin tothe ~~negotiate~~event a ~~new~~force ~~price,~~majeure ~~sometimes~~circumstance ~~between~~exceeds a ~~specified~~certain ~~range~~time ofperiod ~~prices~~(e. Ing., ~~some~~60-90 ~~agreements~~days), if the ~~parties~~unaffected doparty ~~not~~may ~~agree~~have onthe aoption ~~new~~to ~~price,~~terminate ~~either~~the ~~party~~transaction ~~has~~or antransactions ~~option~~under ~~to terminate~~ the ~~contract~~agreement. ~~Under~~Some ~~some~~ of ~~our~~those contracts, westipulate ~~have~~that ~~the~~this ~~right~~tonnage tocan ~~match~~be ~~lower~~made ~~prices~~up ~~offered~~by tomutual ~~our~~agreement ~~customers~~or byat ~~other~~the ~~suppliers~~discretion of the buyer. ~~In addition~~Generally, ~~some~~contracts ofwith our ~~contracts~~mine ~~contain~~customers ~~clauses~~allow our customers to suspend performance in the event that ~~may~~the ~~allow~~railroad ~~customers~~fails to ~~terminate~~provide ~~the~~its ~~contract~~services indue to circumstances that would constitute a force majeure under the ~~event~~terms of ~~certain~~the ~~changes~~contract inbetween ~~environmental~~the ~~laws~~Mine Customer and ~~regulations~~the railroad.

~~Quality~~Many ~~and~~of ~~volumes~~our ~~for~~contracts ~~the~~contain ~~coal~~clauses ~~are~~that ~~stipulated~~require inus ~~coal sales agreements. In most cases, the annual pricing~~ and ~~volume~~our ~~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~~maintain ~~the~~a ~~amount~~certain oflevel ~~coal taken under the contract. Most~~ of ~~our~~creditworthiness ~~coal~~or ~~sales~~provide ~~agreements~~appropriate ~~contain~~credit ~~provisions~~enhancement ~~requiring~~upon ~~us to deliver coal within certain ranges for specific coal characteristics, such as heat content, sulfur, ash and ash fusion temperature~~request. ~~Failure~~The failure to ~~meet~~do ~~these~~so ~~specifications~~ can result in ~~economic~~a ~~penalties,~~ suspension ~~or cancellation~~ of shipments orunder ~~termination of~~ the ~~contracts~~contract. ~~Many~~In some of our contracts, ~~contain~~we ~~clauses~~have ~~that~~a ~~require~~right usof ~~and~~substitution, ~~our~~allowing ~~customers~~us to ~~maintain~~provide acoal ~~certain~~from ~~level~~different ofmines, ~~creditworthiness~~including orthird-party ~~provide~~mines, ~~appropriate~~as ~~credit~~long ~~enhancement~~as ~~upon~~the ~~request. The~~replacement ~~failure~~coal tomeets doquality sospecifications ~~can~~and ~~result~~will inbe asold ~~suspension~~at ofthe ~~shipments~~same ~~under~~delivered ~~the contract~~cost.

~~Our~~Generally, ~~coal~~under ~~sales~~the ~~agreements~~terms ~~also~~of ~~typically~~our ~~contain~~coal ~~force~~supply ~~majeure~~contracts, ~~provisions~~we ~~allowing~~agree ~~temporary~~to ~~suspension~~indemnify ~~of performance by us~~ or reimburse our customers for ~~the~~damage ~~duration~~to oftheir ~~specified~~or ~~events~~their ~~beyond~~rail ~~the~~carrier’s ~~control~~equipment ofwhile ~~the~~on ~~affected~~our ~~party~~property, ~~including~~other ~~events~~than ~~such~~from astheir ~~strikes,~~own ~~adverse mining conditions~~negligence, ~~mine~~and ~~closures~~for ordamage ~~serious~~to ~~transportation~~our ~~problems~~customers’ ~~that~~equipment ~~affect~~due usto ~~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~~non-90coal ~~days),~~materials ~~the~~being ~~unaffected~~included ~~party~~with ~~may~~our ~~have~~coal ~~the~~before ~~option~~leaving toour ~~terminate the transaction or transactions under the agreement~~property. ~~Some contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer.~~

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

InTransportation ~~some~~can be one of ~~our~~the ~~contracts,~~largest wecomponents ~~have~~of a ~~right~~purchaser’s oftotal ~~substitution,~~cost. Coal ~~allowing~~used usfor todomestic ~~provide~~consumption ~~coal~~by ~~from~~our ~~different~~mine ~~mines,~~customers ~~including~~is ~~third-party~~sold ~~mines,~~free ason ~~long~~board as(“FOB”) at the ~~replacement~~mine or nearest loading facility, and the purchaser of the coal ~~meets~~bears ~~quality~~the ~~specifications~~transportation costs and ~~will~~risk beof ~~sold~~loss. Most atelectric generators arrange long-term shipping contracts with rail or barge companies to assure stable delivery costs. Our mines (including the ~~same~~Decker ~~delivered~~mine) ~~cost~~are served by the BNSF and/or UP railways.

~~Generally,~~Although ~~under~~ the ~~terms~~purchaser ofpays ~~our~~the ~~coal sales agreements~~freight, wetransportation ~~agree~~costs tostill ~~indemnify~~are orimportant ~~reimburse~~to ~~our~~coal ~~customers~~mining ~~for~~companies ~~damage~~because tothe ~~their~~purchaser orwill ~~their~~consider ~~rail~~the ~~carrier’s~~delivered ~~equipment~~cost ~~while~~of oncoal, ~~our~~including ~~property~~transportation costs, ~~other~~in ~~than~~determining from ~~their~~which ~~own~~mines ~~negligence,~~it ~~and~~will ~~for~~purchase. Transportation ~~damage~~costs toborne ~~our~~by the customer’s ~~equipment~~vary ~~due~~greatly tobased ~~non-coal~~on ~~materials~~each ~~being~~customer’s ~~included~~proximity ~~with~~to ~~our~~the ~~coal before leaving our property~~mine.

Logistics Customers

Long-term Coal Sales Agreements

We generally enter into fixed price, fixed volume supply contracts with our logistics customers. Contracts with our logistics customers generally have terms of one to three years. The terms of our 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, logistics and coal quality requirements, quantity parameters, permitted sources of supply, impact of future regulatory changes, extension options, force majeure, termination, assignment and other provisions.

Many of our international contracts with logistics customers contain evergreen clauses and a combination of annual, semi-annual, or quarterly pricing negotiations consistent with conventional industry standards for the Asian Pacific region. Our Asian delivered sales are priced broadly in line with a number of relevant international coal indices adjusted for energy content and other quality and delivery criteria. These indices include the Newcastle benchmark price, which is an established index for high Btu Australian thermal coal available to be loaded on a vessel at a coal terminal near Newcastle, north of Sydney. Based on the comparative quality and transport costs, our delivered sales are generally priced at approximately 60% to 70% of the forward Newcastle price.

In addition to containing the similar terms as those described for our mine customers above, contracts with our logistics customers also may include terms relating to:

Table of Contents

· demurrage fees for international contracts, charged to us when a vessel is not dispatched on time;

· fixed pricing for the first year of sales, and a provision providing for future years’ pricing to be negotiated at a specific point in time related to some of our foreign contracts; and

· additional coal quality requirements, such as grindability, which deals with the hardness of the coal, and ash fusion temperature, which measures the softening and melting behavior of the ash contained in the coal.

Transportation and Logistics Services

For our logistics customers, we provide a variety of services designed to facilitate the sale and delivery of coal. These services include the purchase of coal from third parties or from our owned and operated mines, coordination of the transportation and delivery of purchased coal, negotiation of take-or-pay rail agreements and take-or-pay terminal agreements and demurrage settlement with vessel operators. We also bear the costs of transporting the coal to the delivery point. For our international customers, this includes export terminals located in the Pacific Northwest, which can be over 2,600 miles from our mines and involve transporting over three different railroads. Our logistics customers located overseas are generally responsible for paying the cost of ocean freight, although occasionally we may arrange that transportation as well.

We have an unaffiliated Korean representative company, WoonBong Energy, which helps us facilitate our sales in South Korea. WoonBong Energy provides market research on Korean coal markets, acts as an intermediary for communications with our Korean customers and assists with logistics issues in sales to Korean customers. WoonBong Energy provides these services exclusively for us in South Korea.

To help support and ensure export terminal capacity for a portion of our anticipated export sales, from time to time we enter into long-term throughput agreements with export terminal companies and railroads. These types of take-or-pay agreements require us to pay for a minimum quantity of coal to be transported on the railway or through the terminal regardless of whether we sell any coal. If we fail to acquire sufficient export sales to meet our minimum obligations under the take-or-pay agreements, we are still obligated to make payments to the export terminal company or railroad. In 2011, we entered into a long-term throughput contract with Westshore Terminals Limited Partnership that expires in 2023 for a portion of our anticipated export sales through their export terminal in Vancouver, British Columbia. Also, in February 2013, we announced a throughput option agreement with SSA Marine that provides us with an option for up to 16 million tonnes of capacity per year through the planned dry bulk cargo Gateway Pacific Terminal at Cherry Point in the State of Washington. This agreement requires us to make annual option payments, aggregating up to a maximum of $16 million over a five-year period. The initial shipping term is 10 years with an option to enter into two five-year extension terms. Our potential share of capacity will depend upon the ultimate capacity of the terminal and is subject to the terms of the option agreement. The terminal would accommodate cape size vessels. Our option is exercisable following the successful completion of the ongoing permit process for the terminal, which is uncertain. We also continue to explore other Pacific Northwest terminal opportunities as part of our efforts to grow our export sales.

Also included in the costs within our Logistics and Related Activities segment are fees to cover rail and export terminal charges, as well as fees to cover capital costs and investments that we incur to enable us to provide logistics services to our logistics customers, such as the purchase or lease of rail cars.

Broker Sales and Third-Party Sources

From time to time, we purchase coal through brokers and sell to ~~cover~~brokers and third-party sources any ~~shortfalls~~excess ~~under~~produced ~~our~~coal, ~~supply~~including ~~agreements~~selling ~~and~~to brokers who sell to end users in foreign countries. For delivery during the year ended December 31, 2013, we purchased 1.5 million tons through brokers ~~any~~and ~~excess~~third-party ~~produced~~sources, ~~coal~~and sold 1.5 million tons to brokers and third-party sources.

~~Our~~Sales subsidiary, Spring Creek Coal LLC, was a party to a broker sales contract under which it had agreed to sell purchased coal to a wholesale power generation company. In 1978, our Spring Creek subsidiary entered into a long-term coal sales contract to underpin the establishment of the Spring Creek mine. When we acquired the Spring Creek mine in 1993, the contract had been amended to allow the mine to meet its delivery requirements from long-term purchase contracts entered into with two separate mines (one of which was the Jacobs Ranch mine which we subsequently acquired in 1998 and ~~sold in 2009). Due to the nature of the broker sales contract and the market conditions at the time the respective agreements~~Marketing

14We have a team of experienced sales, marketing and customer service personnel. To help develop and maintain the relationships we have with our mine and logistics customers, we have divided the department into teams consisting of:

Table of Contents

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

~~For~~· Customer ~~delivery during the year ended December 31~~Service, ~~2010,~~which weprovides ~~purchased~~contract ~~1.7~~and ~~million~~after-sales ~~tons~~support ~~through~~to ~~brokers~~our ~~and third-party sources.~~customers;

~~Transportation~~· Logistics and Industrial Sales, which focuses on logistics, transportation and related services on behalf of our Logistics and Related Activities segment;

~~Transportation~~· Trading ~~can~~and beRevenue ~~one~~Management, ofwhich ~~the~~provides ~~largest~~industry ~~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~~insight, ~~and~~recommends ~~the~~pricing ~~purchaser~~strategies ~~of the coal normally bears the transportation costs~~ and ~~risk~~participates ~~of loss~~ in the ~~event~~spot ~~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 UPforward ~~railways. In~~markets; ~~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.~~

· Export Sales, which focuses on sales to our international logistics customers.

As of December 31, 2013, we had 23 employees in our sales and marketing department.

Suppliers

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

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

Competition

The coal industry is highly competitive. See Item 1A “Risk Factors—Risks Related to Our Business and Industry—Competition with domestic and foreign coal producers and with producers of natural gas and other competing energy sources may negatively affect our sales volumes and our ability to sell coal at a favorable price.” We compete directly with all coal producers and indirectly with other energy producers throughout the U.S. and, for our export sales, internationally. The most important factors on which we compete with other coal producers are coal price, coal quality and characteristics, costs ~~incurred by our customers~~ to transport the coal, customer service and the reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic and foreign electric generation ~~industry and international consumers~~industries. These coal consumption patterns are influenced by factors beyond our control, including the supply and demand for domestic and foreign electricity, domestic and foreign governmental regulations and taxes, environmental and other regulatory changes, technological developments, the price and availability of other fuels, such as natural gas and crude oil, ~~and~~ the availability of subsidies, and ~~subsidies~~renewable mandates designed to encourage greater use of, alternative energy sources, including hydroelectric, nuclear, wind and solar power, and currency exchange rate fluctuations, all of which can decrease demand for thermal coal or may decrease demand for PRB coal compared to other global coal basins.

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

Employees

As of December 31, ~~2010~~2013, we had approximately 1,~~524~~700 full-time employees. None of our employees are currently parties to collective bargaining agreements. We believe that we have good relations with our employees. We hold a 50% non-operating interest in the Decker mine in Montana, which is a union-based operation ~~operated by a third-party mine operator~~. ~~However,~~We we do not employ any of the Decker mine employees. WeAs ~~believe~~of ~~that~~December 31, 2013, we had 259 external contractors on a full-time, equivalent basis.

1511

Table of Contents

weExecutive ~~have good relations with our employees. As of December 31, 2010, we had 250 external contractors, on a full-time equivalent basis.~~Officers

~~Executive~~Set ~~Officers~~forth below is information concerning our current executive officers as of ~~the~~December 31, ~~Company~~2013.

Set forth below is information concerning our current executive officers.

Name	Age	Position(s)
Colin Marshall	49	President, Chief Executive Officer and Director
Michael Barrett	44	Executive Vice President and Chief Financial Officer
Gary Rivenes	43	Executive Vice President and Chief Operating Officer
Bruce Jones	55	Senior Vice President, Technical Services
Cary Martin	61	Senior Vice President, Human Resources
Todd Myers	49	Senior Vice President, Business Development
James Orchard	53	Senior Vice President, Marketing and Government Affairs
Bryan Pechersky	43	Senior Vice President, General Counsel and Corporate Secretary
Heath Hill	43	Vice President and Chief Accounting Officer

Name	Age	Position(s)
Colin Marshall	46	President, Chief Executive Officer and Director
Michael Barrett	42	Executive Vice President and Chief Financial Officer
Gary Rivenes	40	Executive Vice President and Chief Operating Officer
Cary Martin	58	Senior Vice President, Human Resources
Todd Myers	47	Senior Vice President, Business Development
James Orchard	50	Senior Vice President, Marketing and Government Affairs
Bryan Pechersky	40	Senior Vice President and General Counsel
A. Nick Taylor	60	Senior Vice President, Technical Services
Heath Hill	40	Vice President and Chief Accounting Officer

Colin Marshall has served as our President, Chief Executive Officer and a director since July 2008. Previously, he served as the President and Chief Executive Officer of Rio Tinto Energy America Inc. (“RTEA”), an indirect subsidiary of Rio Tinto plc and the former parent company of Cloud Peak Energy Resources LLC (“CPE Resources”), the company’s wholly-owned subsidiary, from June 2006 until November 2009. In this Proxy Statement, references to “Rio Tinto” refer to Rio Tinto plc and Rio Tinto Limited and their subsidiaries, collectively. Rio Tinto plc is the ultimate parent company of RTEA. From March 2004 to May 2006, Mr. Marshall served as General Manager of Rio Tinto’s Pilbara Iron’s west Pilbara iron ore operations in Tom Price, West Australia, from June 2001 to March 2004, he served as General Manager of RTEA’s Cordero Rojo mine in Wyoming, and from August 2000 to June 2001, he served as Operations Manager of RTEA’s Cordero Rojo mine. Mr. Marshall worked for Rio Tinto plc in London as an analyst in the Business Evaluation Department from 1992 to 1996. From 1996 to 2000, he was Finance Director of the Rio Tinto Pacific Coal business unit based in Brisbane Australia. Mr. Marshall holds a Bachelor of Engineering degree and a Master’s degree in mechanical engineering from Brunel University and a Master of Business Administration from the London Business School.

~~Colin~~Michael ~~Marshall~~Barrett has served as our ~~President, Chief~~ Executive ~~Officer~~Vice President and aChief ~~director~~Financial Officer since ~~July~~September 2008. Previously, he served as ~~the President and~~ Chief ~~Executive~~Financial Officer of ~~Rio~~RTEA ~~Tinto~~from ~~Energy~~April 2007 ~~America~~until ~~Inc. (“RTEA”)~~November 2009, ~~an indirect subsidiary of Rio Tinto plc~~ and ~~the~~as ~~former~~Acting ~~parent~~Chief ~~company~~Financial Officer of ~~Cloud~~RTEA ~~Peak Energy Resources LLC,~~ from ~~June~~January ~~2006~~2007 ~~until~~to ~~November~~March ~~2009~~2007. From ~~March~~November 2004 to ~~May~~April ~~2006~~2007, Mr. ~~Marshall~~Barrett served as ~~General~~Director, ~~Manager~~Finance & ofCommercial ~~Rio~~Analysis ~~Tinto’s~~of ~~Pilbara Iron’s west Pilbara iron ore operations in Tom Price~~RTEA, ~~West~~and ~~Australia,~~ from ~~June~~December 2001 to ~~March~~November 2004, he served as ~~General~~Principal ~~Manager~~Business Analyst of ~~RTEA’s~~Rio ~~Cordero~~Tinto ~~Rojo~~Iron ~~mine~~Ore’s innew ~~Wyoming~~business ~~and~~development ~~from~~group. ~~August~~From May ~~2000~~1997 to ~~June~~May ~~2001~~2000, heMr. Barrett ~~served~~worked as ~~Operations~~a ~~Manager~~Senior ofBusiness ~~RTEA’s~~Analyst ~~Cordero~~for ~~Rojo~~WMC ~~mine. Mr.~~Resources ~~Marshall~~Ltd, ~~worked~~a ~~for~~mining ~~Rio~~company, ~~Tinto~~and ~~plc~~was inChief ~~London~~Financial asOfficer anand ~~analyst~~Finance inDirector ~~the~~of ~~Business~~Medtech Ltd. ~~Evaluation~~and ~~Department~~Auxcis Ltd., ~~from~~two ~~1992~~technology tocompanies ~~1996. From~~listed ~~1996~~on tothe ~~2000~~Australian stock exchange, hefrom ~~was~~May 2000 ~~Finance~~to ~~Director~~December 2001. ofFrom ~~the~~August 1991 ~~Rio~~to ~~Tinto~~May 1997, ~~Pacific~~he ~~Coal~~held ~~business~~positions ~~unit~~with ~~based~~PricewaterhouseCoopers in ~~Brisbane~~England and Australia. Mr. ~~Marshall~~Barrett received his ~~bachelor~~Bachelor’s ~~of engineering~~ degree ~~and~~with ~~his~~joint ~~master’s~~honors ~~degree~~ in ~~mechanical~~economics ~~engineering~~and accounting from ~~Brunel~~Southampton University and ~~his~~is ~~master~~a ofchartered ~~business administration from the London Business School~~accountant.

~~Michael~~Gary ~~Barrett~~Rivenes has served as our Executive Vice President and Chief ~~Financial~~Operating Officer since ~~September~~October ~~2008~~2009. Previously, he served as ~~Chief~~Vice ~~Financial~~President, ~~Officer~~Operations, of RTEA from ~~April~~December ~~2007~~2008 until November 2009, and as Acting ~~Chief~~Vice ~~Financial~~President, ~~Officer~~Operations, of RTEA from January ~~2007~~2008 to ~~March~~November ~~2007~~2008. From ~~November~~September ~~2004~~2007 to ~~April~~December 2007, Mr. ~~Barrett~~Rivenes served as ~~Director,~~General ~~Finance &~~Manager ~~Commercial~~for ~~Analysis~~RTEA’s ofJacobs ~~RTEA~~Ranch mine, ~~and~~ from ~~December~~October ~~2001~~2006 to ~~November~~September ~~2004~~2007, he served as ~~Principal~~General ~~Business~~Manager ~~Analyst~~for ~~of Rio Tinto Iron Ore~~RTEA’s ~~new~~Antelope ~~business~~mine ~~development~~and ~~group. From~~from ~~May~~November ~~1997~~2003 to ~~May~~September ~~2000~~2006, ~~Mr. Barrett~~he ~~worked~~served as aManager, ~~Senior~~Mine ~~Business~~Operations ~~Analyst~~ for ~~WMC~~RTEA’s ~~Resources~~Antelope ~~Ltd,~~mine. aPrior ~~mining~~to ~~company~~that, ~~and~~he ~~was~~worked ~~Chief~~for ~~Financial~~RTEA ~~Officer~~in ~~and~~a ~~Finance~~variety ~~Director~~ of ~~Medtech~~operational ~~Ltd.~~ and ~~Auxcis~~technical ~~Ltd.,~~positions ~~two~~for ~~technology~~RTEA’s ~~companies listed on the Australian stock exchange~~Antelope, ~~from~~Colowyo ~~May 2000~~and toJacobs ~~December 2001. From~~Ranch ~~August 1991~~mines tosince ~~May 1997, he held positions with PricewaterhouseCoopers in England and Australia~~1992. Mr. ~~Barrett~~Rivenes ~~received~~holds ~~his~~a ~~bachelor’s~~Bachelor ~~degree~~of ~~with~~Science ~~joint honors~~ in ~~economics~~mining ~~and~~engineering ~~accounting~~ from ~~Southampton~~Montana ~~University~~College ~~and~~of isMineral, aScience & ~~Chartered Accountant~~Technology.

~~Gary~~Bruce ~~Rivenes~~Jones has served as our ~~Executive~~Senior Vice President, ~~and~~Technical ~~Chief~~Services ~~Operating Officer~~ since ~~October~~July ~~2009~~2013. ~~Previously,~~ hePrior ~~served~~to his appointment as Senior Vice President, ~~Operations, of RTEA from December~~Mr. ~~2008~~Jones ~~until~~was ~~November 2009,~~General ~~and~~Manager ~~as Acting Vice President, Operations,~~ of ~~RTEA~~our ~~from~~Spring ~~January 2008~~Creek ~~to November 2008~~Mine. ~~From~~ ~~September 2007~~He tobegan ~~December 2007,~~his ~~Mr. Rivenes~~career ~~served~~ as ~~General~~a ~~Manager~~mining engineer for ~~RTEA’s~~Inspiration ~~Jacobs Ranch mine~~Coal, ~~from October~~ ~~2006~~Inc. toin ~~September 2007~~Price, heKentucky ~~served~~and, asover ~~General~~the ~~Manager~~past ~~for~~thirty-two ~~RTEA’s~~years, ~~Antelope~~has ~~mine~~held ~~and~~such ~~from~~positions ~~November 2003~~as toMine ~~September 2006~~Foreman, heMaintenance ~~served as~~ Manager, ~~Mine~~Environmental ~~Operations~~Engineer ~~for~~and ~~RTEA’s~~Process ~~Antelope mine~~Supervisor. ~~Prior~~ toBefore ~~that,~~coming heto ~~worked~~Spring ~~for~~Creek ~~RTEA~~Mine, inMr. Jones awas ~~variety~~the ofOperations ~~operational~~Manager ~~and~~for ~~technical~~Kennecott ~~positions~~Utah ~~for~~Copper ~~RTEA’s~~at ~~Antelope,~~the ~~Colowyo~~Bingham ~~and~~Canyon ~~Jacobs~~Mine ~~Ranch~~in ~~mines~~Bingham ~~since~~Canyon, ~~1992~~Utah. Mr. ~~Rivenes~~Jones holds a ~~bachelor~~Bachelor of ~~science~~Science degree in mining engineering from ~~Montana College of Mineral, Science & Technology.~~

Cary Martin has served as our Senior Vice President of Human Resources since October 2009. Previously, he served as Vice President / Corporate Officer of Human Resources for OGE Energy Corp., an electric utility and natural gas processing holding company from September 2006 until March 2008, and as a Segment Vice President for several different divisions of SPX Corporation, an international multi-industry manufacturing and services company from December 199912

Table of Contents

~~until~~the ~~May 2006. In~~University ~~these capacities, Mr. Martin’s responsibilities included oversight~~ of ~~employee and labor relations~~Wisconsin-Platteville, ~~workforce planning, employee development, compensation administration, policies and procedures and other responsibilities that are common for~~ a ~~human~~Master ~~resources~~of executive. From 1982 until 1999, Mr. Martin served in various management and officer positions for industries ranging from medical facilities to cable manufacturers. Mr. Martin received his bachelor’s degree in Business Administration from the University of ~~Missouri~~Utah, and ~~his~~is ~~master’s~~a ~~degree~~registered inprofessional ~~Management~~engineer ~~Sciences~~in ~~from~~Kentucky ~~St. Louis~~and ~~University~~Utah.

~~Todd~~Cary ~~Myers~~Martin has served as our Senior Vice President, ~~Business~~Human ~~Development~~Resources since ~~July~~October ~~2010~~2009. Previously, he served as Vice President / Corporate Officer of ~~Westmoreland~~Human ~~Coal~~Resources ~~Sales~~for ~~Company. Prior~~OGE toEnergy ~~that~~Corp., ~~Mr.~~an electric utility and natural gas processing holding company from September ~~Myers~~2006 ~~served~~until inMarch 2008, ~~other~~and ~~senior~~as ~~leadership~~a ~~positions~~Segment ~~with~~Vice ~~Westmoreland~~President ~~Coal~~for ~~Sales~~several ~~Company~~different indivisions ~~marketing~~of ~~and~~SPX ~~business~~Corporation, ~~development~~an ~~during~~international ~~two~~multi-industry ~~periods~~manufacturing ~~dating~~and toservices ~~1989. In~~company ~~his~~from ~~various~~December 1999 ~~capacities~~until ~~with~~May 2006. ~~Westmoreland~~In these capacities, Mr. ~~Myers~~Martin’s responsibilities included ~~developing~~oversight ~~and~~of ~~implementing~~employee ~~corporate~~and ~~merger~~labor ~~and~~relations, ~~acquisition~~workforce ~~strategies~~planning, ~~divesting~~employee ~~coal~~development, ~~related~~compensation ~~assets~~administration, ~~negotiating~~policies ~~complex~~and ~~transactions~~procedures and other responsibilities ~~generally~~that ~~attributable~~are tocommon ~~the~~for ~~management~~a ofhuman ~~coal~~resources ~~businesses~~executive. ~~Mr. Myers~~ ~~also~~From ~~spent~~1982 ~~five~~until ~~years with RDI Consulting~~1999, aMr. Martin ~~leading~~served ~~consulting firm~~ in ~~the~~various ~~energy~~management ~~industry, where he led the energy~~ and ~~environment~~officer ~~consulting~~positions ~~practice. In~~for ~~1987,~~industries ~~Mr. Myers~~ranging ~~served~~from asmedical afacilities ~~staff~~to ~~assistant~~cable ~~in the U~~manufacturers.S. ~~House of Representatives.~~ Mr. ~~Myers~~Martin ~~earned~~received his ~~bachelor~~Bachelor’s ofdegree ~~arts~~ in ~~political~~business ~~science~~administration from ~~Pennsylvania~~the ~~State~~ University inof ~~University~~Missouri ~~Park, Pennsylvania,~~ and his ~~masters~~Master’s degree in ~~international~~ management sciences from ~~the~~St. Louis ~~Thunderbird Graduate School of Global Management in Glendale, Arizona~~University.

~~James~~Todd ~~Orchard~~Myers has served as our Senior Vice President, ~~Marketing~~Business ~~and~~Development ~~Government Affairs~~ since ~~October~~July ~~2009~~2010. Previously, he served as ~~Vice~~ President of Westmoreland Coal Sales Company. Prior to that, ~~Marketing~~Mr. Myers served in other senior leadership positions with Westmoreland Coal Company in marketing and ~~Sustainable~~business ~~Development~~development ~~for~~during ~~RTEA~~two ~~from~~periods ~~March 2008~~dating ~~until~~to ~~November 2009~~1989. ~~From~~ ~~January 2005~~In tohis ~~March 2008~~various capacities with Westmoreland, Mr. ~~Orchard~~Myers’s ~~was~~responsibilities ~~Director~~included ofdeveloping ~~Customer~~and ~~Service~~implementing ~~for~~corporate ~~RTEA. Prior~~merger toand ~~that~~acquisition hestrategies, ~~worked~~divesting ~~for~~coal ~~Rio~~related ~~Tinto’s~~assets, ~~Aluminum~~negotiating ~~division~~complex intransactions ~~Australia~~ and ~~New~~other ~~Zealand~~responsibilities ~~for~~generally ~~over~~attributable 17to the management of coal businesses. Mr. Myers also spent five years, ~~where~~with heRDI ~~held~~Consulting, a ~~number~~leading ofconsulting ~~technical,~~firm ~~operating~~in the energy industry, ~~process~~where ~~improvement~~he led the energy and ~~marketing~~environment ~~positions~~consulting practice. In 1987, ~~including~~Mr. Myers served as ~~manager~~a ofstaff ~~Metal~~assistant ~~Products~~in ~~from~~the ~~January 2001~~U.S. toHouse ~~January 2005~~of Representatives. Mr. ~~Orchard~~Myers ~~graduated~~earned his Bachelor of Arts in political science from ~~the~~Pennsylvania State University ofin ~~New~~University ~~South~~Park, ~~Wales~~Pennsylvania, ~~with~~and ahis ~~bachelor~~Master’s ofdegree ~~science~~in ~~and~~international amanagement ~~PhD~~from the Thunderbird Graduate School of Global Management in ~~industrial~~Glendale, ~~chemistry~~Arizona.

~~Bryan~~James ~~Pechersky~~Orchard has served as our Senior Vice President, Marketing and ~~General~~Government ~~Counsel~~Affairs since ~~January~~October ~~2010~~2009. Previously, ~~Mr. Pechersky~~he ~~was~~served ~~Senior~~as Vice President, ~~General~~Marketing ~~Counsel~~ and ~~Secretary~~Sustainable Development for ~~Harte-Hanks, Inc.,~~RTEA ~~a worldwide, direct and targeted marketing company~~ from March ~~2007~~2008 tountil ~~January~~November ~~2010~~2009. ~~Prior~~ toFrom ~~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~~January 2005 to March ~~2007~~2008, ~~and~~Mr. Orchard was ~~Deputy~~Director ~~General~~of ~~Counsel~~Customer ~~and~~Service ~~Secretary~~ for ~~Unocal~~RTEA. ~~Corporation,~~Prior anto ~~international~~that ~~energy~~he ~~company~~worked ~~acquired~~for byRio ~~Chevron~~Tinto’s ~~Corporation~~Aluminum division in ~~2005,~~Australia ~~from~~and ~~March 2004~~New ~~until~~Zealand ~~October 2005. While~~for inover ~~these capacities~~17 years, ~~Mr. Pechersky’s~~where ~~responsibilities~~he ~~included~~held ~~advising~~a ~~corporate~~number ~~clients~~of ~~regarding various legal~~technical, ~~regulatory and compliance matters~~operating, ~~transactions~~process ~~and~~improvement ~~other responsibilities that are common for a general counsel~~ and ~~corporate~~marketing ~~secretary. Mr. Pechersky~~positions, ~~was~~including inas ~~private~~manager ~~practice~~of ~~for~~Metal ~~approximately~~Products ~~seven~~from ~~years with the international law firm Vinson~~January &2001 ~~Elkins~~to ~~LLP before joining Unocal Corporation~~January 2005. Mr. ~~Pechersky~~Orchard ~~also~~graduated ~~served~~from ~~as a Law Clerk to~~ the ~~Hon. Loretta~~University ~~A. Preska, Chief Judge~~ of ~~the~~New ~~U.S.~~South ~~District~~Wales ~~Court~~with ~~for~~a ~~the~~Bachelor ~~Southern District~~ of ~~New~~Science ~~York in 1995~~ and ~~1996. Mr. Pechersky~~a ~~earned~~PhD ~~his~~in ~~bachelor’s~~industrial ~~degree and Juris Doctorate from the University of Texas, Austin, Texas~~chemistry.

A.Bryan ~~Nick~~Pechersky ~~Taylor~~ has served as our Senior Vice President, ~~Technical~~and ~~Services~~General Counsel since ~~October~~January ~~2009~~2010 and our Corporate Secretary since March 2013. Previously, heMr. Pechersky ~~served~~was asSenior ~~RTEA’s~~ Vice President, ofGeneral ~~Technical~~Counsel ~~Services~~and Secretary for Harte-Hanks, &Inc., ~~Business~~a ~~Improvement~~worldwide, ~~Process~~direct and targeted marketing company from ~~October~~March ~~2005~~2007 ~~until~~to ~~November~~January ~~2009~~2010. Prior to that, ~~Mr. Taylor~~he ~~worked~~also ~~for~~served ~~Rio~~as ~~Tinto~~Senior ~~Technical~~Vice ~~Services~~President, inSecretary ~~Sydney~~and ~~providing~~Senior ~~advice~~Corporate toCounsel ~~Rio~~for ~~Tinto~~Blockbuster Inc., ~~mining~~a ~~operations~~global ~~worldwide~~movie and game entertainment retailer from ~~1992~~October 2005 to ~~2005~~March 2007, atand ~~its~~was ~~Bougainville~~Deputy ~~Copper~~General ~~operations~~Counsel inand ~~New~~Secretary ~~Guinea~~for ~~from~~Unocal ~~1980~~Corporation, toan ~~1981,~~international ~~and~~energy atcompany ~~its~~acquired ~~Rossing~~by ~~Uranium~~Chevron ~~operations~~Corporation in ~~Namibia~~2005, from ~~1976~~March 2004 tountil ~~1980~~October 2005. ~~Additionally,~~ heWhile ~~worked~~in ~~for~~these ~~Nchanga~~capacities, ~~Consolidated~~Mr. Pechersky’s ~~Copper~~responsibilities ~~Mines~~included inadvising ~~Zambia~~on ~~from~~various ~~1973~~legal, toregulatory ~~1976~~and compliance matters, transactions and asother responsibilities that are common for a ~~mining~~general ~~consultant~~counsel and corporate secretary. Mr. Pechersky was in ~~Australia~~private ~~between~~practice ~~1981~~for ~~and~~approximately ~~1992~~seven years with the international law firm Vinson & Elkins L. L.P. before joining Unocal Corporation. Mr. ~~Taylor~~Pechersky ~~graduated~~also ~~from~~served as a Law Clerk to the ~~University~~Hon. Loretta A. Preska, Chief Judge of ~~Wales~~the ~~with~~U.S. aDistrict ~~bachelor~~Court for the Southern District of ~~science~~New ~~degree~~York in ~~mineral~~1995 ~~exploitation~~and 1996. Mr. Pechersky earned his Bachelor’s degree and Juris Doctorate from the University of Texas, Austin, Texas.

Heath Hill has served as our Vice President and Chief Accounting Officer since September 2010. Previously, Mr. Hill served in various capacities with PricewaterhouseCoopers LLP, our independent public accountants, from September 1998 to September 2010, including Senior Manager from September 2006 to September 2010, and Manager from September 2003 to September 2006. While with PricewaterhouseCoopers LLP, Mr. Hill’s responsibilities included assurance services primarily related to SEC registrants, including annual audits of financial statements and internal controls, public debt offerings and IPO transactions. From June 2003 to June 2005 he held a position with PricewaterhouseCoopers in Germany serving USU.S. registrants throughout Europe. Mr. Hill never worked on any engagements or projects for Cloud Peak Energy Inc. or its predecessor, Rio Tinto, while he was with PricewaterhouseCoopers LLP. Mr. Hill earned his ~~bachelor~~Bachelor’s degree in accounting from the University of Northern Colorado and is an active certified public accountant.

1713

Table of Contents

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~~Current and future laws, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations, or orders, and related third-party legal challenges, 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~~Current and future laws, regulations or orders, including those relating to global climate change, may also cause coal to continue 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, current and future laws, regulations or orders may materially adversely affect our mining operations, cost structure, the price we receive for our coal, or our customers’ demand for coal.

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

Mining Permits and Approvals

Numerous governmental permits or approvals are required for mining operations. When we apply for these permits and approvals, we may be required to prepare and present data to federal, state or local authorities pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment. For example, in order to obtain a federal coal lease, an EIS must be prepared to assist the BLM in determining the potential environmental impact of lease issuance, including any direct and indirect effects from the mining, transportation and burning of coal. ~~Recently~~In recent years, particular attention has been focused on the impact of the production and usage of coal on global climate change, which resulted in extensive comments from environmental groups on the EIS prepared in connection with the West Antelope II LBA, and subsequent legal challenges were filed ~~in 2010~~ against the BLM and the Secretary of the Interior with respect to ~~this~~the ~~LBA,~~corresponding ~~which~~coal ~~we have nominated~~leases. ~~This~~See ~~may~~Item ~~result~~3 in“Legal ~~further~~Proceedings—West ~~delays~~Antelope orII anLBA ~~inability to obtain this lease~~Challenges.” ~~Future~~Our nominations or lease applications may ~~also~~ be subject to delays or challenges, which may result in difficulties in obtaining ~~other~~leases or impact our ability to mine the coal subject to those leases and/or delay our access to mine the coal. The authorization, permitting and implementation requirements imposed by federal, state and local authorities may be costly and time consuming and may limit or delay commencement or continuation of mining operations. In the states where we operate, the applicable laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if officers, directors, ~~shareholders~~stockholders with specified interests or certain other affiliated entities with specified interests in the applicant or permittee have, or are affiliated with another entity that has, outstanding permit violations. Thus, past or ongoing violations of applicable laws and regulations by these interested persons and entities could provide a basis to revoke our existing permits and to deny the issuance of additional permits.

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

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

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.14

Table of Contents

Surface Mining Control and Reclamation Act

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

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

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

In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund, which was created by SMCRA, imposes a fee on all coal produced. The proceeds of the fee are used to restore mines closed or abandoned prior to SMCRA’s adoption in 1977. The current fee is $0.~~315~~28 per ton of coal produced from surface mines. In ~~2010~~2013, we recorded $2924.12 million of expense related to these reclamation fees for our three owned and operated mines.

Surety Bonds

~~State~~Federal and state laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. ~~Prior~~As toof ~~the IPO~~December 31, ~~Rio Tinto served as guarantor of our surety bonds~~2013, ~~and~~there ~~our letters of credit~~ were ~~issued~~approximately ~~under Rio Tinto’s pre-existing credit facilities~~$677. We5 ~~have~~million ~~obtained~~in ~~new~~ surety bonds, ~~letters~~outstanding ofto ~~credit~~secure ~~or other credit arrangements and have obtained~~ the ~~full~~performance ~~release~~ of ~~Rio~~our ~~Tinto~~reclamation ~~and~~obligations ~~its~~(including ~~affiliates~~$66.8 million with respect to ~~any~~our ~~existing~~obligations ~~surety~~for ~~bonds,~~the ~~letters~~Decker ofmine ~~credit~~ and ~~other~~approximately ~~guarantees~~$0.6 ormillion ~~credit~~for ~~arrangements and such instruments have been accepted as replacements by~~ the ~~appropriate agencies.~~

As of December 31, 2010, there were approximately $525.0 million in surety bonds outstanding to secure the performance of our reclamation obligations (including our obligations with respect to the Decker mine). In addition, we have15

Table of Contents

aYoungs ~~letter~~Creek ofproject). At ~~credit~~some ~~for~~point, ~~$10.5~~federal ~~million~~and ~~that~~state welaws ~~use~~may tobe ~~secure~~amended ~~our~~to ~~50%~~require ~~share~~certain forms of ~~additional~~financial ~~reclamation~~assurance ~~obligations~~that atare ~~the~~more ~~Decker~~costly ~~mine. At~~to ~~December 31~~obtain, ~~2010,~~such weas ~~had~~letters ~~$182.1 million~~ of ~~restricted cash used as collateral for our surety bonds~~credit.

Mine Safety and Health

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

WeIn ~~have~~2006, ~~implemented~~in ~~various~~response ~~internal~~to ~~standards~~underground tomine ~~promote~~accidents, ~~employee~~Congress ~~health~~enacted the Mine Improvement and ~~safety~~New Emergency Response Act (the “MINER Act”). In ~~addition~~The toMINER ~~these~~Act ~~internal~~significantly ~~standards~~amended the Mine Act, werequiring ~~are~~improvements ~~also~~in ~~Occupational~~mine ~~Health~~safety practices, increasing criminal penalties and ~~Safety~~establishing ~~Assessment~~a ~~Series 18001~~maximum ~~certified~~civil penalty for non-compliance, and ~~have~~expanding ~~voluntarily~~the ~~implemented~~scope ~~policies~~of federal oversight, inspection and ~~standards~~enforcement inactivities. Since ~~addition~~passage toof ~~those~~the ~~required~~MINER byAct, ~~state~~enforcement orscrutiny ~~federal~~has ~~regulations~~increased, ~~that~~including wemore ~~consider~~inspection ~~important~~hours toat mine sites, increased numbers of inspections and increased issuance of the ~~health~~number and ~~safety~~the severity of ~~our~~enforcement ~~employees~~actions and related penalties. ~~According~~ toVarious ~~MSHA~~states ~~data,~~also inhave ~~2009~~enacted wetheir ~~had~~own ~~one~~new laws and regulations addressing many of ~~the~~these ~~lowest~~same ~~employee~~subjects. ~~all~~MSHA ~~injury~~continues ~~incident~~to ~~rate~~interpret ~~among~~and implement various provisions of the 10MINER ~~largest~~Act, ~~U.S.~~along ~~coal~~with ~~producing~~introducing ~~companies~~new proposed regulations and standards.

~~Under~~In ~~the~~response ~~Black~~to ~~Lung Benefits Revenue Act of 1977 and~~ the ~~Black~~April 2010 ~~Lung~~explosion ~~Benefits~~at ~~Reform~~Massey ~~Act~~Energy ofCompany’s ~~1977,~~Upper asBig ~~amended~~Branch ~~in 1981~~Mine, ~~each~~we ~~coal~~have ~~mine~~seen ~~operator~~an ~~must~~increase ~~pay~~in ~~federal~~enforcement ~~black~~scrutiny ~~lung~~continue ~~benefits~~ to ~~claimants~~increase, ~~who~~including ~~are~~more ~~current~~inspection ~~and~~hours ~~former~~at ~~employees~~mine ~~and~~sites, ~~also~~increased ~~make~~numbers ~~payments~~of toinspections aand ~~trust~~increased ~~fund~~issuance ~~for~~of the ~~payment~~number ~~of benefits~~ and ~~medical expenses to claimants who last worked in~~ the ~~coal~~severity ~~industry~~of ~~prior~~enforcement ~~to January 1, 1970~~actions. ~~The~~Various ~~trust~~states ~~fund~~also ishave ~~funded~~enacted bytheir anown ~~excise~~new ~~tax~~laws ~~on production of up to $1.10 per ton for deep-mined coal~~ and upregulations toaddressing ~~$0.55~~many ~~per~~of ~~ton~~these ~~for~~same ~~surface-mined coal, neither amount to exceed 4~~subjects.4% Our ofcompliance ~~the~~with ~~gross~~these ~~sales~~or ~~price. The~~any ~~excise~~new ~~tax~~mine ~~does~~health ~~not~~and ~~apply~~safety toregulations ~~coal~~could ~~shipped~~increase ~~outside~~our ~~the~~mining ~~U.S. In 2010~~costs, weonly ~~recorded~~some ~~$42.6 million~~ of ~~expense~~which ~~related~~may tobe ~~this~~passed ~~excise~~on ~~tax~~to ~~for our three owned and operated mines~~customers.

We have implemented various internal standards to promote employee health and safety. In addition to these internal standards, we are also Occupational Health and Safety Assessment Series 18001 certified and have voluntarily implemented policies and standards in addition to those required by state or federal regulations that we consider important to the health and safety of our employees. According to MSHA data, in 2013, we had one of the lowest employee all injury incident rates among the largest U.S. coal producing companies.

Black Lung

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must pay federal black lung benefits to claimants who are current and former employees and also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to January 1, 1970. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the U.S. In 2013, we recorded $42.5 million of expense related to this excise tax for our three owned and operated mines.

The Patient Protection and Affordable Care Act includes significant changes to the federal black lung program including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association with the federal black lung program. For miners last employed as miners after

Table of Contents

1969 and who are determined to have contracted black lung, we maintain coverage sufficient to cover the cost of present and future claims through the use of trusts or insurance policies. We may also be liable under state laws for black lung claims that are covered through insurance policies.

Clean Air Act

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

20· Acid Rain. Title IV of the Clean Air Act requires reductions of sulfur dioxide emissions by electric utilities. Affected power plants have sought to reduce sulfur dioxide emissions by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading sulfur dioxide emission allowances. We cannot accurately predict the future effect of these Clean Air Act provisions on our operations. These acid rain requirements would not be supplanted by CSAPR, were it to take effect.

· NAAQS for Criterion Pollutants. The Clean Air Act requires the EPA to set standards, referred to as NAAQS, for six common air pollutants, including nitrogen oxide and sulfur dioxide. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. Meeting these limits may require reductions of nitrogen oxide and sulfur dioxide emissions. Although our operations are not currently located in non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development if that were to change. On February 9, 2010, the EPA published revised NAAQS for nitrogen dioxide. On June 22, 2010, the EPA published a final rule that tightens the NAAQS for sulfur dioxide. Non-attainment designations for the 2012 nitrogen dioxide NAAQS were determined in January 2012, with all of the U.S. declared unclassifiable/attainment with additional monitoring planned. Initial non-attainment determinations related to the 2010 sulfur dioxide rule were published in August 2013 with an effective date of October 4, 2013; these are comprised of areas with 2009-2011 data indicating non-attainment of the 2010 standards. Determinations on remaining areas of the U.S. have yet to be made. For the initial non-attainment designation areas, state implementation plans are due in the winter of 2014; and the deadline to achieve attainment is the summer of 2017. In addition, on December 14, 2012, the EPA issued an update to the NAAQS for fine particles, tightening the annual PM2.5 standard to 12 micrograms per cubic meter. In separate but associated actions, in January 2013 the District of Columbia Circuit Court remanded to the EPA the agency’s 1997 PM2.5 implementation rules; proposed revisions to address that remand were published in November 2013 and finalization has not occurred as of January 31, 2014. We do not know whether or to what extent these developments might affect our operations or our customers’ businesses.

· Clean Air Interstate Rule and Cross-State Air Pollution Rule. CAIR calls for power plants in 28 states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system now in effect for acid rain. In June 2011, the EPA finalized CSAPR, a replacement rule to CAIR, which requires 28 states in the Midwest and eastern seaboard of the United States to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions would commence in 2012 with further reductions effective in 2014. However, on August 21, 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR and ordered the EPA to continue enforcing CAIR. The EPA petitioned for en banc review of that decision but the petition was denied on January 24, 2013. In March 2013, the EPA petitioned the U.S. Supreme Court to hear their challenge of the D.C. Circuit Court’s vacatur of CSAPR; in June 2013 the Supreme Court granted certiorari to the EPA, agreeing to review aspects of the vacatur. Oral arguments occurred in early December 2013. We are unable to predict whether the CSAPR program will be upheld or reversed but for states to meet their requirements under CSAPR, a number of coal-fired electric generating units will likely

Table of Contents

~~recent~~need ~~years,~~to ~~Congress~~be ~~has considered legislation that would require increased reductions in emissions of sulfur dioxide~~retired, ~~nitrogen~~rather ~~oxide~~than ~~and~~retrofitted ~~mercury. In~~with ~~addition to~~ the ~~greenhouse~~necessary ~~gas~~emission ~~issues~~control ~~discussed below~~technologies, ~~the~~reducing ~~air~~demand ~~emissions~~for ~~programs~~thermal ~~that may affect our operations, directly or indirectly, include, but are not limited to, the following:~~coal.

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

· Particulate Matter. The Clean Air Act requires the EPA to set standards, referred to as NAAQS, for certain pollutants. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. For example, NAAQS have been issued for coarse particulate matter with an aerodynamic diameter less than or equal to 10 microns, or PM10, and for fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns, or PM2.5. In 2004, the EPA designated all or part of 225 counties in 20 states as well as the District of Columbia, as non-attainment areas with respect to the PM2.5 NAAQS. Individual states were required to identify the sources of emissions and submit emission reduction plans by 2008. These plans could be state-specific or regional in scope. Under the Clean Air Act, individual states have until 2010, with possible extensions to 2015, to secure emissions reductions from sources contributing to the problem and achieve attainment of the standards. None of our operations are located in non-attainment areas for PM2.5 that were designated in 2004. New, more stringent NAAQS for PM2.5 and PM10 were promulgated in 2006.

In February 2009, the U.S. Court of Appeals for the District of Columbia Circuit upheld the 2006 PM10 NAAQS, but remanded the 2006 PM2.5 NAAQS to the EPA. The 2006 PM2.5 NAAQS remain in effect pending either the promulgation of a new NAAQS or an adequate justification of the 2006 PM2.5 NAAQS by the EPA. Any new PM2.5 NAAQS may be more stringent than the 2006 version. In November 2009, the EPA designated non-attainment areas for the revised PM2.5 NAAQS adopted in 2006. State emission reduction plans for achieving the revised standards are due in 2012 and attainment must be achieved between 2014 and 2019. Meeting the 2006 PM2.5 NAAQS or any new version in non-attainment areas may require reductions of nitrogen oxide and sulfur dioxide emissions, in addition to requiring reductions of PM2.5 emissions that are separate and distinct from the reductions that may be required under any other program. Although our operations are not currently located in non-attainment areas, enforcement of the 2006 PM2.5 NAAQS or the promulgation of any new standard will affect many power plants, especially coal-fired plants in non-attainment areas. We are unable to predict the magnitude of the impact on the demand for, or price of, lower sulfur coals from the PRB. Moreover, if the areas in which our mines and coal preparation plants are located suffer from extreme weather events such as droughts, or are designated as non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development. In addition, the EPA has set more stringent emissions standards for coal preparation plants that took effect on October 8, 2009. These revised limits include more stringent and additional particulate matter emissions limits for certain plants constructed, reconstructed or modified after April 28, 2008, and new emission limits for sulfur dioxide, nitrogen dioxide and carbon monoxide from certain equipment constructed, reconstructed or modified after May 27, 2009. We do not know whether or to what extent the revised limits might have a negative impact on our customers or adversely affect the demand for coal.

· Ozone. The EPA issued revised ozone NAAQS imposing more stringent limits that took effect in May 2008. Nitrogen oxides, which are a by-product of coal combustion, are classified as an ozone precursor. Under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants. Attainment dates for the new standards range between 2013 and 2030, depending on the severity of the non-attainment. In July 2009, the U.S. Court of Appeals for the District of Columbia vacated part of a rule implementing the ozone NAAQs and remanded certain other aspects of the rule to the EPA for further consideration. Notwithstanding the decision, we expect that additional emissions control requirements may be imposed on new and expanded coal-fired power plants and industrial boilers in the years ahead. In January 2010, the EPA proposed to adopt even more stringent primary NAAQS for ozone, between the range of 60-70 parts per billion (“ppb”) (compared with the 75 ppb standard adopted in 2008). Stringent secondary standards to protect sensitive vegetation and ecosystems also were proposed. The EPA has extended the deadline for adopting new standards to the end of July 2011; non-attainment designations will be made by July 2013; state plans to implement the standards will be due by the end of 2016; and attainment of the standards must be achieved by 2018 or later, depending on the severity of the problem. The combination of these actions may impact demand for coal nationally, but we are unable to predict the magnitude of the impact.

Table of Contents

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

· Nitrogen Dioxide. On February 9, 2010, the EPA published a revised NAAQS for nitrogen dioxide. For the first time, the EPA has adopted a 1-hour standard at a level of 100 ppb, as well as retaining the existing annual standard. Initial designations of non-attainment areas will be made by January 2012, with additional designations in 2016-2017 based on further monitoring of ambient levels of nitrogen dioxide. EPA estimates the target date for attainment of the new standard will be between 2021-2022. We do not know whether or to what extent these developments might affect our operations.

· NOx SIP Call. The NOx SIP Call program was established by the EPA in October 1998 to reduce the transport of nitrogen oxide and ozone on prevailing winds from the Midwest and South to states in the Northeast, which alleged that they could not meet federal air quality standards because of migrating pollution. The program is designed to reduce nitrogen oxide emissions by one million tons per year in 22 eastern states and the District of Columbia. As a result of the program, many power plants have been or will be required to install additional emission control measures, such as selective catalytic reduction devices. Installation of additional emission control measures will make it more costly to operate coal-fired power plants, potentially making coal a less attractive fuel.

· ~~Clean~~Mercury ~~Air~~and ~~Interstate~~Hazardous ~~Rule~~Air Pollutants. ~~The~~On ~~EPA’s Clean Air Interstate Rule~~February ~~calls~~16, ~~for~~2012, ~~power~~the ~~plants~~EPA informally 28adopted ~~eastern~~a ~~states~~rule that ~~and~~would regulate the ~~District~~emission of ~~Columbia~~mercury toand ~~reduce~~other ~~emission~~metals, ~~levels~~fine ofparticulates ~~sulfur~~and ~~dioxide~~acid ~~and~~gases ~~nitrogen~~such ~~oxide~~as ~~pursuant~~hydrogen tochloride afrom ~~cap~~coal- and oil-~~trade~~fired ~~program~~power ~~similar~~plants, referred to ~~the~~as ~~system now in effect for acid rain~~“MATS.” InOn ~~July~~November ~~2008~~30, 2012, the ~~U.S.~~EPA ~~Court~~published ofa ~~Appeals~~reconsideration ~~for~~of the ~~District~~MATS ofrule as ~~Columbia~~it ~~Circuit~~pertains ~~vacated~~to ~~CAIR~~new inpower ~~its~~plants, ~~entirety~~principally ~~and~~adjusting ~~directed~~emissions ~~the~~limits ~~EPA~~for ~~to commence~~ new ~~rule~~coal-~~making. After~~fired aunits ~~petition~~to ~~for~~levels ~~rehearing,~~considered ~~the~~attainable ~~court~~by ~~ruled~~existing incontrol ~~December~~technologies. In March ~~2008~~2013, ~~that~~the toEPA ~~completely~~finalized ~~vacate~~the ~~CAIR~~reconsideration ~~would~~form ~~sacrifice~~of ~~public~~the ~~health~~rule. Litigation ~~and~~filings ~~environmental~~subsequently ~~benefits~~occurred and ~~that~~oral ~~CAIR~~arguments ~~should~~were ~~remain~~heard inby ~~effect while~~ the ~~EPA~~District ~~modifies the rule. The EPA released its proposed replacement~~ of ~~CAIR,~~Columbia ~~which~~Circuit isCourt ~~CATR~~in onearly ~~July~~December ~~6, 2010~~2013. ~~Under~~The ~~the~~litigation ~~proposed~~does ~~rule,~~not ~~which~~include ~~will~~provisions befor ~~subject~~a tostay ~~public comment~~ and ~~possible amendments,~~ the ~~EPA~~timeline ~~would~~for ~~require~~general ~~reductions~~compliance inwith ~~annual~~the ~~sulfur~~standards ~~dioxide~~remains ~~and~~at ~~nitrogen~~March 2015. Apart ~~oxide emissions~~ from ~~power~~MATS, ~~plants~~several ~~in 28~~ states~~. A~~ ~~final~~have ~~rule is~~enacted ~~expected~~or inproposed ~~July 2011~~regulations ~~and~~requiring ~~the emissions~~ reductions ~~would start~~ in ~~2012. When~~mercury ~~combined~~emissions ~~with~~from ~~other~~coal-fired ~~EPA~~power ~~and state efforts~~plants, ~~the~~and ~~EPA~~federal ~~predicts~~legislation ~~that~~to ~~CATR~~reduce ~~will~~mercury ~~result~~emissions infrom ~~sulfur~~power ~~dioxide~~plants ~~reductions~~has ofbeen ~~71%~~proposed. Regulation ~~and nitrogen oxide reductions~~ of ~~52%~~mercury ~~from~~emissions ~~2005 levels~~ by ~~2014. In~~the ~~addition~~EPA, ~~legislation~~states, ~~has~~Congress ~~been~~or ~~introduced~~pursuant into ~~the Senate that would require~~ an ~~80%~~international ~~reduction~~treaty inmay ~~power~~decrease ~~plants’~~the ~~sulfur~~future ~~dioxide~~demand ~~emissions~~for ~~by 2018~~coal, abut ~~50%~~we ~~reduction~~are incurrently ~~nitrogen~~unable ~~oxide~~to ~~emissions~~predict bythe ~~2015~~magnitude ~~and~~of aany ~~90%~~such ~~reduction in mercury emissions by 2015~~effect. ~~Under~~The ~~CAIR,~~North ~~the~~American ~~proposed~~Electric ~~CATR,~~Reliability ~~and~~Corporation ~~any~~in ~~replacement~~its ~~rule with~~2011 ~~similarly~~and ~~stringent~~2012 ~~caps, although some coal~~Long-~~fired~~Term ~~power~~Reliability ~~plants~~Assessments ~~might~~noted ~~elect~~that toCSAPR, ~~use~~MATS ~~more~~and ~~low-sulfur~~other ~~coal,~~proposed ~~which~~regulations could ~~increase~~accelerate the ~~demand,~~retirement ~~other~~of ~~plants~~a ~~might~~significant benumber ~~required~~of tocoal-fired ~~install~~power ~~additional pollution control equipment~~plants. ~~This~~We ~~pollution~~continue ~~control~~to ~~equipment,~~evaluate ~~such~~the aspossible ~~scrubbers,~~scenarios ~~could~~associated ~~lead~~with ~~scrubbed~~CSAPR ~~plants~~and toMATS ~~become~~and ~~less~~the ~~sensitive~~effects tothey ~~the~~may ~~sulfur~~have ~~content~~on ofour ~~coal~~business and ~~more~~our ~~sensitive~~results toof ~~delivered price~~operations, ~~thereby~~financial ~~potentially~~condition ~~decreasing~~or ~~the~~cash ~~demand for low-sulfur coal at these plants and reducing market prices for low-sulfur coal~~flows.

· ~~Mercury. In~~Regional ~~February 2008~~Haze, ~~the~~New ~~U.S.~~Source ~~Court~~Review ofand ~~Appeals~~Methane. The ~~for~~EPA ~~the~~has ~~District~~initiated ofa ~~Columbia~~regional ~~Circuit~~haze ~~vacated~~program ~~the~~designed ~~EPA’s~~to ~~Clean~~protect ~~Air~~and ~~Mercury~~improve ~~Rule (“CAMR”),~~visibility ~~which~~at ~~had established a cap-~~and~~-trade~~ ~~program~~around tonational ~~reduce~~parks, ~~mercury~~national ~~emissions~~wilderness ~~from~~areas ~~power~~and ~~plants~~international parks. AtOn ~~present~~December 23, ~~there~~2011, ~~are~~the noEPA ~~federal~~Administrator ~~regulations~~signed ~~that~~a ~~require~~final ~~monitoring~~rule under ~~and~~which ~~reduction~~the ofemission ~~mercury~~caps ~~emissions~~imposed atunder ~~existing~~the ~~power~~CSAPR ~~plants,~~for ~~and~~a ~~regulations~~given ~~that~~state ~~were~~would ~~promulgated~~supplant ~~under~~ the ~~CAMR~~obligations ~~framework~~of inthat ~~several~~state ~~states~~with ~~have~~regard ~~been~~to ~~invalidated~~visibility protection. AsThat arule has ~~result~~not ofyet ~~the~~been ~~decision~~published, toand ~~vacate~~ the ~~CAMR, the~~ EPA’s isplans ~~gathering~~for ~~information~~publishing ~~from~~this ~~coal-fired~~rule in ~~power~~light ~~plants regarding emissions~~ of ~~mercury and other hazardous air pollutants for~~ the ~~purpose~~status of ~~developing~~CSAPR ~~Maximum~~have ~~Achievable~~yet ~~Control~~to ~~Technology~~be ~~standards (“MACT”), for these emissions~~announced. ~~The~~In ~~MACT~~addition, ~~standards~~the ~~for~~EPA’s ~~mercury~~new ~~are~~source ~~likely~~review toprogram ~~impose~~under ~~stricter~~certain ~~limitations~~circumstances onrequires ~~mercury~~existing ~~emissions~~coal-fired ~~from~~ power plants ~~than the vacated CAMR~~, aswhen ~~well~~modifications ~~as limits on other hazardous air pollutants. The EPA is under a court deadline~~ to ~~issue~~those ~~a final rule requiring MACT for power~~ plants bysignificantly ~~November 2011. In~~change ~~the meantime~~emissions, ~~case-by-case~~to ~~MACT~~install ~~determinations~~the ~~for~~more ~~mercury~~stringent ~~and possibly other hazardous~~ air ~~pollutants~~emissions ~~may~~control beequipment required ~~for~~of new ~~and reconstructed coal-fired power~~ plants. WeThere ~~are~~is ~~unable~~also pending litigation to ~~predict~~force the ~~impact~~EPA ofto ~~any~~list ~~future~~coal ~~MACT~~mines ~~standard~~as ~~for~~a ~~mercury~~category orof ~~other hazardous~~ air ~~pollutants~~pollution onsources ~~the~~that ~~demand~~endanger ~~for,~~public health or ~~the~~welfare ~~price~~under Section 111 of, ~~our~~the ~~low-sulfur~~Clean ~~coal. Apart~~Air ~~from~~Act ~~CAMR,~~and establish ~~several~~standards ~~states~~to ~~have~~reduce ~~enacted~~emissions orfrom ~~proposed~~sources ~~regulations~~of ~~requiring~~methane ~~reductions~~and inother ~~mercury~~ emissions ~~from~~related to coal~~-fired~~ ~~power plants, and~~mines.

Table of Contents

federal legislation to reduce mercury emissions from power plants has been proposed. The Obama Administration has also indicated a desire to begin negotiations on an international treaty to reduce mercury pollution. Regulation of mercury emissions by the EPA, states, Congress or pursuant to an international treaty may decrease the future demand for coal, but we are currently unable to predict the magnitude of any such effect.

· Regional Haze. The EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. This program may result in additional emissions restrictions from new coal-fired power plants whose operations may impair visibility at and around federally protected areas. This program may also require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could negatively affect the future market for coal.

· New Source Review. A number of pending regulatory changes, court actions and administrative actions may affect the scope and application of the EPA’s new source review program, which under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install the more stringent air emissions control equipment required of new plants. The changes to the new source review program may negatively impact demand for coal nationally, but as the final form of the requirements after their revision is not yet known, we are unable to predict the magnitude of the impact. In June, 2010, Earthjustice filed a petition with EPA on behalf of several environmental organizations that requested the agency to: 1) list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the Clean Air Act; 2) establish standards of performance to reduce emissions from new and modified coal mine sources of methane (due to global climate change concerns), particulate matter (including fugitive particulates), volatile organic compounds and nitrogen oxides; and 3) establish standards of performance to reduce emissions of methane from existing coal mine sources. We do not know whether EPA will grant the petition and propose regulations accordingly. If EPA should propose regulations, we do not know what they might require or what impact they might have on our operations.

Global Climate Change

~~One~~There ~~by-product~~are ofthree ~~burning~~important ~~coal~~sources ~~is carbon dioxide, which is considered a greenhouse gas and is a major source~~ of ~~public~~GHGs ~~concern,~~associated ~~recent regulatory initiatives and litigation~~ with ~~respect~~the tocoal ~~global climate change and global warming~~industry. InThe ~~2005,~~end ~~the~~use ~~Kyoto~~of ~~Protocol~~our tocoal ~~the~~in ~~1992~~electricity ~~United~~generation ~~Nations~~is ~~Framework Convention on Climate Change (the “Kyoto Protocol”), which establishes~~ a ~~binding~~source ~~set~~ of ~~emission~~GHGs. Combustion ~~targets~~of fuel for ~~greenhouse~~mining ~~gases,~~equipment ~~became~~used ~~binding~~in oncoal ~~all~~production ~~those~~is ~~countries~~another ~~that~~source ~~had~~of ~~ratified it~~GHGs. ToIn ~~date~~addition, ~~the~~coal ~~U.S.~~mining ~~has~~can ~~refused~~release tomethane, ~~ratify~~a ~~the Kyoto Protocol~~GHG, ~~which~~directly ~~expires~~into ~~in 2012. Emission targets under~~ the ~~Kyoto Protocol vary from country to country~~atmosphere. IfThese ~~the U.S. were to ratify the Kyoto Protocol, the U.S. would be required to reduce greenhouse gas~~ emissions ~~to 93% of 1990 levels~~ from ~~2008~~coal toconsumption ~~2012. International~~and ~~discussions~~production are ~~currently~~potentially ~~underway~~subject to ~~develop~~regulation aas ~~treaty~~part ~~to replace the Kyoto Protocol after its expiration in 2012, with an initial goal~~ of ~~reaching~~regulatory ainitiatives ~~consensus~~to onaddress aglobal ~~replacement~~climate ~~treaty~~change atand ~~the~~global ~~milestone meeting in Copenhagen, Denmark in December 2009~~warming. ~~The~~These ~~Copenhagen~~regulatory ~~meeting~~initiatives ~~did~~may ~~not~~increase ~~result~~our incosts ~~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~~decrease ~~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 our coal.

~~Future~~The ~~regulation~~Kyoto ofProtocol ~~greenhouse~~to ~~gas emissions in~~ the ~~U.S.~~1992 ~~could~~United ~~occur~~Nations ~~pursuant~~Framework toConvention ~~future~~on ~~U.S.~~Climate ~~treaty~~Change ~~commitments,~~(the ~~new~~“Kyoto ~~domestic~~Protocol”) ~~legislation~~became ~~that~~effective ~~may~~in ~~impose~~2005, aand ~~carbon~~bound ~~emissions~~those ~~tax~~developed orcountries ~~establish~~that aratified ~~cap-and-trade~~it ~~program~~(which ~~or regulation by~~ the ~~EPA~~U. ~~Passage~~S. ofdid ~~comprehensive~~not ~~global~~do) ~~climate~~to ~~change~~reduce ~~and~~their ~~energy~~global ~~legislation~~GHG ~~could impact the demand for coal~~emissions. ~~Any~~Discussions ~~reduction~~to indevelop ~~the~~a ~~amount~~treaty ofto ~~coal~~replace ~~consumed~~the byKyoto ~~North~~Protocol ~~American~~after ~~electric~~its ~~power~~expiration ~~generators~~in ~~could~~2012 ~~reduce~~are ~~the~~still ~~price~~ongoing. Any offuture ~~coal~~global ~~that~~agreement weon ~~mine~~climate ~~and~~change ~~sell,~~could ~~thereby~~further ~~reducing~~reduce ~~our~~demand ~~revenues~~for ~~and materially and adversely affecting~~ our ~~business and results of operations~~coal.

Even in the absence of new federal legislation, greenhouse gas emissions may be subject to regulation by the EPA pursuant to the Clean Air Act. In response to the 2007 U.S. Supreme Court ruling Massachusetts v. EPA, the EPA has taken several steps towards promulgating and implementing regulations regarding the emission of greenhouse gases. On December 7, 2009, the EPA issued a final finding that the presence of carbon dioxide and certain other greenhouse gases in the atmosphere endangers public health and welfare. This finding was a prerequisite to EPA regulation of greenhouse gas emissions from motor vehicles under the Clean Air Act. As a result of this finding, EPA has promulgated further regulations18

Table of Contents

~~subjecting~~The ~~greenhouse~~EPA ~~gas~~has begun adopting and implementing regulations to restrict emissions ~~from~~of ~~stationary~~GHGs ~~sources~~under ~~that~~existing ~~exceed~~provisions ~~certain~~of ~~emission~~the ~~thresholds~~Clean (Air Act. These rules were legally challenged, but on June 26, 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied these ~~emission~~challenges. Among ~~thresholds~~the ~~would~~rules promulgated ~~cover~~after ~~power~~the ~~plants~~EPA’s asendangerment ~~well~~finding aswas ~~other~~the ~~large~~Tailoring ~~industrial~~Rule, which requires that all new or modified stationary sources) ~~will~~of ~~also~~GHGs ~~become~~that ~~subject~~will toemit ~~various~~more ~~requirements~~than 75,000 ~~including~~tons ~~certain~~of ~~air~~carbon ~~permitting~~dioxide ~~requirements,~~per ~~under~~year ~~the~~and are otherwise subject to Clean Air Act ~~beginning~~regulation, onand ~~January 2~~any other facilities that will emit more than 100,000 ~~2011~~tons of carbon dioxide per year, to undergo prevention of significant deterioration (“PSD”) permitting. ~~These~~PSD ~~requirements~~permitting ~~would~~requires ~~include~~that the ~~mandatory~~permitted ~~use~~entity ofadopt the best available control technology. Addressing ~~for~~a ~~greenhouse~~consent ~~gas~~decree ~~emissions~~with ~~whenever~~environmental groups, on April 13, 2012, the ~~construction~~EPA orpublished ~~modification~~draft ofNew aSource ~~facility~~Performance ~~would~~Standards ~~increase~~for greenhouse gas emissions byfrom ~~75,000~~new ~~tons~~electric ~~per~~generating ~~year~~units. The orObama ~~more~~Administration ashas ~~well~~announced asits ~~other~~intent ~~burdensome~~to issue regulations under Section 111(b) and ~~time-consuming~~Section 111(d) of ~~permitting~~Clean ~~requirements~~Air Act to set New Source Performance Standards for both new or future power plants and existing power plants by June 2015. As aof ~~result~~January 31, of2014, the EPA has not formally proposed any rules to finalize these ~~regulations,~~requirements ~~our~~relative ~~customers~~to ~~may~~new ~~reduce~~plants. On January 8, 2014, the ~~amount~~EPA ofissued ~~coal~~a ~~they~~proposed ~~purchase~~rule regulating GHG emissions from usnew greenfield power plants and new generating units at existing sources. ~~Moreover~~In this proposal, inthe ~~September~~EPA has concluded that partial carbon capture and sequestration is the appropriate emission standard for these sources. We believe that any final rules ~~2009,~~issued by the EPA ~~promulgated~~in this area will be challenged and, in fact, the state of Nebraska has already filed a ~~rule requiring~~lawsuit ~~certain~~challenging ~~emitters~~the legality of ~~greenhouse~~the ~~gases~~proposed rules. Additionally, ~~including~~in ~~coal-fired~~October 2013 ~~power~~the ~~plants,~~U.S. toSupreme ~~monitor~~Court ~~and~~granted ~~report~~certiorari ~~their~~to ~~greenhouse~~hear ~~gas~~arguments ~~emissions~~related to a combination of several petitions challenging the EPA’s approach to CO2 regulation.

~~Many~~The ~~states~~EPA ~~and~~has ~~regions~~also ~~have~~ adopted ~~greenhouse~~rules requiring ~~gas initiatives and certain governmental bodies, including~~ the ~~State~~reporting of ~~California,~~GHG ~~have~~emissions orfrom ~~are~~specified ~~considering~~large ~~the~~GHG ~~imposition of fees or taxes based on the~~ emission ofsources greenhouse gases by certain facilities. Ten northeastern states (Connecticut, Delaware, Maine, Massachusetts, Maryland, New Hampshire, New Jersey, New York, Rhode Island and Vermont) have formed the Regional Greenhouse Gas Initiative (“RGGI”), the only operating cap-and-trade system in the United States~~. RGGI~~, isincluding ~~aimed~~coal-fired atelectric ~~reducing carbon dioxide emissions from~~ power plants, inon ~~the~~an ~~participating~~annual ~~states. The~~basis, ~~RGGI~~beginning ~~program~~in ~~calls~~2011 for ~~signatory states to stabilize carbon dioxide~~ emissions atoccurring ~~2005~~after ~~levels~~January 1, ~~from 2009 to 2015~~2010, ~~followed~~as bywell aas ~~2.5%~~certain ~~reduction~~oil ~~each~~and ~~year~~natural ~~from~~gas ~~2015~~production ~~through 2018. Since its inception~~facilities, ~~several~~on ~~additional~~an ~~northeastern~~annual ~~states~~basis, ~~and~~that ~~Canadian~~began ~~provinces~~in ~~have~~2012 ~~joined as observers. RGGI has begun holding quarterly carbon dioxide allowance auctions~~ for ~~its~~emissions ~~initial~~occurring ~~three-year~~in ~~compliance period from January 1, 2009, to December 31,~~ 2011 toand ~~allow utilities to buy allowances to cover their carbon dioxide emissions~~beyond.

~~Global~~As ~~climate~~a ~~change~~result ~~initiatives~~of ~~are~~revisions ~~also~~to ~~being~~its ~~considered~~preconstruction orpermitting ~~enacted~~rules that inbecame ~~some~~fully ~~western~~effective ~~states. In~~on ~~September~~January ~~2006~~2, ~~California~~2011, ~~enacted~~ the ~~Global~~EPA ~~Warming~~is ~~Solutions~~now ~~Act~~requiring ofnew ~~2006~~sources, ~~which~~including ~~establishes~~coal-fired apower ~~statewide~~plants, ~~greenhouse~~to ~~gas~~undergo ~~emissions~~control ~~cap~~technology ofreviews ~~1990 levels by 2020 and sets a framework~~ for ~~further~~GHGs ~~reductions~~(predominately ~~after~~carbon ~~2020. In~~dioxide) ~~September 2006,~~as ~~California also adopted greenhouse gas legislation that prohibits long-term baseload generators from having~~ a ~~greenhouse~~condition ~~gas emissions rate greater than that~~ of ~~combined~~permit ~~cycle natural gas generator~~issuance. InThese ~~February 2007,~~reviews ~~the~~may ~~governors~~impose oflimits ~~Arizona,~~on ~~California,~~GHG ~~New Mexico~~emissions, ~~Oregon~~or ~~and~~otherwise ~~Washington~~be ~~launched~~used ~~the Western Climate Initiative in an effort~~ to ~~develop~~compel aconsideration ~~regional strategy for addressing global climate change. The goal~~ of ~~the~~alternative ~~Western~~fuels ~~Climate Initiative is to identify, evaluate~~ and ~~implement~~generation ~~collective and cooperative methods of reducing greenhouse gases in the region to 15% below 2005 levels by 2020. Since its initial launching~~systems, ~~a number of additional western states and provinces have joined the initiative, or have agreed to participate~~ as ~~observers,~~well ~~including Montana, which has joined the initiative and Wyoming, which has signed on~~ as anincrease ~~observer. The~~litigation ~~Western~~risk ~~Climate Initiative envisions an economy-wide cap-~~for—and~~-trade~~ ~~program~~so ~~that~~discourage ~~would~~development ~~include fossil fuels (such as~~ of—coal)-fired ~~production~~power ~~and processing~~plants. ~~Thus, our coal mines could incur additional direct costs if new laws are passed in Montana and Wyoming in accordance with the Western Climate Initiative.~~

~~Midwestern~~Various states ~~have~~and ~~also~~regions have adopted GHG initiatives toand ~~reduce~~certain ~~and~~governmental ~~monitor~~bodies, ~~greenhouse~~including ~~gas~~the ~~emissions. In~~State ~~November 2007~~of California, have or are considering the ~~governors~~imposition of ~~Illinois, Indiana, Iowa,~~fees ~~Kansas,~~or ~~Michigan,~~taxes ~~Minnesota,~~based ~~Ohio,~~on ~~South~~the ~~Dakota~~emission ~~and~~of ~~Wisconsin~~GHGs ~~and~~by ~~the~~certain ~~premier~~facilities. A number of ~~Manitoba~~states ~~signed~~have ~~the~~enacted ~~Midwestern~~legislative ~~Greenhouse~~mandates ~~Gas~~requiring ~~Reduction~~electricity ~~Accord~~suppliers to ~~develop~~use ~~and~~renewable ~~implement~~energy ~~steps~~sources to ~~reduce~~generate ~~greenhouse~~a ~~gas~~certain ~~emissions~~percentage of power. ~~The~~These ~~draft~~and ~~recommendations~~other current or future global climate change laws, ~~released~~regulations, court orders or other legally enforceable mechanisms may in ~~June 2009,~~the ~~call~~future ~~for~~require aadditional ~~20%~~controls ~~reduction~~on ~~below~~coal-fired ~~2005~~power ~~emissions~~plants ~~levels~~and byindustrial ~~2020~~boilers and ~~additional~~may ~~reductions~~even cause some users of coal to ~~80%~~switch ~~below~~from ~~2005~~coal ~~emissions~~to ~~levels~~alternative bysources ~~2080~~of fuel.

~~RGGI~~Likewise, GHG emissions have increasingly become issues that must be addressed in connection with the ~~Western~~preparation ~~Climate~~of ~~Initiative~~EISs ~~and~~necessary to obtain additional federal coal leases. For example, several environmental groups commented on the ~~Midwestern~~global ~~Greenhouse~~climate ~~Gas~~change ~~Reduction~~discussion ~~Accord~~within ~~have~~an ~~released~~EIS adocument ~~joint~~for ~~policy~~the ~~paper~~federal ~~stating~~coal ~~that~~lease ~~they~~application ~~share~~for athe ~~common~~West ~~vision~~Antelope onII ~~offsets~~LBA, ~~and~~which ~~signaling~~we ~~that~~nominated. Furthermore, the ~~three~~federal ~~programs~~coal ~~may~~leases befor ~~moving~~the ~~closer~~West ~~toward~~Antelope ~~acting~~II ~~together~~LBA, which we acquired in 2011, have been subject to ~~form a~~legal ~~national~~challenges ~~cap-~~filed against the BLM and~~-trade~~ ~~program~~Secretary of the Interior by environmental organizations. ~~Offsets~~See ~~are~~Item ~~greenhouse~~3 ~~gas~~“Legal ~~reduction~~Proceedings—West ~~projects~~Antelope ~~outside~~II aLBA ~~mandatory~~Challenges.” Disputes ~~cap~~regarding ~~that~~the ~~entities~~level ~~can~~of ~~turn~~evaluation torequired iffor ~~they~~climate ~~fail~~change could complicate and protract the time required to ~~meet~~obtain ~~greenhouse~~coal ~~gas~~leases ~~reductions~~on ~~targets~~a attimely ~~their~~basis ~~own~~which ~~facilities~~could have an adverse impact on our business.

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

These and other current or future global climate change rules have required, and rules, court orders or other legally enforceable mechanisms may in the future require, additional controls on coal-fired power plants and industrial boilers and

Table of Contents

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

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

Clean Water Act

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

~~CWA requirements that may directly or indirectly affect our operations include the following:~~19

· Wastewater Discharge. Section 402 of the CWA creates a process for establishing effluent limitations for discharges to streams that are protective of water quality standards through the National Pollutant Discharge Elimination System (“NPDES”), and corresponding programs implemented by state regulatory agencies. Regular monitoring, reporting and compliance with performance standards are preconditions for the issuance and renewal of NPDES permits that govern discharges into waters of the U.S. Discharges that exceed the limits specified under NPDES permits can lead to the imposition of penalties, and persistent non-compliance could lead to significant penalties, litigation, compliance costs and delays in coal production. Furthermore, the imposition of future restrictions on the discharge of certain pollutants into waters of the U.S. could increase the difficulty of obtaining and complying with NPDES permits, which could impose additional time and cost burdens on our operations.

Discharges of pollutants into waters that states have designated as impaired (i.e., as not meeting present water quality standards) are subject to Total Maximum Daily Load (“TMDL”) regulations. The TMDL regulations establish a process for calculating the maximum amount of a pollutant that a water body can receive while maintaining state water quality standards. Pollutant loads are allocated among the various sources that discharge pollutants into that water body. Mine operations that discharge into water bodies designated as impaired will be required to meet new TMDL allocations. The adoption of more stringent TMDL-related allocations for our coal mines could require more costly water treatment and could adversely affect our coal production and costs of operations.

Table of Contents

~~The~~ CWA ~~also~~requirements ~~requires states to develop anti-degradation policies to ensure~~ that ~~non-impaired~~may ~~water~~directly ~~bodies~~or ~~continue~~indirectly toaffect ~~meet~~our ~~water~~operations ~~quality~~include ~~standards. The issuance and renewal of permits for~~ the discharge of pollutants to waters that have been designated as “high quality” are subject to anti-degradation review that may increase the cost, time and difficulty associated with obtaining and complying with NPDES permits.following:

· ~~Dredge~~Wastewater ~~and Fill Permits~~Discharge. ~~Many~~ Section 402 ~~mining activities, including the development~~ of ~~settling ponds and other impoundments, may result in impacts to waters of~~ the ~~U.S.,~~CWA ~~including~~creates ~~wetlands,~~a ~~streams~~process ~~and~~for ~~certain~~establishing ~~man-made~~effluent ~~conveyances~~limitations ~~with~~for ~~hydrologic~~discharges ~~connections~~ to ~~such~~ streams orthat ~~wetlands. Under the CWA, coal companies~~ are ~~required~~protective toof ~~obtain~~water aquality ~~Section 404~~standards ~~permit~~through ~~from~~ the ~~Army~~National ~~Corps~~Pollutant ofDischarge ~~Engineers~~Elimination ~~(the~~System (“~~Corps~~NPDES”), ~~prior~~and tocorresponding ~~conducting~~programs ~~such~~implemented ~~mining~~by ~~activities. In~~state ~~Coeur~~regulatory ~~Alaska Inc~~agencies. v. ~~Southeast~~Regular ~~Alaska~~monitoring, ~~Conservation~~reporting ~~Council,~~and ~~the~~compliance ~~U.S.~~with ~~Supreme~~performance ~~Court~~standards ~~held~~are ~~that~~preconditions for the ~~Section 402~~issuance and ~~Section 404~~renewal ~~permitting~~of ~~programs~~NPDES ~~are~~permits ~~mutually exclusive, such~~ that ifgovern ~~fill~~discharges ~~material is discharged~~ into waters of the U.S. Failure ~~under~~to acomply ~~Section 404~~with ~~permit, a Section 402 permit for~~ the ~~same~~CWA ~~discharge~~or isNPDES ~~not~~permits ~~required. The~~can ~~Corps~~lead ~~is authorized~~ to ~~issue~~the ~~general~~imposition ~~“nationwide” permits for specific categories~~ of ~~activities~~significant ~~that~~penalties, ~~are~~litigation, ~~similar~~compliance incosts ~~nature~~ and ~~that~~delays ~~are~~in ~~determined~~coal ~~to have minimal adverse effects on the environment~~production. ~~Permits~~ ~~issued pursuant to Nationwide Permit 21 (“NWP 21”)~~Furthermore, ~~generally authorize~~ the ~~disposal~~imposition of ~~dredged~~future orrestrictions ~~fill~~on ~~material~~the ~~from~~discharge ~~surface~~of ~~coal~~certain ~~mining~~pollutants ~~activities~~ into waters of the U.S., ~~subject~~could toincrease ~~certain~~the ~~restrictions. Since~~difficulty ~~March 2007,~~of ~~permits~~obtaining ~~under~~and ~~NWP~~complying 21with ~~were~~NPDES ~~reissued~~permits, ~~for~~which acould ~~five-year~~impose ~~period~~additional ~~with~~time ~~new~~and ~~provisions~~cost ~~intended~~burdens toon ~~strengthen~~our ~~environmental protections~~operations. ~~There~~For ~~must~~instance, bewaters ~~appropriate~~that ~~mitigation~~states inhave ~~accordance~~designated ~~with~~as ~~nationwide~~impaired ~~general~~(i.e., as ~~permit~~not ~~conditions~~meeting ~~rather~~present ~~than~~water ~~less~~quality ~~restrictive~~standards) ~~state-required~~are ~~mitigation~~subject ~~requirements,~~to ~~and~~Total ~~permit-holders~~Maximum ~~must~~Daily ~~receive~~Load ~~explicit~~regulations, ~~authorization~~which ~~from~~may ~~the~~lead ~~Corps~~to ~~before~~the ~~proceeding~~adoption ~~with~~of ~~proposed~~more ~~mining~~stringent ~~activities. We~~discharge ~~currently~~standards ~~utilize~~for ~~NWP~~our 21coal ~~authorizations~~mines ~~for~~and ~~our~~could ~~operations~~require inmore ~~Wyoming~~costly ~~and Montana~~treatment.

~~The Corps~~Likewise, ~~the~~when ~~EPA~~water ~~and~~quality ~~the Department of the Interior have announced an interagency action plan designed to reduce the harmful environmental consequences of mountaintop mining~~ in ~~the Appalachian region. As part of this interagency action plan and in response to~~ a ~~federal~~receiving ~~judge’s~~stream ~~ruling~~is inbetter ~~March 2009~~than ~~that the use of permits by the Corps to circumvent its statutory obligations to thoroughly examine the environmental impacts of mountaintop mining was illegal~~required, ~~in June 2010 the Corps suspended the use of NWP 21 in six Appalachian region~~ states~~. The~~ ~~permit~~are ~~continues~~required to beconduct ~~available~~an inanti-degradation ~~other~~review ~~regions~~before ofapproving ~~the~~discharge ~~country~~permits. ~~The~~ ~~suspension~~Anti-degradation ofpolicies ~~the~~may ~~NWP~~increase ~~21 in Appalachia will remain in effect until~~ the ~~Corps takes further action or until the permit expires on March 18~~cost, ~~2012. We~~time doand ~~not~~difficulty ~~practice~~associated ~~mountaintop~~with ~~mining;~~obtaining ~~we have no operations in the jurisdictions where these lawsuits were filed;~~ and wecomplying ~~have~~with noNPDES ~~operations in the states that may be affected by the suspension of NWP 21. However, decisions that restrict the issuance of~~ permits ~~pursuant~~and ~~to NWP 21, lawsuits challenging the use of NWP 21 that~~ may bealso ~~filed~~require inmore ~~jurisdictions~~costly ~~where we operate, or suspensions or modifications of NWP 21 in the states where we operate could restrict our ability to utilize NWP 21 authorizations in the future~~treatment. Additionally, while it is unknown precisely what other future changes will be implemented as a result of the interagency action plan, any future changes could further restrict our ability to obtain other new permits or to maintain existing permits.

~~The~~· Dredge ~~geographic~~and ~~extent~~Fill ofPermits. Many ~~the~~mining ~~Corps’~~activities, ~~regulatory~~including ~~jurisdiction~~the ~~over~~development ~~waters~~ of ~~the~~settling ~~U.S.~~ponds isand ~~likewise~~other ~~subject~~impoundments, torequire ~~legal~~a ~~uncertainty that may affect NWP 21 permitting as applied to our operations. On June~~Section 5,404 ~~2007,~~permit infrom ~~response to~~ the ~~U.S.~~Army ~~Supreme~~Corps ~~Court’s~~of ~~divided~~Engineers ~~decision~~(the ~~in Rapanos v~~“Corps”). ~~United~~Generally ~~States~~speaking, ~~the~~these ~~Corps and the EPA issued joint regulatory guidance interpreting the extent of jurisdiction under~~ Section 404 ofpermits allow the ~~CWA~~placement ~~and~~of ~~issued~~fill ~~revised~~materials ~~guidance~~into onnavigable ~~December 2, 2008. Specifically, the guidance differentiates between~~ waters ~~where~~of the ~~agencies~~United ~~will~~States ~~categorically~~including ~~assert~~wetlands, ~~jurisdiction~~streams, and ~~waters~~other ~~where~~regulated ~~the~~areas. The ~~agencies~~Corps ~~will~~has ~~assert~~issued ~~jurisdiction~~general on“nationwide” apermits ~~case-by-case~~for ~~basis after a fact-~~specific ~~“significant~~categories ~~nexus~~of ~~analysis.”~~activities ~~Waters~~ that are ~~subject~~similar toin ~~the~~nature ~~significant~~and ~~nexus analysis include non-navigable tributaries~~ that doare ~~not~~determined ~~have relatively permanent flow, wetlands adjacent~~ to ~~non-navigable~~have ~~tributaries~~minimal ~~that~~adverse ~~are~~effects ~~not~~on ~~relatively~~the ~~permanent,~~environment. ~~and~~Permits ~~wetlands~~issued ~~adjacent~~pursuant to ~~but~~Nationwide ~~that~~Permit do21 ~~not~~(“NWP ~~directly~~21”) ~~abut~~generally aauthorize ~~relatively~~the ~~permanent~~disposal ~~non-navigable tributary. We have applied for revised jurisdictional wetland determinations for certain~~ of ~~our~~dredged ~~mines~~or infill ~~Wyoming~~material ~~and~~from ~~Montana. A~~surface ~~Preliminary Jurisdictional Determination was completed on April 22, 2009 for our Antelope~~ coal ~~mine,~~mining ~~finding~~activities ~~that~~into ~~there may be~~ waters of the U.S., ~~on the~~ subject ~~project~~to ~~site~~certain restrictions. WeNWP ~~accepted~~21s ~~the~~are ~~Preliminary~~typically ~~Jurisdictional~~reissued ~~Determination~~for bya ~~letter~~five-year ~~dated~~period ~~July 8,~~and ~~2009. The~~require ~~Corps’~~appropriate ~~decisions~~mitigation, onand ~~our~~permit ~~other~~holders ~~applications~~must ~~are~~receive ~~currently~~explicit ~~pending. Until~~authorization ~~all~~from ~~jurisdictional~~the ~~determinations~~Corps ~~are~~before ~~resolved,~~proceeding ~~our~~with ~~affected~~proposed ~~mines~~mining ~~continue~~activities. The toCorps ~~operate~~reauthorized ~~under~~use ~~their~~of ~~old~~ NWP 21 ~~permits. We~~for ~~believe~~surface ~~that~~coal ~~the~~mines ~~pending~~on ~~jurisdictional~~February 17, ~~wetland~~2012. The ~~determinations~~new ~~are likely to reduce the waters that are currently subject to~~ NWP 21 ~~permitting~~imposes ~~requirements,~~new ~~with~~limits ~~concomitant~~on ~~decreases~~stream inimpacts ~~the cost~~ and ~~time~~prohibits ~~burdens~~valley ~~associated with NWP 21 permit compliance~~fills.

26Because of the U.S. Supreme Court’s divided decision in Rapanos v. United States, there is some regulatory uncertainty about what constitutes a jurisdictional wetland. On March 18, 2010, the Corps made a determination that there are no jurisdictional wetlands at our Spring Creek mine. Similarly, on September 12, 2012, the Corps made a determination of an absence of waters of the U.S. for our Antelope mine. Therefore, the Corps’ authorization of mining activities is not required for currently permitted lands. On March 30, 2011, the Corps authorized proposed operations under NWP 21 for our Cordero Rojo mine. A request to extend this authorization until March 2018 has been filed with the Corps and until received, Cordero is operating under the previous authorization. All jurisdictional determinations are resolved, where applicable. Where there are jurisdictional wetlands, our Wyoming coal mines continue to operate under their respective NWP 21 permits.

Table of Contents

Resource Conservation and Recovery Act

The EPA determined that coal combustion ~~wastes~~residues (“CCR”) do not warrant regulation as hazardous wastes under the Resource Conservation and Recovery Act (“RCRA”) in May 2000. Most state hazardous waste laws ~~also~~do not regulate ~~coal~~CCR ~~combustion wastes~~ as ~~non-~~hazardous wastes. The EPA also concluded that beneficial uses of ~~coal combustion wastes~~CCR, 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~~minefill. There have been several legislative proposals that would require the EPA to further regulate the storage of ~~coal combustion waste~~CCR. Any significant changes in the management of ~~coal~~CCR ~~combustion waste~~ could increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, in June 2010 the EPA released two competing proposals for the regulation of ~~coal combustion byproducts~~CCR. One would regulate the ~~byproducts~~CCR as hazardous or special waste and the other would classify the ~~byproducts~~CCR as non -hazardous waste. ~~A further revised draft is expected to be published late in 2011.~~ IfUnder ~~coal~~both ~~combustion wastes were classified as a special or hazardous waste~~options, ~~regulations~~the ~~may~~EPA ~~impose~~would ~~restrictions~~establish ondam ~~ash~~safety ~~disposal,~~requirements ~~provide~~to ~~specifications~~address ~~for~~the ~~storage~~structural ~~facilities,~~integrity ~~require~~of ~~groundwater~~surface ~~testing~~impoundments ~~and~~to ~~impose~~prevent ~~restrictions~~catastrophic onreleases. The ~~storage~~EPA ~~locations,~~did ~~which~~not ~~could~~address ~~increase~~in ~~our~~the ~~customers’~~proposed ~~operating~~regulations ~~costs and potentially reduce their ability to purchase coal. In addition, contamination caused by~~ the ~~past~~use ~~disposal~~ of ~~coal~~CCR ~~combustion~~as ~~waste~~minefill, ~~including~~but ~~coal~~indicated ~~ash,~~that ~~can~~it ~~lead~~would toseparately ~~material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.~~work

Table of Contents

with the OSM in order to develop effective federal regulations ensuring that such placement is adequately controlled. In April 2012, several environmental organizations filed suit against the EPA to compel the EPA to take action on the proposed rule. On January 29, 2014, the EPA entered into a Consent Decree requiring it to promulgate by December 2014 a final rule addressing the proper disposal of CCR. If the final rule classifies CCR as a special or hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, can lead to material liability for our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

Comprehensive Environmental Response, Compensation and Liability Act

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

Endangered Species Act

The federal Endangered Species Act (the “ESA”) and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (the “USFWS”) works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from mining-related impacts. A number of species indigenous to the areas in which we operate are protected under the ESA, and compliance with ESA requirements could have the effect of prohibiting or delaying us from obtaining mining permits. These requirements may also include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. For example, our Spring Creek coal mine applied for lease modification under the BLM leasing regulations, and the area we were proposing to include was declared ~~critical~~core greater sage-grouse habitat by the Montana Fish, Wildlife and Parks Department. This requires a certain degree of mitigation of the impacts on the habitat in order for us to obtain approval of this lease modification. Similarly, in Wyoming, the Buffalo Field Office of the BLM is engaged in revising its Resource Management Plan (“RMP”) to include additional sage -grouse protective measures in its RMP. ~~Once~~As ~~adopted~~of January 31, ~~this~~2014, ~~plan~~the ~~may~~RMP ~~impose~~and ~~limitations~~the onMontana ~~future~~conservation ~~development~~strategy ~~and/or~~had ~~further~~not ~~mitigation~~yet ~~measures~~been ~~within~~finalized. In ~~sage~~the ~~grouse~~latter ~~habitat~~part of 2011, the BLM released an Instruction Memorandum on ~~lands~~greater ~~administered~~sage-grouse byand ~~the~~formal ~~Buffalo~~planning ~~Field~~processes ~~Office,~~for ~~including~~conservation measures for the ~~PRB~~species. ~~Should~~Additionally, ~~more~~the ~~stringent~~USFWS ~~protective~~is ~~measures~~under bethe ~~applied,~~directives orof ifan ~~the~~agreement ~~USFWS~~to ~~lists~~determine ~~the~~by ~~sage~~2015 whether greater sage-grouse will be listed as a threatened orspecies. These ~~endangered~~actions could result in more stringent requirements being issued by the BLM. Should more stringent protective measures be applied, this could result in increased operating costs, heightened difficulty in obtaining future mining permits, or the need to implement additional mitigation measures. ~~The~~On ~~USFWS~~June 29, ~~published~~2010, the ~~result~~USFWS ofissued ~~its~~a ~~12-month~~notice ~~status~~reinstating ~~review~~the onproposed ~~March~~rule 5,relating ~~2010,~~to ~~determining~~the ~~that~~listing aof ~~listing~~the ismountain ~~warranted~~plover ~~but~~as ~~precluded~~threatened byunder ~~higher~~the ~~priority~~ESA ~~listing~~and ~~actions~~requesting public comment. ~~This~~In ~~finding~~May 2011, ~~imposes~~the noUSFWS ~~legal~~determined ~~obligation~~not to ~~protect~~list the ~~bird. Three~~mountain ~~environmental~~plover ~~groups~~as ~~have~~threatened, ~~filed~~however athe ~~lawsuit~~species ~~against~~status ~~USFWS~~could ~~challenging~~be ~~its~~reviewed ~~failure~~in tothe ~~provide~~future. If ~~ESA~~a ~~protection~~listing determination results, it could lead to ~~the~~new ~~sage~~land ~~grouse. On~~use ~~June 29,~~restrictions ~~2010,~~to ~~the~~protect ~~USFWS~~nesting ~~issued~~plovers ain ~~notice~~Wyoming ~~reinstating~~and ~~the~~Montana. We ~~proposed~~have ~~rule for~~not ~~relating~~determined toits ~~the~~possible ~~listing~~impact ofon ~~the~~our ~~mountain~~operations, ~~plover~~although asa ~~threatened~~listing ~~under~~could ~~the~~adversely ~~ESA~~impact our mining operations and costs.

Table of Contents

requesting public comment. If finalized by May 2011, the threatened species listing could lead to new land use restrictions to protect nesting plovers in Wyoming and Montana. We have not determined its impact on our operations, if any.

Use of Explosives

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

Table of Contents

(including ammonium nitrate at certain threshold levels) are required to complete a screening review. Our mines are low risk, Tier 4 facilities which are not subject to additional security plans. In 2008, the Department of Homeland Security proposed regulation of ammonium nitrate under the ammonium nitrate security rule. Many of the requirements of the rule would be duplicative of those in place under the Bureau of Alcohol Tobacco and Firearms, including registration and background checks. Additional requirements may include tracking and verifications for each transaction related to ammonium nitrate. A final rule is expected to be published in the second quarter of 2014. It is possible that our use of explosives in connection with blasting operations may subject us to the Department of Homeland Security’s new ammonium nitrate security 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, and the Toxic Substance Control Act and transportation laws adopted to ensure the ~~Emergency~~appropriate ~~Planning~~transportation of our coal both nationally and ~~Community~~internationally. Laws, ~~Right-to-Know~~regulations, ~~Act~~and treaties of other countries may also adversely impact our export sales by reducing demand for PRB coal, or coal in general, as a source of power generation in those countries.

Available Information

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

We also make the documents listed above available without charge through our website, www.cloudpeakenergy.com, as soon as practicable after we file or furnish them with the SEC. You may also request copies of the documents, at no cost, by telephone at (720) 566-2900 or by mail at Cloud Peak Energy ~~Resources LLC~~Inc., 385 Interlocken Crescent, Suite 400, Broomfield, Colorado, 80021, Attention: Vice President, Investor Relations. In addition to reports we file or furnish with the SEC, we publicly disclose material information from time to time in our press releases, at annual meetings of stockholders, in publicly accessible conferences and investor presentations, and through our website. The information on our website is not part of this Form 10-K.

Table of Contents

Item 1A. Risk Factors.

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

Risks Related to Our Business and Industry

~~Coal~~A ~~prices are subject to change and a~~ substantial or extended decline in the prices ~~could~~we ~~materially~~receive ~~and~~for ~~adversely affect~~ our ~~revenues~~coal ~~and~~could ~~results~~reduce ofour ~~operations,~~revenue asand ~~well~~profitability asand decrease the value of our coal reserves.

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

· ~~the~~ domestic and foreign supply and demand for coal, including Asian and other foreign demand for ~~U.S.~~PRB coal exports, ~~from~~and ~~eastern~~the ~~U.S.~~impact ~~markets~~of domestic and foreign government energy and tax policies and currency exchange rate fluctuations;

· domestic and foreign demand for electricity;

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

~~· the quantity and quality of coal available from competitors;~~22

Table of Contents

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

· competition for production of electricity from non-coal sources, including the price and availability of alternative fuels, such as natural gas and crude oil, and alternative energy sources, such as nuclear, hydroelectric, wind and solar power, and the effects of technological developments related to these non-coal and alternative energy sources;

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

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

· legislative, regulatory and judicial developments, environmental regulatory changes, or changes in energy and tax policy and energy conservation measures that would adversely affect the coal ~~industry~~or utility industries, such as legislation that limits carbon dioxide or sulfur dioxide emissions or provides for increased funding, ~~and~~subsidies or other incentives for, or mandates the use of, alternative energy sources;

· domestic and foreign governmental regulations and taxes, including with respect to air emission standards for coal-fired power plants, and the ability of coal-fired power plants to meet these standards by installing scrubbers or other means;

· ~~the~~market ~~quantity,~~price ~~quality~~fluctuations ~~and~~for ~~pricing~~sulfur ofdioxide ~~coal~~emission ~~available in the resale market~~allowances;

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

· ~~market~~the ~~price~~other ~~fluctuations~~risks ~~for~~described ~~sulfur~~in ~~dioxide~~this ~~emission~~Item ~~allowances; and~~1A.

~~· subsidies~~A ~~designed~~substantial toor ~~encourage~~extended decline in the ~~use~~prices we receive for our coal due to these or other factors could reduce our revenue and profitability, cash flows, liquidity, and value of ~~alternative~~our ~~energy~~coal ~~sources~~reserves.

ACompetition ~~substantial~~with ordomestic ~~extended~~and ~~decline~~foreign incoal ~~the~~producers ~~prices~~and wewith ~~receive~~producers ~~for~~of ~~our~~natural ~~future~~gas ~~coal~~and ~~sales contracts due to these or~~ other ~~factors~~competing ~~could~~energy ~~materially~~sources ~~and~~may ~~adversely~~negatively affect usour bysales ~~decreasing~~volumes and our ~~revenues,~~ability ~~thereby~~to ~~materially~~sell ~~and~~coal ~~adversely~~at ~~affecting~~a ~~our~~favorable ~~results of operations~~price.

The coal industry is highly competitive. We compete directly with all domestic and many foreign coal producers, and indirectly with other energy producers throughout the U.S. and, for our export sales, internationally. In addition to the price of coal, coal quality, and transportation costs, demand for coal also has a significant impact on our ability to compete domestically and internationally for coal sales. Demand for coal depends upon a number of factors, including:

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

· delivered prices for coal, including the relative costs of transportation, such as ocean freight rates, from our mine site and competing mines;

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

· technological developments;

· environmental, tax, and other governmental policies and regulations, including EPA regulations; and

· currency exchange rate fluctuations impacting our export sales.

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

Table of Contents

In addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas and crude oil. A decline in the price of natural gas, or sustained low natural gas prices, could cause demand for coal to decrease and adversely affect the price of our coal. For example, while the average price of natural gas increased from $3.34 per thousand cubic feet as of December 2012 to $4.24 per thousand cubic feet as of December 2013, we continue to experience fuel switching and decreased coal consumption by electricity-generating utilities. Sustained low natural gas prices may also cause utilities to phase out or close existing coal-fired power plants or reduce construction of any new coal-fired power plants, which could have a material adverse effect on demand and prices received for our coal.

Legislation requiring the use and dispatch of alternative energy sources and fuels or legislation providing financing or incentives to encourage continuing technological advances and deployment in this area could further enable alternative energy sources to become more competitive with coal. If alternative energy sources, such as hydroelectric, wind or solar, become more cost-competitive, demand for coal could decrease and cause a decrease in the price of coal.

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

According to the EIA, the market share of coal used in electric generation is expected to decrease from 40% to 34% from 2013 to 2035 as a result of various factors, including low natural gas prices, regulatory and environmental pressures on coal-fired electricity generation and domestic and foreign economic conditions and associated electricity demand. A growing percentage of our coal sales in recent years has been into export markets in Asia, and we are seeking to make additional export sales to Asia and potentially other international locations. Our ability to maintain our export sales revenue and logistics margins depends on a number of factors, including the existence of sufficient and cost-effective export terminal capacity for the shipment of thermal coal to foreign markets, demand by customers in Asia and in other potential export markets for PRB coal, and the price we receive for our coal and our logistics services.

At present, there is limited terminal capacity for the export of PRB coal to foreign markets. Our access to existing and any future terminal capacity, including the proposed Gateway Pacific Terminal in which we have an option for potential future capacity, may be adversely affected by regulatory and permit requirements, environmental and other legal challenges, public perceptions and resulting political pressures, operational issues at terminals and competition among North American coal producers for access to limited terminal capacity, among other factors. If we fail to maintain terminal capacity, or are denied access to existing or any future terminals for the export of our coal on commercially reasonable terms, or at all, our results from our export transactions will be materially adversely affected.

International customer demand for PRB coal, and the prices those customers may be willing to pay for PRB coal and related transportation services provided by our logistics business, can be affected by a variety of matters, including supplier diversity and security considerations, economic conditions and demand for electricity in the relevant markets, international energy and tax policies and regulatory requirements, and availability and pricing for thermal coal delivered from alternative international coal basins. Further, our export sales are priced relative to the international Newcastle benchmark price index. Fluctuations in this index may be affected by a wide range of international supply and demand factors, including economic conditions, demand for electricity in the relevant markets and availability and pricing for thermal coal delivered from alternative international coal basins. Our export sales may also be negatively impacted by currency exchange rate fluctuations that make coal from other countries more economical than PRB coal. If demand for exports declines or we are unable to secure a favorable price for the export of our coal, our cash flows, profitability, liquidity and results of operations may be materially adversely affected.

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

Table of Contents

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

In recent years, the global economic downturn, particularly with respect to the U.S. economy, and the global financial and credit market disruptions had a negative impact on us and the coal industry generally. For example, the demand for electricity in our target markets decreased during 2009, which led to a decrease in coal consumption by customers. As a result, coal inventory by our customers increased during this time leading to our customers curtailing future orders and causing a decrease in coal prices. In 2009, we also experienced a greater than normal number of customers seeking to reduce the amount of tons taken under existing contracts through contractual remedies, such as force majeure provisions.

Furthermore, because we typically seek to enter into long-term arrangements for the sale of a substantial portion of our coal, the average sales price we receive for our coal may lag behind any general economic recovery. Future economic downturns or further disruptions in the financial and credit markets could negatively impact our business, financial condition and results of operations.

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

Our coal customers primarily use our coal as fuel for electricity generation. Overall economic activity and the associated demands for power by industrial users can have significant effects on overall electricity demand and can be caused by a number of factors. An economic slowdown can significantly slow the growth of electricity demand and could result in reduced demand for coal. For example, declines in the rate of international economic growth in countries such as China, India or other developing countries could impact the demand for U.S. coal. Weather patterns can also greatly affect electricity demand. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increase generating requirements from all sources. Mild temperatures, on the other hand, result in lower electrical demand, which allows generators to choose the sources of power generation when deciding which generation sources to dispatch. For example, the unusually warm winter of 2011/2012 led to low gas heating demand at a time of increasing gas production. This in turn led to low gas prices and substitution of gas for coal. When gas prices rose, this substitution of PRB coal decreased, but not enough to offset the increased utility coal stockpiles during this period, which lead to a reduction in utility coal contracting and depressed coal prices. Decreases in coal demand for these or other reasons could cause downward pressure on coal prices and would negatively impact 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.

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

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

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

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

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

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

Table of Contents

· competition and/or conflicts with other natural resource extraction activities and production within our operating areas, such as coalbed methane extraction or oil and gas development; and

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

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

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

Our profitability depends substantially on our ability to mine, in a timely and cost-effective manner, coal reserves that possess the quality characteristics our customers’ desire. Because our reserves decline as we mine our coal, our future success and growth depend upon our ability to acquire additional coal that is economically recoverable. We primarily acquire additional coal through the federal competitive leasing process, but we also enter into state and private coal leases as well as acquire coal from private third parties. If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted. Our ability to obtain additional coal reserves in the future could also be limited by a number of factors, any of which could impact our business and growth strategy, including:

· the availability of cash we generate from our operations;

· available financing and restrictions under our debt instruments;

· competition from other coal companies for properties;

· lack of suitable acquisition or LBA opportunities; or

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

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

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

The U.S. federal government owns most of the coal in the vicinity of our mines. Accordingly, the federal competitive leasing process is our primary means of acquiring additional reserves. There is no requirement that the federal government must lease its coal. Furthermore, there is no requirement that the federal government must give preference to any LBA applicant which means our bids for federal coal leases may compete with other coal producers’ bids. Over time, federal coal leases have become increasingly more competitive and expensive to obtain, and the review process to submit an LBA for bid continues to lengthen. We expect this trend to continue. The increasing size of potential LBA tracts may make it easier for new mining operators to enter the market on economic terms and may, therefore, increase competition for federal coal leases. Increased opposition from non-governmental organizations and other third parties may also lengthen, delay or complicate the LBA process. In order to win a lease in the LBA process and acquire additional coal, our bid for a coal tract must meet or exceed the fair market value of the coal based on the internal estimates of the BLM, which is not published. Any failure or delay in

Table of Contents

acquiring a coal lease through the LBA process, or the inability to do so on economic terms, could cause our production to decline, materially adversely affecting our business, cash flows and results of operations. For example, the West Antelope II leases we were awarded through the LBA process in 2011 have been subject to legal challenges against the BLM and the Secretary of the Interior by environmental organizations. See Item 3 “Legal Proceedings—West Antelope II LBA Challenges.”

The LBA process also requires us to acquire rights to mine from certain surface owners overlying the coal before the federal government will agree to lease the coal. Surface rights in the PRB are becoming increasingly more difficult and costly to acquire. Certain federal regulations provide a specific class of surface owners, also known as qualified surface owners (“QSO”), with the ability to prohibit the BLM from leasing its coal. For example, in connection with an LBA that we previously nominated for our Cordero Rojo mine, the BLM indicated that certain surface owners satisfy the regulatory definition of QSO. If a QSO owns the land overlying a coal tract, federal laws prohibit us from leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO. This right of QSOs allows them to exercise significant influence over negotiations to acquire surface rights and can delay the LBA process or ultimately prevent the acquisition of coal underlying their surface. If we are unable to successfully negotiate access rights with QSOs at a price and on terms acceptable to us, we may be unable to acquire federal coal leases on land owned by the QSO. Our profitability could be materially adversely affected if the prices to acquire land owned by QSOs increase.

If we are unable to acquire surface rights to access our coal, we may be unable to obtain a permit or otherwise be unable to mine coal we own and may be required to employ expensive techniques to mine around those sections of land we cannot access in order to access other sections of coal reserves.

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

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

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

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

Table of Contents

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

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

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

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

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

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

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

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

· diversion of our management’s attention from other business concerns;

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

· environmental or geological problems in acquired coal properties, including factors that make the coal unsuitable for intended customers (due to ash, heat value, moisture, or contaminants), that make the coal more expensive to mine, or delay our ability to mine;

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

· outstanding permit violations associated with acquired assets;

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

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

· unanticipated liabilities associated with the acquired companies.

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

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

As a mining company, we must obtain a number of permits and licenses from various federal, state and local agencies and regulatory bodies that impose strict regulations on environmental and operational matters in

Table of Contents

connection with our coal operations, including restricting the number of tons we may mine under our air quality permits. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by the regulators, all of which make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing operations, impact the development of future mining operations or restrict the amount of our production. The public, including non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and submit objections to requested permits and EIS prepared in connection with applicable regulatory processes. These groups may also participate in the permitting and licensing process, including bringing citizens’ lawsuits to challenge the issuance of permits, the validity of an EIS or performance of mining activities, which can create delay and uncertainty in acquiring permits and mining the coal underlying our leases. For example, the EIS and other regulatory matters associated with the West Antelope II LBAs were legally challenged by several non-governmental organizations. See Item 3 “Legal Proceedings—West Antelope II LBA Challenges.” If our permits or licenses are not issued or renewed in a timely fashion or at all, or if permits issued or renewed are conditioned in a manner that restricts our ability to efficiently and economically conduct our mining activities, we could suffer a material reduction in our production, an impairment of our mineral rights, and our cash flows or profitability could be materially adversely affected.

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

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

The permitting of new coal-fired power plants has also recently been contested, at times successfully, by state regulators and environmental organizations due to concerns related to GHG emissions from the new plants. Private litigation has also been brought against industry participants based on GHG-related concerns. The U.S. Supreme Court held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, but tort-type liabilities and other GHG-related claims against utilities and energy producers may be asserted. For example, in 2011 residents and property owners along the Mississippi Gulf coast filed litigation against approximately 90 companies in energy, fossil fuels and chemical industries, including PRB and other domestic coal companies, alleging that the defendants caused the emission of GHGs that contributed to global warming, which in turn caused a rise in sea levels and added to the ferocity of Hurricane Katrina in 2005, which combined to destroy the plaintiffs’ property. The lawsuit was dismissed by the Federal District Court in 2012 and the dismissal was affirmed by the Fifth Circuit Court of Appeals in May 2013. However, if other GHG-related litigation is successful, the coal industry and our company may be materially adversely impacted. See Item 1 “Business—Environmental and Other Regulatory Matters—Global Climate Change.”

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

The operations of our customers are subject to extensive environmental regulation particularly with respect to air emissions. For example, CSAPR, if implemented, initially requires 28 states in the Midwest and eastern seaboard of the U.S. to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. On August 21, 2012, the U.S Court of Appeals for the District of Columbia Circuit vacated CSAPR, leaving CAIR in place until the pending legal challenges have been resolved or a replacement rule is finalized. CSAPR is one of a number of significant regulations that the EPA has issued or expects to issue that will impose more stringent requirements relating to air, water and waste controls on electric generating units. These rules include the EPA’s pending new requirements for coal combustion residue

Table of Contents

~~Competition~~(“CCR”) ~~within~~management which may further regulate the handling of wastes from the combustion of coal. In ~~production~~addition, ~~industry~~in ~~and~~March 2013, ~~with~~the ~~producers~~EPA formally adopted a revised final rule to reduce emissions of ~~competing~~toxic ~~energy~~air ~~sources~~pollutants ~~may~~from ~~materially~~power plants. Specifically, these mercury and ~~adversely~~air ~~affect~~toxic ~~our~~standards ~~ability~~(“MATS”) tofor ~~sell~~power plants will reduce emissions from new and existing coal- and oil-fired electric utility steam generating units. Litigation filed with respect to the final MATS rule was still on-going before the District of Columbia Circuit Court at January 31, 2014. The litigation does not include provisions for a ~~favorable~~stay ~~price~~and the timeline for general compliance with the standards remains at March 2015. We continue to evaluate the possible scenarios associated with CSAPR, CCR and MATS and the effects they may have on our business and our results of operations, financial condition or cash flows.

WeConsiderable ~~compete~~uncertainty is associated with ~~numerous~~air ~~other~~emissions ~~coal~~initiatives. New ~~producers~~regulations are in ~~various~~the ~~regions~~process of ~~the~~being ~~U.S.~~developed, ~~for~~and ~~domestic~~many ~~sales. International~~existing ~~demand~~and ~~for~~potential ~~U.S.~~regulatory ~~coal~~initiatives ~~also~~are ~~affects~~subject ~~competition~~to ~~within~~review ~~our~~by ~~industry. The~~federal ~~demand~~or ~~for~~state ~~U.S.~~agencies ~~coal~~or ~~exports~~the ~~depends~~courts. Stringent ~~upon~~air aemissions ~~number~~limitations ofare ~~factors,~~either ~~including~~in ~~the~~place ~~overall~~or ~~demand~~are ~~for~~likely ~~electricity~~to inbe ~~foreign~~imposed ~~markets;~~in ~~currency~~the ~~exchange~~short ~~rates;~~to ~~ocean~~medium ~~freight~~term, ~~rates;~~and ~~weather~~these ~~disruption;~~limitations ~~port~~will ~~and~~likely ~~shipping~~require ~~capacity;~~significant ~~the~~emissions ~~demand~~control expenditures for ~~foreign~~many coal-~~produced~~fired ~~steel~~power plants. As a result, ~~both~~these inpower ~~foreign~~plants ~~markets~~may ~~and~~switch into ~~the~~other ~~U.S.~~fuels ~~market;~~that ~~general~~generate ~~economic~~fewer ~~conditions~~of inthese ~~foreign~~emissions ~~countries;~~or ~~technological~~may ~~developments;~~install ~~and~~more ~~environmental~~effective ~~and~~pollution ~~other~~control ~~governmental~~equipment ~~regulations. Foreign~~that ~~demand~~reduces the need for Ulow-sulfur coal.S. Any switching of fuel sources away from coal, ~~has~~closure ~~increased~~of ~~and~~existing ~~decreased~~coal-fired ~~over~~power ~~the~~plants, ~~last~~or ~~decade~~reduced ~~because~~construction of ~~these~~new ~~factors. Decline~~coal-fired inpower ~~foreign~~plants could have a material adverse effect on demand for, ~~U.S.~~and prices received for, our coal. Alternatively, ~~could~~less ~~cause~~stringent ~~competition~~air ~~among~~emissions ~~coal~~limitations, ~~producers~~particularly ~~for~~related ~~sales~~to insulfur, to the ~~U.S.~~extent toenacted, ~~intensify~~could make low-sulfur coal less attractive, ~~potentially~~which ~~resulting~~could inalso ~~significant~~have ~~additional~~a ~~downward~~material ~~pressure~~adverse effect on ~~domestic~~the ~~coal~~demand for, and prices received for, ~~including~~our incoal. See ~~the~~Item ~~PRB~~1 “Business—Environmental and Other Regulatory Matters—Clean Air Act.”

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

~~Global~~Our ormining ~~U.S.~~operations ~~economic~~are ~~and~~subject ~~market~~to ~~conditions~~extensive ~~may~~federal, ~~have~~state aand ~~material~~local ~~adverse~~environmental, ~~affect~~health onand ~~our~~safety, ~~business~~transportation, ~~financial~~labor ~~condition~~ and ~~results~~other oflaws ~~operations~~and regulations. Examples include those relating to:

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

We· emissions ~~may be unable~~ to ~~obtain,~~air ~~maintain~~and ordischarges ~~renew~~to ~~permits, licenses or leases necessary for our operations, which would materially reduce our production, cash flow and profitability.~~water;

~~Mining~~· plant ~~companies must obtain a number of permits~~ and ~~licenses~~wildlife ~~that impose strict regulations on various environmental and operational matters in connection with coal mining. These include permits and licenses issued by various federal~~protection, ~~state~~including ~~and local agencies and regulatory bodies. The permitting rules, and~~ the ~~interpretations~~potential ofclassification ~~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~~sage-~~governmental~~grouse ~~organizations, anti-mining groups~~ and individuals, have certain statutory rights to comment upon and submit objections to requested permits and environmental impact statements (each an “EIS”) prepared in connection with applicable regulatory processes, and otherwise engage in the ~~permitting~~mountain ~~and~~plover ~~licensing~~as ~~process,~~endangered ~~including bringing citizens’ lawsuits to challenge the issuance of permits, the validity of EIS~~ or ~~performance~~threatened of mining activities. For example, the EIS and other regulatory matters associated with the West Antelope II LBA are being legally challenged by several non-governmental organizations, which could create a delay or uncertainty in acquiring the coal lease. If this or any other permits, licenses or leases are not issued or renewed in a timely fashion or at all, or if permits or leases issued or renewed are conditioned in a manner that restricts our ability to efficientlyspecies;

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

· remediation of contaminated soil, surface and groundwater; and

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

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

MSHA is responsible for monitoring compliance with federal mine health and safety standards at our mines. MSHA has various enforcement tools that it can use, including the issuance of citations resulting in monetary penalties and orders of withdrawal from a mine or part of a mine. Since the April 2010 explosion at Massey Energy Company’s (now Alpha Natural Resources) Upper Big Branch Mine, increased scrutiny has been placed on the mining industry and has had significant impacts on the regulation of mine safety matters at the federal and state levels. For example, federal authorities have announced additional targeted inspections of coal mines to evaluate several safety concerns, including the accumulation of coal dust and the proper ventilation of gases such as methane. Federal authorities are also frequently proposing changes to mine safety rules and regulations which could potentially result in additional or enhanced required safety equipment, more frequent mine inspections, stricter and more thorough enforcement practices and enhanced reporting requirements. Any new environmental and/or health and safety requirements may be replicated in the states in which we operate and could increase our operating costs or otherwise prevent, delay or reduce our planned production, any of which could adversely affect our financial condition, results of operations and cash flows.

Table of Contents

The costs, liabilities and ~~economically~~requirements ~~conduct~~associated ~~our~~with ~~mining~~complying ~~activities,~~with wethese requirements are often significant and time-consuming and may delay commencement or continuation of exploration or production. These factors could ~~suffer~~have a material ~~reduction~~adverse ineffect on our ~~production~~results of operations, cash flows and ~~our~~financial ~~cash~~condition. New ~~flow~~legislation or ~~profitability~~administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations may also require us to change operations significantly or incur increased costs. For example, on November 17, 2011, several environmental groups sued the EPA in Washington federal court to compel the EPA to include coal mines on the list of stationary sources governed by air pollution performance standards. The plaintiffs and the EPA have agreed to stay the litigation to facilitate settlement discussions. Any imposition of air emission standards on coal mines or any other such changes could behave ~~materially~~a material adverse effect on our financial condition and ~~adversely~~results ~~affected~~of operations.

Because ~~most~~ of the ~~coal~~extensive inregulatory ~~the~~environment ~~vicinity~~in ofwhich ~~our~~we ~~mines~~operate, iswe ~~owned~~cannot byassure ~~the~~complete ~~U.S.~~compliance ~~federal~~with ~~government,~~all ~~our~~laws ~~future~~and ~~success~~regulations. Failure ~~and~~to ~~growth~~comply ~~could~~with bethese ~~materially~~laws ~~and~~may ~~adversely~~result ~~affected~~in ifsignificant wecosts ~~are~~to ~~unable~~us to ~~acquire~~correct orsuch ~~are~~violations, ~~delayed~~as inwell ~~the~~as ~~acquisition~~civil ofor ~~additional~~criminal ~~reserves~~penalties ~~through~~and ~~the~~limitations ~~federal~~or ~~competitive~~shutdowns ~~leasing~~of ~~process~~our operations.

~~The~~Federal ~~U.S.~~and ~~federal~~state ~~government~~regulatory ~~owns~~agencies ~~most~~have of the ~~coal~~authority into ~~the~~order ~~vicinity~~any 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 anbe ~~LBA,~~temporarily ~~lease its coal at all~~ or ~~give~~permanently ~~preference~~closed tounder ~~any~~certain ~~LBA applicant~~circumstances, and our bids may compete with other coal producers’ bids in the PRB. In the current coal pricing environment, LBAs are becoming increasingly more competitive and expensive to obtain, and the review process to submit an LBA for bid continues to lengthen. We expect that this trend may continue. The increasing size of potential LBA tracts may make it easier for new mining operators to enter the market on economical terms and may, therefore, increase competition for LBAs. Increased opposition from non-governmental organizations and other third parties may also lengthen, delay or complicate the LBA process. For example, the West Antelope II LBA is subject to pending legal challenges filed in 2010 against the BLM and the Secretary of the Interior by environmental organizations. In order to win a lease in the LBA process and acquire additional coal, our bid for a coal tract must meet or exceed the fair market value of the coal based on the internal estimates of the BLM, which ~~they~~could domaterially ~~not~~adversely ~~publish. We~~affect ~~have maintained a history of timely payments related to~~ our ~~LBAs. If~~ability ~~we are unable~~ to ~~maintain~~meet our ~~“good~~customers’ ~~payer” status, we would be required to seek bonding for any remaining payments~~demands.

~~The~~Federal ~~LBA~~and ~~process~~state ~~also~~regulatory ~~requires~~agencies ushave tothe ~~acquire~~authority ~~rights~~following tosignificant ~~mine~~health ~~from~~and ~~surface~~safety ~~owners~~incidents, ~~overlying~~such ~~the~~as ~~coal~~fatalities, ~~and~~to ~~these~~order ~~rights~~a ~~are~~mine ~~becoming~~to ~~increasingly~~be ~~more~~temporarily ~~difficult~~or ~~and~~permanently ~~costly to acquire~~closed. ~~Certain~~If ~~federal~~this ~~regulations~~were ~~provide~~to ~~a specific class of surface owners~~occur, ~~also~~we ~~known~~may asbe ~~qualified~~required ~~surface~~to ~~owners~~incur ~~(each,~~capital aexpenditures ~~“QSO”), with the ability~~ to ~~prohibit~~re-open the ~~BLM from leasing its coal~~mine. ~~For~~In ~~example,~~the inevent ~~connection~~that ~~with~~these aagencies ~~pending~~order ~~LBA~~the ~~that~~closing weof ~~nominated for~~ our ~~Cordero Rojo mine~~mines, ~~the~~our ~~BLM~~coal ~~has~~sales ~~indicated~~contracts ~~that~~and ~~certain~~our ~~surface~~take-or-pay ~~owners~~contracts ~~satisfy~~related ~~the~~to ~~regulatory~~our ~~definition~~export ofterminals ~~QSO. If~~may apermit ~~QSO~~us ~~owns~~to ~~the~~issue ~~land~~force ~~overlying~~majeure ~~a coal tract~~notices, ~~federal~~which ~~laws~~suspend ~~prohibit~~our usobligations ~~from~~to ~~leasing~~deliver ~~the~~ coal ~~tract~~under ~~without~~these ~~first~~contracts. However, ~~securing~~our ~~surface~~customers ~~rights~~may tochallenge ~~the~~our ~~land,~~issuances orof ~~purchasing~~force ~~the~~majeure ~~surface rights from the QSO~~notices. ~~This~~If ~~right~~these ofchallenges ~~QSOs~~are ~~allows~~successful, ~~them~~we tomay ~~exercise~~have ~~significant influence over negotiations~~ to ~~acquire~~purchase ~~surface~~coal ~~rights~~from ~~and~~third-party ~~can~~sources, ~~delay~~if ~~the~~it ~~LBA~~is ~~process~~available, orto ~~ultimately~~fulfill ~~prevent~~these ~~the~~obligations, ~~acquisition~~incur ofcapital anexpenditures ~~LBA. If~~to were-open ~~are~~the ~~unable~~mines toand/or ~~successfully~~ negotiate ~~access~~settlements ~~rights~~ with ~~QSOs~~the atcustomers, awhich ~~price~~may ~~and~~include onprice ~~terms~~reductions, ~~acceptable~~the toreduction ~~us,~~of wecommitments ~~may~~or bethe ~~unable~~extension toof ~~acquire~~time ~~LBAs~~ for ~~coal~~delivery onor ~~land~~terminate ~~owned~~customers’ ~~by the QSO~~contracts. IfAny ~~the~~of ~~prices~~these toactions ~~acquire~~could ~~land~~have ~~owned~~a bymaterial ~~QSOs~~adverse ~~increase,~~effect iton ~~could~~our ~~materially~~business and ~~adversely~~results ~~affect~~of ~~our profitability~~operations.

~~Excess~~Our ~~production~~operations ~~and~~may ~~production~~affect ~~capacity in~~ the ~~coal~~environment ~~industry~~or ~~could~~cause ~~put~~exposure ~~downward~~to ~~pressure~~hazardous onsubstances, ~~coal~~and ~~prices~~our ~~and,~~properties asmay ahave ~~result~~environmental contamination, ~~materially~~any ~~and~~of ~~adversely~~which ~~affect~~could ~~our~~result ~~revenues~~in ~~and~~material ~~profitability~~liabilities to us.

~~During~~Our ~~the~~operations ~~mid-1970s~~use hazardous materials and ~~early~~generate ~~1980s~~hazardous and non-hazardous wastes. In addition, ~~increased~~many ~~demand~~of ~~for~~the ~~coal~~locations ~~attracted~~that ~~new~~we ~~investors~~own, tolease ~~the~~or operate were used for coal ~~industry~~mining inand/or involved the ~~PRB~~generation, ~~spurred~~use, ~~the~~storage ~~development~~and disposal of ~~new~~hazardous ~~mines~~substances ~~and~~either ~~resulted~~before inor ~~additional~~after ~~production~~we ~~capacity~~were ~~throughout~~involved ~~the~~with ~~industry,~~these ~~all~~locations. We ofmay ~~which~~be ~~led~~subject to ~~increased~~claims ~~competition~~under federal and ~~lower~~state ~~coal~~statutes ~~prices. Increases~~and/or incommon ~~coal~~law ~~prices~~doctrines ~~during~~for ~~recent~~toxic ~~periods~~torts, ~~encouraged~~natural resource damages and other damages, as well as for the ~~development~~investigation and cleanup of ~~expanded~~soil, ~~capacity~~surface bywater, ~~coal~~groundwater ~~producers~~and other media. ~~Some~~ These claims may arise, for example, out of ~~these~~current ~~planned~~or ~~capacity~~former ~~increases~~conditions ~~and~~at ~~existing~~sites ~~production~~that ~~plans~~we ~~were~~own, ~~delayed~~lease or ~~reduced~~operate ~~due~~currently, toas ~~coal~~well ~~price~~as ~~reductions~~at ~~since~~sites ~~mid-2008~~that ~~and~~we ~~the~~or ~~concurrent~~predecessor ~~global~~entities ~~economic~~owned, ~~downturn. However~~leased or operated in the past, ~~these~~and ~~capacity~~at ~~increases~~contaminated ~~may~~third-party besites ~~restarted~~at which we have disposed of hazardous substances and waste. ~~Any~~As ~~overcapacity~~a matter of law, and ~~increased~~despite ~~production~~any incontractual indemnity or allocation arrangements or acquisition agreements to the ~~future~~contrary, ~~could~~our ~~materially~~liability ~~reduce~~for ~~coal~~these ~~prices~~claims may be joint and, ~~therefore~~several, ~~materially~~so ~~reduce~~that we may be held responsible for more than our ~~revenues~~share ~~and~~of ~~profitability~~any contamination, or even for the entire share.

~~Our~~We ~~coal~~may ~~mining~~incur ~~operations~~material ~~are~~costs ~~subject~~and liabilities resulting from claims for damage to ~~operating~~property ~~risks,~~or ~~which~~injury ~~could~~to ~~result~~persons inarising ~~materially~~from ~~increased~~our ~~operating~~operations. If ~~expenses~~we ~~and~~are ~~decreased~~pursued ~~production~~for ~~levels~~sanctions, costs and ~~could~~liabilities ~~materially~~in respect of these matters, our mining operations and, ~~adversely~~as ~~affect~~a result, our ~~results~~profitability ofcould ~~operations~~be materially adversely affected.

WeSignificant ~~mine~~increases ~~coal at surface mining operations located~~ in ~~Wyoming~~taxes ~~and Montana. Our coal mining operations are subject to a number of operating risks. Because~~ we ~~maintain~~pay ~~very~~on ~~little~~the ~~produced~~ coal ~~inventory~~we produce, ~~certain~~such ~~conditions~~as royalties or ~~events~~severance ~~could~~and ~~disrupt~~production ~~operations~~taxes, ~~adversely~~including ~~affect~~as ~~production~~a ~~and~~result ~~shipments and increase the cost~~ of ~~mining~~governmental ataudits ~~particular~~or ~~mines~~regulatory ~~for~~or ~~varying~~interpretive ~~lengths of time~~changes, ~~which~~ could ~~have~~materially aadversely ~~material~~affect ~~adverse effect on~~ our ~~results of operations~~profitability. ~~These conditions and events include, among others:~~

~~· poor~~We ~~mining~~pay ~~conditions~~federal, ~~resulting~~state ~~from~~and ~~geological~~private royalties and federal, ~~hydrologic~~state orand ~~other~~county ~~conditions~~severance and production taxes on the coal we sell. A substantial portion of our royalties and severance and production taxes are levied as a percentage of gross revenue with the remaining levied on a per ton basis. For example, ~~which~~we ~~may~~pay ~~cause~~production ~~instability~~royalties of ~~highwalls~~12.5% orof ~~spoil-piles~~gross orproceeds ~~cause~~to ~~damage~~the federal government on all coal sold at the mine sites. We incurred royalties and severance and production taxes totaling $327.9 million and $352.2 million for the years ended December 31, 2013 and 2012, respectively. The calculations used to ~~nearby~~determine ~~infrastructure;~~royalty or severance and production tax payments can be complex

Table of Contents

~~· mining~~and subject to interpretation, making it difficult in some cases to estimate such payments. If royalties or severance and ~~plant~~production ~~equipment~~tax ~~failures~~rates were to significantly increase, or if the methodology by which the government agencies assess royalties or severance and ~~unexpected~~production ~~maintenance~~tax ~~problems;~~rates (including with respect to non-arms’ length sales) materially changes, our results of operations could be materially adversely affected. Examples of this could include:

· ~~adverse~~ if ~~weather~~the ~~and~~federal ~~natural~~government ~~disasters,~~were ~~such~~to asmaterially ~~heavy~~alter ~~rains,~~the ~~flooding~~method ~~and~~for ~~other~~valuing ~~natural~~royalty ~~events~~payments ~~affecting~~for ~~operations~~our non-arms’ length sales, ~~transportation~~our orprofitability ~~customers~~and cash flows could be materially adversely affected;

· ~~the~~ if ~~unavailability~~a ofstate ~~raw~~government ~~materials,~~were ~~equipment~~to ~~(including~~increase ~~heavy~~this ~~mobile~~tax ~~equipment)~~ or any other ~~critical~~tax ~~supplies~~applicable ~~such~~to asour ~~tires~~operations ~~and~~in ~~explosives,~~that ~~fuel~~state, ~~lubricants~~our ~~and~~profitability ~~other~~could ~~consumables~~be ofreduced ~~the type, quantity~~ and~~/or~~ ~~size~~our ~~needed~~results toof ~~meet~~operations ~~production~~negatively ~~expectations~~affected; and

· ~~the~~ if ~~capacity~~we ~~of,~~are ~~and~~required ~~proximity~~ to, ~~rail~~make ~~transportation~~additional ~~facilities~~payments (including related interest and ~~rail~~penalties) ~~transportation~~as ~~delays~~a result of pending or ~~interruptions~~future governmental audits, ~~including~~our ~~derailments;~~results of operations would be negatively impacted.

~~· delays,~~Failure ~~challenges~~to maintain our surety bonds on acceptable terms could affect our ability to, ~~and~~secure ~~difficulties~~reclamation inand ~~acquiring,~~coal ~~maintaining~~lease orobligations ~~renewing~~and ~~necessary~~materially ~~permits,~~adversely ~~including~~affect ~~environmental~~our ~~permits,~~ability orto ~~mining~~mine or ~~surface~~lease ~~rights;~~coal.

~~· delays~~Federal orand ~~difficulties~~state ~~in,~~laws require us to secure the ~~unavailability~~performance of certain long-term obligations, orsuch ~~unexpected~~as ~~increases~~mine inclosure ~~the~~costs, ~~cost~~reclamation costs, and federal and state workers’ compensation costs, including black lung. The primary methods we use to meet those obligations are to provide a third-party surety bond or a letter of ~~acquiring~~credit. As of December 31, ~~developing~~2013, we had outstanding surety bonds with third parties of $677.5 million. Surety bonds are typically renewable on a yearly basis. Surety bond issuers and ~~permitting~~holders ~~new~~may ~~LBA~~not ~~acquisitions~~continue ~~from~~to renew the ~~federal~~bonds ~~government~~or ~~and~~may ~~other~~demand ~~new~~additional ~~mining~~collateral, ~~reserves~~unfavorable terms or higher fees upon those renewals. Our failure to retain, or inability to acquire, surety bonds or letters of credit or to provide a suitable alternative could adversely affect our ability to mine or lease coal, which would materially adversely affect our business and ~~surface~~results ~~rights~~of operations. That failure could result from a variety of factors, including ~~challenges~~lack of availability, higher expense or unfavorable market terms, the exercise by ~~non~~third-~~governmental~~party orsurety ~~environmental~~bond ~~organizations~~issuers orof ~~other~~their right to refuse to renew the surety bonds and restrictions on availability of collateral for current and future third-party ~~parties;~~surety bond issuers under the terms of any credit arrangements then in place.

~~· competition~~Furthermore, ~~and/or~~while ~~conflicts~~we ~~with~~have ~~other~~maintained ~~natural~~a ~~resource~~history ~~extraction~~of ~~activities~~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, which could adversely impact our cash flows and ~~production~~the ~~within~~amount of availability under our ~~operating~~credit ~~areas~~facility, if such asbonds ~~coalbed~~could ~~methane~~be ~~extraction~~obtained orat ~~oil~~all. In addition, the BLM has proposed rule changes pursuant to the 2005 Energy Policy Act that, among other things, would require a 5-year history to take advantage of bonus bid bonding waivers for lessees with favorable histories of timely payments of bonus bids and ~~gas~~royalties, ~~development;~~which could result in a requirement for our company to provide lease bonus bid bonds.

~~· a~~In ~~major~~addition, ~~incident~~if atfederal aor ~~mine~~state ~~site~~laws ~~that~~are ~~causes~~amended ~~all~~to orrequire ~~part~~certain forms of ~~the~~financial ~~operations~~assurance other than surety bonds, such as letters of credit, obtaining them, if we could obtain them at all, could have a ~~mine~~material tonegative ~~cease~~impact ~~for~~on ~~some~~our ~~period~~liquidity and results of ~~time;~~operations.

~~· current~~The availability and ~~future~~reliability ~~health,~~of ~~safety~~sufficient ~~and~~transportation ~~environmental~~capacity ~~regulations~~and orincreases ~~changes~~ in ~~interpretations~~transportation ofcosts ~~current~~could ~~regulations,~~materially ~~including~~adversely affect the ~~classification~~demand offor ~~plant~~our ~~and~~coal ~~animal~~or ~~species~~impair ~~near~~ our ~~mines,~~ability ~~including~~to ~~the~~supply ~~potential~~coal ~~listing~~to ofour ~~the~~domestic ~~sage grouse~~ and ~~the~~export ~~mountain plover, as endangered or threatened species;~~customers.

~~· inability~~Transportation tocosts ~~acquire~~represent ora ~~maintain~~significant ~~adequate~~portion ~~financial~~of ~~sureties~~the total cost of coal for ~~mining~~our domestic and ~~reclamation~~export ~~purposes~~customers. The cost and availability of transportation is a key factor in a customer’s purchasing decision and impacts our coal sales and the price we receive for our coal. Coal could become a less competitive source of energy if the costs of transportation increase or tothe ~~meet~~availability ~~other~~or ~~governmental~~capacity of rail lines or ~~private~~export ~~bonding~~terminals ~~requirements;~~is insufficient. Transportation costs and availability could also make our coal less competitive than coal produced from other regions.

~~· the~~Our ~~value~~ability ofto ~~the~~sell Ucoal to our customers depends primarily upon third-party rail systems and export terminals.S. If ~~dollar~~our ~~relative~~customers are unable to ~~other~~obtain ~~currencies~~transportation services, ~~particularly~~or ~~where~~to ~~imported~~do ~~products~~so on a cost-effective basis, our business and growth strategy could be adversely affected. Alternative transportation and delivery systems are ~~required~~generally ~~for~~inadequate and not suitable to handle the ~~mining~~quantity ~~process~~of our shipments or to ensure timely delivery to our customers. Export terminals, ~~such~~including asthe ~~tires~~proposed Gateway Pacific Terminal in which we have an option for potential future capacity, are also subject to permit requirements and ~~petroleum~~challenges ~~products.~~from environmental

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

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

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

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

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

Table of Contents

~~according~~organizations which may make it complicated or expensive to ~~the~~expand Uexisting terminal capacity or open new export terminals in a timely and cost-effective manner.S. In ~~Energy~~addition, ~~Information~~much ~~Administration~~of (the ~~“EIA”)~~PRB is served by two rail carriers, and the northern PRB is only serviced by one rail carrier. The ~~amount~~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 ~~consumed~~and ~~for~~resulting Uin materially decreased revenue.S Similarly, being denied access to an export terminal could significantly affect our export sales, materially decreasing our revenue. Our ~~electric~~ability ~~power~~to ~~generation~~open isnew mines or expand existing mines may also be affected by the access to, ~~among~~and availability and cost of rail, export terminal or other ~~things:~~transportation systems available for servicing these mines.

· Typically, our mine customers contract for, and pay directly for, transportation of coal from the ~~location~~mine or port to the point of use. However, ~~availability~~for contracts with our logistics customers, ~~quality~~we are required to enter into transportation agreements pursuant to which we arrange and ~~price~~pay offor ~~alternative~~all ~~energy~~rail ~~sources~~transport, terminal, and for ~~power~~our ~~generation~~international customers, ~~such~~demurrage ascharges. As ~~natural~~the ~~gas~~volume of deliveries coordinated to customer contracted destinations increases, so do our costs. Our ability to supply coal to our customers and our customers’ ability to take our coal may be impacted by the disruption of these transportation services because of weather-related problems; mechanical difficulties; maintenance shut-downs; environmental, political and regulatory issues; train derailment; bridge or structural concerns; infrastructure damage, whether caused by ground instability, accidents or otherwise; strikes; lock-outs; lack of fuel ~~oil~~or maintenance items; fuel costs; accidents; terrorism or domestic catastrophe or other events. For example, ~~nuclear~~in the spring and summer of 2011, ~~hydroelectric~~the Midwest region experienced severe flooding which disrupted rail service to mines in the PRB and affected the ability of those customers who were impacted by the flooding to take coal deliveries. In the three months ended December 31, ~~wind~~2013, we also experienced increased competition for rail crews from crude oil and ~~solar~~grain ~~power;~~shipments that negatively impacted our shipments and financial results. Any similar disruption in the future could negatively impact our results of operations.

~~· technological~~Our ~~developments,~~business ~~including~~requires ~~those~~substantial ~~related~~capital toexpenditures, ~~alternative~~which ~~energy~~we ~~sources;~~may ~~and~~be unable to provide.

~~· subsidies~~Our orbusiness ~~legal~~plan ~~mandates~~and ~~designed~~strategy toare ~~encourage~~dependent ~~the~~upon ~~use~~our acquisitions of ~~alternative~~additional ~~energy~~reserves, ~~sources~~which require substantial capital expenditures. We also require capital for, among other purposes:

~~Gas-fired~~· acquisition ~~generation has the potential to displace coal-fired generation, particularly from older, less efficient coal-powered generators. We expect that many~~ of ~~the~~surface new power plants needed to meet increasing demand for domestic electricity generation will be fired by natural gas, because gas-fired plants are cheaper to construct, and permits to construct these plants are easier to obtain as natural gas is seen as having a lower environmental impact than coal-fired generators. In recent periods, governmental regulators at the federal, state and local levels have shown increased interest in limiting greenhouse gas (“GHG”) emissions. This has resulted in increased regulation of coal mining and of coal-fired power plants and other end-users of coal, increasing the cost of burning coal compared to alternative energy sources. In addition, environmental activists concerned with climate change issues have attempted to use the regulatory and judicial processes to block the construction of new coal-fired power plants or capacity expansions to existing plants. Further, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal. Many states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard. Although none of these federal proposals have been enacted to date, the current Administration has indicated its support for a federal renewable energy standard as part of energy and climate change legislative initiatives. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by U.S. electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.rights;

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

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

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

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

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

To the extent that cash on hand, cash generated internally and cash available under our credit facility are not sufficient to fund capital requirements, we will require additional debt and/or equity financing. However, additional debt or equity financing may not be available to us or, if available, may not be available on satisfactory terms. Additionally, our debt instruments may restrict our ability to obtain such financing. If we are unable to obtain additional capital, we may not be able to maintain or increase our existing production rates and we could be forced to reduce or delay capital expenditures or change our business strategy, sell assets or restructure or refinance our indebtedness, all of which could have a material adverse effect on our business or financial condition.

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

SMCRA and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining. We accrue for the costs of current mine disturbance and final mine closure. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our experience. Estimates of reclamation liability at the Decker mine are provided to us by the Decker mine. The amounts recorded are dependent upon a number of variables, including the estimated future asset retirement costs, estimated proven reserves, assumptions involving profit margins of third-party contractors, inflation rates, discount

Table of Contents

~~· State~~rates and ~~regional~~assumed ~~climate change initiatives intended to limit or affect the emission of GHG emissions from certain sources~~credit-adjusted, ~~such as the Regional Greenhouse Gas Initiative covering certain northeastern and mid~~risk-~~Atlantic~~free ~~states~~rates. Furthermore, ~~the~~these ~~Western~~obligations ~~Climate~~are ~~Initiative,~~unfunded. If ~~the~~our ~~Midwestern~~accruals ~~Greenhouse~~are ~~Gas~~insufficient ~~Reduction~~or ~~Accord~~our ~~and~~liability ~~the~~in ~~California~~a ~~Global~~particular ~~Warming~~year ~~Solutions~~is ~~Act,~~greater ~~either~~than ~~have~~currently ~~already~~anticipated, ~~taken~~our ~~effect~~future oroperating ~~may~~results ~~take~~could ~~effect~~be inmaterially ~~the~~adversely ~~foreseeable future~~affected.

~~· The~~We ~~State~~do not operate the Decker mine and our results of ~~California~~operations ~~approved~~could abe ~~fee~~adversely affected if the other 50% owner fails to beeffectively ~~paid~~operate bythe ~~certain~~mine ~~emitters~~or offails ~~GHGs~~to perform its obligations. In addition, ~~and~~our ~~other~~credit ~~jurisdictions~~arrangements ~~have~~may orlimit ~~are~~our ~~also~~ability ~~considering~~to ~~imposing~~contribute ~~similar~~cash ~~fees~~to orthe ~~taxes~~Decker mine.

~~The~~We ~~permitting~~hold ofa ~~new~~50% ~~coal~~non-~~fired~~operating ~~power~~interest ~~plants~~in ~~has~~the ~~also~~Decker ~~recently~~mine ~~been~~in ~~contested,~~Montana atthrough ~~times~~a ~~successfully,~~joint byventure ~~state~~agreement ~~regulators~~with ~~and~~the ~~environmental~~other ~~organizations~~50% ~~due~~owner. The toother ~~concerns~~50% ~~related~~mine toowner ~~GHG~~has ~~emissions~~responsibility ~~from~~for the ~~new~~day-to-day ~~plants~~operations of the Decker mine. ~~Additionally,~~While atwe ~~least~~participate ~~one~~in ~~U.S.~~the ~~federal~~management ~~appeals~~committee ~~court~~of ~~reinstated~~the aDecker ~~lawsuit~~mine ~~permitting~~under ~~individuals,~~the ~~state~~terms ~~attorneys~~of ~~general~~the ~~and~~joint ~~others~~venture toagreement, ~~pursue~~we ~~claims~~do ~~against~~not ~~industrial~~control, ~~companies~~and onour employees do not participate in, the ~~basis~~day-to-day ~~that~~operations ~~they~~of ~~have~~the ~~created~~Decker amine. If ~~public~~the ~~nuisance~~other ~~due~~50% tomine ~~their~~owner ~~emissions~~fails ofto ~~carbon~~operate ~~dioxide~~the ~~and~~Decker ~~its~~mine ~~alleged~~effectively, ~~effects~~our onresults ~~climate~~of ~~(e.g. sea~~operations ~~level~~could ~~and~~be ~~storm~~adversely ~~severity)~~affected.

~~Climate~~We ~~change~~share ~~initiatives~~the profits, losses, operating expenses, reclamation obligations and ~~other~~liabilities ~~efforts~~and toassets ~~reduce~~associated ~~GHG~~with ~~emissions~~the ~~like~~Decker ~~those~~mine ~~described~~equally ~~above~~with orthe ~~otherwise~~other 50% owner and may ~~require~~be ~~additional~~required ~~controls~~to oncontribute ~~coal-fired~~cash ~~power~~or ~~plants~~other property and ~~industrial~~equipment ~~boilers~~and ~~may~~our ~~cause~~proportional ~~some~~share ~~users~~ of ~~coal~~funds to ~~switch~~carry ~~from~~on ~~coal~~the tobusiness aof ~~lower~~the ~~carbon~~joint ~~fuel~~venture ~~and~~or ~~may~~to ~~result~~cover inliabilities. In the ~~closure~~event that either 50% owner does not contribute its share of ~~coal-fired~~operating ~~power~~expenses, ~~plants~~including reclamation expenses when due, or inother ~~reduced~~liabilities, ~~construction~~the ofother ~~new~~owner ~~plants~~is not required to assume their obligation. ~~Any~~However, ~~switching~~we may have joint and several liability as a matter of ~~fuel~~law ~~sources~~for ~~away~~these ~~from~~expenses ~~coal~~and other liabilities, ~~closure~~including for operational liabilities. Accordingly, our financial obligations with respect to the Decker mine are subject to the creditworthiness of ~~existing~~the ~~coal-fired~~other ~~power~~50% ~~plants~~owner, which is outside of our control. For example, an October 2013 audit report related to the other 50% owner’s ultimate parent company stated that if planned funding or ~~reduced~~alternative ~~construction~~sources of ~~new~~capital ~~coal-fired~~are ~~power~~not ~~plants~~obtained, ~~could~~there ~~have~~exists a material ~~adverse~~uncertainty ~~effect~~whether onAmbre ~~demand~~Energy ~~for~~Limited and ~~prices~~its ~~received~~controlled ~~for~~entities would be able to continue as a going concern. In addition, if we do not provide our ~~coal~~proportional share or the other 50% owner does not provide its proportional share, our interest in the Decker mine may be adjusted proportionally. CPE Resources’s current debt instruments and future credit arrangements may limit our ability to make contributions to the Decker joint venture.

~~Our~~Increases ~~business~~in ~~requires~~the ~~substantial~~cost ~~capital~~of ~~investment~~raw materials and ~~maintenance~~other ~~expenditures~~industrial supplies, ~~which~~or wethe ~~may~~inability beto ~~unable~~obtain toa ~~provide~~sufficient quantity of those supplies, could increase our operating expenses, disrupt or delay our production and materially adversely affect our profitability.

~~Our~~We ~~business~~use ~~plan~~considerable ~~and~~quantities ~~strategy~~of ~~are~~explosives, ~~dependent~~petroleum-based ~~upon~~fuels, ~~our~~tires, ~~acquisitions~~steel ofand ~~additional~~other ~~reserves~~raw materials, ~~which~~as ~~require~~well ~~substantial~~as ~~capital~~spare ~~expenditures~~parts toand ~~acquire~~other ~~additional~~consumables ~~coal~~in ~~leases~~the mining process. WeIf ~~also~~the ~~require~~prices ~~capital~~of ~~for~~steel, ~~among~~explosives, ~~other purposes~~tires, ~~acquisition~~petroleum ofproducts ~~surface~~or ~~rights,~~other ~~equipment~~materials ~~and~~increase significantly or if the ~~development~~value of ~~our~~the ~~mining~~U.S. ~~operations,~~dollar ~~capital~~declines ~~renovations,~~relative ~~maintenance~~to ~~and~~foreign ~~expansions~~currencies ofwith ~~plants~~respect ~~and~~to ~~equipment~~certain ~~and~~imported ~~compliance~~supplies ~~with~~or ~~environmental~~other ~~laws~~products, ~~and~~our ~~regulations~~operating expenses will increase, which could materially adversely impact our profitability. ToAdditionally, ~~the~~a ~~extent~~limited ~~that~~number ~~cash~~of onsuppliers ~~hand~~exist for certain supplies, ~~cash~~such ~~generated~~as ~~internally~~explosives and ~~cash~~tires, ~~available~~as ~~under~~well as certain mining equipment, and any of our ~~credit~~suppliers ~~facility~~may ~~are~~divert ~~not~~their ~~sufficient~~products to ~~fund~~buyers ~~capital~~in ~~requirements,~~other wemines ~~will~~or ~~require~~industries ~~additional~~or ~~debt~~divert ~~and/or~~their ~~equity~~raw ~~financing~~materials to produce other products that have a higher profit margin. ~~However~~For example, ~~additional~~we ~~debt~~previously orexperienced ~~equity~~a ~~financing~~severe ~~may~~tire ~~not~~shortage bein ~~available~~2005 tothat uslasted ~~or,~~several ifyears. This ~~available,~~tire ~~may~~shortage ~~not~~increased bethe ~~available~~direct oncost ~~satisfactory~~of ~~terms. Additionally,~~tires ~~our~~and ~~debt~~caused ~~instruments~~us ~~may~~to ~~restrict~~change our ~~ability~~operating practices to ~~obtain~~increase ~~such~~tire ~~financing~~life. IfShortages wein ~~are~~raw ~~unable~~materials toused ~~obtain~~in ~~additional~~the ~~capital~~manufacturing of supplies and mining equipment, wewhich, ~~may~~in ~~not~~some becases, ~~able~~do tonot ~~maintain~~have ready substitutes, or ~~increase~~the cancellation of our ~~existing~~supply ~~production~~contracts ~~rates~~under ~~and~~which we obtain these raw materials and other consumables, could belimit ~~forced~~our ability to ~~reduce~~obtain these supplies or ~~delay~~equipment. As ~~capital~~a ~~expenditures~~result, orwe ~~change~~may ~~our~~not ~~business~~be ~~strategy,~~able ~~sell~~to ~~assets~~acquire oradequate ~~restructure~~replacements for these supplies or ~~refinance~~equipment ~~our~~on ~~indebtedness,~~a ~~all~~cost-effective ofbasis or at all, which could ~~have~~also amaterially ~~material~~increase ~~adverse~~our ~~effect~~operating onexpenses ~~our~~or ~~business~~halt, disrupt or ~~financial~~delay ~~condition~~our production.

IfFurthermore, weoperating expenses at our mining locations are ~~unable~~sensitive to ~~acquire~~changes orin ~~develop~~certain ~~additional~~variable ~~coal~~costs, ~~reserves~~particularly ~~that~~diesel ~~are~~fuel ~~economically recoverable~~prices, which is our largest variable cost after personnel costs. Our profitability depends on our ability to adequately control our costs, particularly with respect to diesel fuel. 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 ~~future~~Analysis ~~success~~of Financial Condition and ~~growth~~Results ~~may~~of beOperations—Cost ~~materially~~of Product Sold” and ~~adversely~~Item ~~affected~~7A”Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risks.”

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

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

Table of Contents

IfOur wehedging ~~are~~activities ~~unable~~for todiesel ~~acquire~~fuel ~~surface rights to access our coal, we~~ may beprevent ~~unable~~us tofrom ~~obtain~~benefiting afrom ~~permit~~cost toprice 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 operationsdecreases.

~~After~~We weenter ~~acquire~~into ~~coal~~hedging ~~through~~arrangements in the ~~LBA~~form ~~process~~of orcostless ~~otherwise,~~collars wefor ~~are required to obtain~~ a ~~permit~~portion toof ~~mine~~our ~~the~~anticipated ~~coal~~diesel ~~through~~fuel ~~the applicable state agencies prior to mining the acquired coal~~needs. InThese ~~part,~~costless ~~the~~collars ~~permitting~~are ~~requirements~~designed ~~provide~~to ~~that,~~help ~~under~~manage ~~certain~~our ~~circumstances,~~exposure weto ~~must~~extreme ~~obtain~~market ~~surface~~changes ~~owner~~to ~~consent~~our ifdiesel ~~the~~fuel ~~surface estate has been split from the mineral estate, which is commonly known as a “split estate~~costs.” The Wecollars ~~have~~are inindexed ~~the past and may in the future be required~~ to ~~negotiate with multiple parties for~~ the ~~surface~~WTI ~~access~~crude ~~that~~oil ~~overlies~~price ~~coal~~as wequoted ~~acquired~~on ~~through~~ the ~~LBA~~New ~~process~~York orMercantile ~~otherwise~~Exchange. IfAs wesuch, ~~are~~the ~~unable~~nature ~~to successfully negotiate surface access with any~~ of ~~these~~the ~~surface~~collar ~~owners,~~does ornot dodirectly sooffset onmarket ~~commercially~~changes ~~reasonable terms, we may be denied a permit~~ to ~~mine some of~~ our ~~coal~~diesel orfuel ~~may find that we cannot mine the coal at a profit~~costs. IfUnder ~~we are denied~~ a ~~permit~~collar agreement, ~~this~~we ~~would~~pay ~~create~~the ~~significant~~difference ~~delays~~between inthe ~~our~~index ~~mining~~price ~~operations~~ and ~~materially~~a ~~and~~floor ~~adversely~~price ~~impact~~if ~~our~~the ~~business~~index ~~and~~price ~~results~~is ofbelow ~~operations. Furthermore~~the floor, ifand we ~~determine~~receive tothe ~~alter~~difference ~~our~~between ~~plans~~the toceiling ~~mine~~price ~~around~~and the ~~affected~~index ~~areas,~~price weif ~~could~~the ~~incur~~index ~~significant~~price ~~additional~~is ~~costs~~above tothe doceiling ~~so,~~price. No ~~which~~amounts ~~could~~are ~~increase~~paid ~~our~~or ~~operating~~received ~~expenses~~if ~~considerably~~the ~~and~~index ~~could~~price ~~materially~~is ~~and~~between ~~adversely~~the ~~affect~~floor ~~our~~and ~~results~~ceiling ~~of operations~~prices.

WeAs ~~may~~of beDecember 31, ~~unable~~2013, towe ~~acquire~~had ~~state~~approximately ~~leases~~76% of our diesel fuel needs for ~~coal,~~2014 orhedged tounder docostless socollars. While onour ahedging ~~cost-effective~~strategy ~~basis~~provides us protection in the event of extreme crude oil price increases, ~~which~~it ~~could~~may ~~materially~~also ~~and~~prevent ~~adversely~~us ~~affect~~from benefiting if crude oil prices decrease below our ~~business~~floor. See ~~strategy~~Item 7A “Quantitative and ~~growth~~Qualitative ~~plans~~Disclosures About Market Risk—Commodity Price Risks” and Note 6 of Notes to Consolidated Financial Statements in Item 8.

WeOur ~~acquire~~hedging aactivities ~~small~~for ~~percentage of our~~ coal ~~through~~sales ~~state~~prices ~~leasing~~may ~~processes. Nearly~~result ~~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~~negative ~~basis,~~impact ~~our~~from ~~business~~sales ~~strategy~~price ~~could be adversely affected~~changes. ~~We do not typically acquire state leases in Montana significantly in advance of mining operations due to the complexity of the leasing process in Montana.~~

~~Extensive~~As ~~environmental~~part ~~regulations~~of our logistics business, ~~including~~we ~~existing~~enter ~~and~~into ~~potential~~derivative financial instruments in the form of international coal forward contracts to help manage our exposure to future ~~regulatory~~coal ~~requirements~~sales ~~relating~~prices by fixing a price now for a future contracted coal delivery. This type of hedge is designed to ~~air~~protect ~~emissions,~~us ~~affect~~from any price decreases. While our ~~customers~~hedging ~~and~~strategy ~~could~~provides ~~reduce~~us some degree of protection in the ~~demand~~event ~~for~~future coal asprices adecrease ~~fuel~~it ~~source~~may ~~and~~also ~~cause~~prevent us from benefiting if future coal prices ~~and~~increase ~~sales~~above our hedged price. As of ~~our~~December 31, 2013, we had coal toforward ~~materially~~contracts ~~decline~~for approximately 2.0 million tons, which will settle between 2014 and 2016.

~~The~~In ~~operations~~addition, ofwe ~~our~~use ~~customers~~domestic ~~are~~coal ~~subject~~futures contracts to ~~extensive~~help ~~environmental~~manage ~~regulation~~our ~~particularly~~exposure ~~with respect~~ to ~~air~~market ~~emissions. For~~changes ~~example,~~in ~~the~~domestic ~~federal~~coal ~~Clean~~prices. This ~~Air~~type ~~Act~~of ~~and~~hedge ~~similar~~is ~~state~~designed ~~and~~to ~~local~~benefit ~~laws~~us ~~extensively~~when ~~regulate~~prices ~~the~~change ~~amount~~relative ofto ~~sulfur~~our ~~dioxide,~~current ~~particulate~~open ~~matter,~~positions. If ~~nitrogen~~there ~~oxides,~~are ~~mercury~~significant and ~~other~~extended ~~compounds~~unfavorable ~~emitted~~price ~~into~~movements ~~the~~against ~~air~~our ~~from electric power plants~~positions, ~~which~~our ~~are~~earnings ~~the~~and ~~largest~~liquidity ~~end-users~~could ofbe ~~our~~negatively ~~coal~~impacted. AAs ~~series~~ of ~~more~~December ~~stringent requirements relating to particulate matter~~31, ~~ozone~~2013, ~~haze,~~we ~~mercury,~~held ~~sulfur~~domestic ~~dioxide,~~coal ~~nitrogen~~futures ~~oxide~~contracts ~~and~~for ~~other~~approximately ~~air~~2.9 ~~pollutants~~million ~~recently~~tons, ~~has~~which ~~been~~will ~~adopted~~settle ~~and/or is expected to be proposed or become effective~~ in ~~the~~2014 ~~near~~and ~~future~~2015. InSee ~~addition,~~Item ~~federal~~7A ~~and~~“Quantitative ~~state mandates~~ and ~~incentives~~Qualitative ~~designed~~Disclosures toAbout ~~encourage~~Market ~~energy~~Risk—Commodity ~~efficiency~~Price Risks” and ~~the~~Note ~~use~~6 of ~~alternative~~Notes ~~energy~~to ~~sources~~Consolidated ~~have~~Financial ~~been~~Statements ~~proposed and implemented~~ in ~~recent~~Item ~~years~~8. ~~Concerted conservation efforts that result in reduced electricity consumption could cause coal prices and sales of our coal to materially decline.~~

~~Considerable~~Changes ~~uncertainty is associated with these air emissions initiatives. New regulations are~~ in the ~~process~~fair ofvalue 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~~derivative ~~emissions~~instruments ~~or may install more effective pollution control equipment~~ that ~~reduces~~are ~~the~~not ~~need~~accounted for ~~low-sulfur~~as ~~coal, possibly reducing future demand for coal and resulting in~~ a ~~reduced~~hedge ~~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~~cause avolatility ~~material~~in ~~adverse effect on demand for, and prices received for,~~ our ~~coal~~earnings. 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.

From time to time, we enter into certain derivative financial instruments to help manage our exposure to future coal prices, both with respect to our export and domestic sales prices and to extreme rises in our diesel costs. Derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Changes in fair value are recognized either in earnings or equity, depending on whether the transaction qualifies for cash flow hedge accounting, and if so, how effective the derivatives are at offsetting price movements in the underlying exposure. To the extent these derivative financial instruments do not qualify for hedge accounting or we choose not to designate them for hedge accounting, we are required to record changes in the fair value of these derivative financial instruments in our Consolidated Statement of Operations, resulting in increased volatility in our income in future periods.

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

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

· coal characteristics such as Btu and sulfur content;

Table of Contents

~~Our~~· geological ~~customers are also subject to other existing~~ and ~~potential~~mining ~~environmental regulations~~conditions, ~~such~~which asmay ~~EPA’s~~not ~~publication~~be infully ~~June 2010~~identified ofby ~~proposed~~available ~~regulations~~exploration ~~for~~data ~~the management~~ and/or ~~disposal~~may ofdiffer ~~coal~~from ~~combustion by-products. While we are unable to determine the likely ultimate regulatory requirements, any significant changes in the management of coal combustion by-products could require~~ our ~~customers~~experiences ~~to comply with more stringent storage and disposal requirements, which~~ in ~~turn~~areas ~~could~~where ~~increase~~we ~~their~~currently ~~costs and reduce the demand for our coal.~~mine;

~~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. prices;

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

· ~~limitations~~operating oncosts, ~~land~~including ~~use~~for critical supplies such as fuel, tires and explosives;

· ~~mine~~capital ~~permitting~~expenditures and ~~licensing~~development ~~requirements~~and reclamation costs;

· ~~reclamation~~the ~~and~~percentage ~~restoration~~ of ~~mining~~coal ~~properties~~ultimately ~~after mining is completed~~recoverable;

· ~~management~~the effects of ~~materials~~regulation, ~~generated~~including bythe ~~mining~~issuance ~~operations~~of required permits, and taxes, including severance and production taxes and royalties, and other payments to governmental agencies; and

· ~~the~~timing ~~storage,~~for ~~treatment~~the ~~and~~development ~~disposal~~ of ~~wastes;~~the reserves.

~~· remediation~~Any changes to the above factors and assumptions could cause our estimates of ~~contaminated~~the ~~soil~~quantities and ~~groundwater;~~qualities of economically recoverable coal to vary significantly. Changes to the above factors and assumptions could also materially impact how we classify our reserves based on risk of recovery and our estimates of future net cash flows expected from these properties. Actual production recovered from identified reserve areas and properties, and revenue and expenditures associated with our mining operations, may vary materially from estimates. Any inaccuracy in our proven and probable reserves estimates could result in decreased profitability from lower than expected revenue and/or higher than expected costs.

~~· air~~The ~~quality~~majority ~~standards;~~of our coal sales contracts are forward sales contracts at fixed prices, which may not reflect favorable then-existing prices for coal or may affect our profitability if we cannot adequately control the costs of production for coal underlying such contracts.

~~· water~~We ~~pollution;~~have historically sold most of our coal under long-term coal sales agreements, which we generally define as contracts with a term of one to five years. For the year ended December 31, 2013, approximately 83% of our revenue was derived from coal sales that were made under long-term coal sales agreements. The prices for coal sold under these agreements are typically fixed for an agreed amount of time. Pricing in some of these contracts is subject to certain adjustments in later years or under certain circumstances, and may be below the current market price for similar type coal at any given time, depending on the time frame of the contract.

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

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

~~· the~~The ~~discharge~~loss of, ~~materials~~or ~~into~~significant ~~the~~reduction ~~environment;~~in, ~~and~~purchases by our largest customers could adversely affect our profitability.

· For the ~~effects~~year ended December 31, 2013, we derived approximately 17% of ~~mining~~our ontotal ~~surface~~revenue ~~water~~from sales to our three largest customers and ~~groundwater~~approximately ~~quality~~44% of our total revenue from sales to our ten largest customers. We are currently discussing the extension of coal sales agreements with some of these customers. However, we may be unsuccessful in obtaining coal supply agreements with these customers, and ~~availability~~some or all of these customers could discontinue purchasing coal from us. If any of these customers, particularly any of our three largest customers, was to significantly reduce the quantities of coal it purchases from us, or if we are unable to sell coal to these customers on terms as favorable to us, the results of our business would be adversely impacted.

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

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

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

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

Table of Contents

WeChanges ~~and~~in ~~Holdings~~purchasing ~~are~~patterns ~~incurring~~in ~~increased~~the ~~costs~~coal asindustry amay ~~result~~make ofit ~~being~~difficult ~~public~~for ~~companies,~~us ~~and~~to ~~the~~enter ~~requirements~~into ofnew ~~being~~contracts ~~public~~with ~~companies~~customers, ~~may~~or ~~divert~~do ~~our~~so ~~manager’s~~on ~~attention~~favorable ~~from~~terms, ~~our~~which ~~business. If~~could wematerially ~~and~~adversely ~~Holdings~~affect ~~are~~our ~~unable~~business ~~to achieve~~ and ~~maintain effective internal controls, our operating~~ results ~~and~~of ~~financial condition could be harmed~~operations.

AsIn ~~public~~past ~~companies~~years, we ~~and~~have ~~Holdings~~experienced ~~incur~~customers ~~significant~~being ~~legal,~~less ~~accounting~~willing ~~and~~to ~~other~~enter ~~expenses~~into ~~that~~long-term wecoal ~~did~~sales ~~not~~contracts ~~incur~~ as athey ~~subsidiary~~continue ~~of Rio Tinto. In addition, we and Holdings are subject~~ to aadjust number of additional requirements, including the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) and Holdings is subject to ~~the~~relatively ~~listing~~low ~~standards of New York Stock Exchange~~U. ~~These~~S. ~~requirements~~natural ~~have~~gas ~~caused~~prices, ~~us and Holdings to incur~~ increased ~~costs~~price ~~and~~volatility, ~~have placed~~ increased ~~demands~~fungibility onof ~~our~~coal ~~systems and resources. The Exchange Act requires~~products, ~~among~~frequently ~~other~~changing ~~things,~~regulations ~~that we~~ and ~~Holdings~~the ~~file~~increasing ~~annual,~~deregulation ~~quarterly~~of ~~and~~their ~~current reports with respect to our business and financial condition~~industry. ~~The~~In ~~Sarbanes-Oxley Act requires~~addition, ~~among~~the ~~other~~prices ~~things~~for ~~that~~coal ~~Holdings~~in ~~maintains~~the ~~effective~~spot ~~disclosure~~market ~~controls~~may ~~and procedures and internal control over financial reporting, and also requires that Holdings’s internal control over financial reporting~~ be ~~assessed~~lower bythan ~~management and attested to by its auditors as of December 31 of each year. Due to a transition period established by rules of~~ the ~~SEC~~prices ~~for~~previously ~~newly~~set ~~public~~under ~~companies,~~many ~~we will not be subject to certain requirements~~ of ~~the~~our ~~Sarbanes~~long-~~Oxley~~term ~~Act~~coal ~~until~~sales ~~the year ending December 31, 2011~~agreements. InAs ~~order to maintain and improve the effectiveness of~~ our ~~and~~contracts ~~Holdings’s~~with ~~disclosure~~customers ~~controls~~expire ~~and~~or ~~procedures~~are ~~and~~otherwise ~~internal control over financial reporting~~renegotiated, ~~significant~~our ~~resources~~customers ~~and~~may ~~management~~be ~~oversight~~less ~~will~~willing beto ~~required. As~~extend aor ~~result,~~enter ~~our~~into ~~manager’s~~new ~~attention~~long-term ~~might~~coal besales ~~diverted~~agreements ~~from~~under ~~other~~their ~~business~~existing ~~concerns,~~or ~~which~~similar ~~could~~pricing ~~have~~terms aor ~~material~~our ~~adverse~~customers ~~effect~~may ondecide ~~our~~to ~~business,~~purchase ~~prospects,~~fewer ~~financial~~tons ~~condition~~of ~~and~~coal ~~results~~than ofin ~~operations~~the past.

WeTo ~~identified~~the ~~material~~extent ~~weaknesses~~our incustomers ~~our~~shift ~~internal~~away ~~controls~~from ~~over~~long-term ~~financial~~supply ~~reporting~~contracts, ~~that~~it ~~contributed~~will tobe amore ~~restatement~~difficult ofto predict our ~~2005~~future sales. As a result, ~~2006~~we ~~and~~may ~~2007~~not ~~consolidated~~have ~~financial~~a ~~statements~~market ~~and~~for ~~June 30,~~our ~~2008,~~future ~~interim~~production ~~consolidated~~at ~~financial~~acceptable ~~statements~~prices. IfThe ~~not~~prices ~~remediated~~we ~~satisfactorily~~receive in the spot market may be less than the contractual price an electric utility is willing to pay for a committed supply. Furthermore, ~~these~~spot ~~material~~market ~~weaknesses~~prices tend to be more volatile than contractual prices, which could result in ~~further~~decreased ~~material~~revenue ~~misstatements~~and inprofitability. For example, as of December 31, 2013, we had approximately 82 million tons of committed sales for 2014 and 45 million tons for 2015, which is below our ~~consolidated~~typical ~~financial~~forward ~~statements~~sales inlevels, ~~future~~leaving more coal left to be sold for those periods.

~~During~~We ~~the~~are ~~preparation~~exposed ofto ~~our~~counterparty ~~consolidated~~risk ~~financial statements as of December 31, 2007 and 2008 and for each of the three years in the period ended December 31, 2008, in accordance~~ with ~~U.S. GAAP, we identified material weaknesses in~~ our ~~internal controls over financial reporting that contributed both to a restatement of our 2005~~customers, ~~2006~~trading ~~and 2007 consolidated financial statements and June 30~~partners, ~~2008 interim consolidated~~ financial ~~statements. Specifically~~institutions, ~~as a subsidiary of Rio Tinto, we were not required to~~ and weother ~~did~~parties ~~not maintain a sufficient complement of personnel~~ with anwhom ~~appropriate~~we ~~level~~conduct ~~of accounting, taxation, and financial reporting knowledge, experience and training in the application of U~~business.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.

InWe ~~preparation~~face ~~for~~an ~~the~~increased ~~filing~~risk ofthat ~~Holdings’s~~we ~~annual~~do ~~report~~not onreceive ~~Form 10-K~~payment for coal sold and delivered if the ~~year~~creditworthiness ~~ended~~of ~~December 31,~~any ~~2009,~~of our ~~manager~~counterparties ~~performed~~deteriorates anor ~~evaluation~~if any of ~~the~~our ~~effectiveness~~counterparties ofbecome ~~the~~subject ~~design~~to ~~and~~bankruptcy ~~operation~~proceedings. The creditworthiness of ~~our~~these ~~disclosure~~counterparties ~~controls~~depends ~~and~~on ~~procedures~~any asnumber of ~~December 31~~factors, ~~2009~~including the economic volatility and tightening of credit markets, and ~~concluded~~deregulation ~~that~~of the ~~previously~~U.S. ~~identified~~utilities ~~material~~markets, ~~weaknesses~~allowing ~~were~~utilities ~~not~~to ~~yet~~sell ~~remediated~~their power plants to their non-regulated affiliates or third parties that may have credit ratings that are below investment grade. Competition with other coal suppliers could cause us to extend credit to customers and on terms that could increase the risk of payment default.

AWe ~~material~~have ~~weakness~~contracts isto asupply ~~deficiency,~~coal orto aenergy ~~combination~~trading ofand ~~deficiencies~~brokering companies, inunder ~~internal~~which ~~control~~they ~~over~~purchase ~~financial~~the ~~reporting,~~coal ~~such~~for ~~that~~their ~~there~~own isaccount aor ~~reasonable~~resell ~~possibility~~to ~~that~~domestic aand ~~material~~foreign ~~misstatement~~end users. If the creditworthiness of ~~our~~these ~~annual~~energy ortrading ~~interim~~and ~~financial~~brokering ~~statements~~companies ~~will~~declines, this would increase the risk that we may not be ~~prevented~~able orto ~~detected~~collect payment for all coal sold and delivered to or on abehalf ~~timely~~of ~~basis~~those companies. AFurthermore, ~~deficiency~~if any of these companies seek to renegotiate or cancel sales of coal because of fluctuations in ~~internal~~spot ~~control~~prices ~~over~~for ~~financial~~coal, ~~reporting~~issues ~~exists~~with ~~when~~their end users accepting the ~~design~~coal or ~~operation~~other factors, we may be unable to sell previously anticipated volumes of coal at favorable prices or at all. We also enter into derivative financial instruments with a ~~control~~number ~~does~~of ~~not~~financial ~~allow~~institutions. If ~~management~~one or ~~employees,~~more inof ~~the~~these ~~normal~~institutions ~~course~~were ofto ~~performing~~default ~~their~~on ~~assigned~~its ~~functions,~~future obligation to ~~prevent~~us, orour ~~detect~~cash ~~misstatements~~flows onand aresults ~~timely~~of ~~basis~~operations would be negatively impacted.

~~Our~~In ~~manager~~certain ~~has~~circumstances ~~implemented~~we ~~changes~~may ~~and~~be ~~improvements~~entitled into ~~its~~demand ~~disclosure~~credit ~~controls~~enhancements ~~and~~or ~~procedures~~withhold ~~and~~shipments ~~its~~of ~~internal~~coal ~~control~~from ~~over~~these ~~financial~~parties ~~reporting~~if towe ~~remediate~~determine ~~the~~they ~~control~~are ~~deficiencies~~not ~~that~~creditworthy. However, ~~gave~~these ~~rise~~protections tomay ~~the~~be ~~material~~insufficient ~~weaknesses. If~~to wecover ~~experience~~our ~~future~~risks ~~material~~or ~~weaknesses, investors~~ could ~~lose~~cause ~~confidence~~us into ~~our~~resell ~~financial~~the ~~reporting,~~coal ~~particularly~~on ifthe ~~such~~spot ~~weaknesses~~market ~~result~~at inunfavorable aprices ~~restatement~~or ofnot ~~our~~at ~~financial results~~all.

IfWe ~~our~~have ~~highwalls~~significant orcash ~~spoil-piles fail~~balances, ~~our~~which ~~mining~~we ~~operations~~may ~~and~~invest ~~ability~~from time to ~~ship~~time ~~our~~in ~~coal~~marketable ~~could~~securities beissued ~~impaired~~by various counterparties including the U.S. government and ~~our~~U.S. ~~results~~government sponsored entities, municipal entities, financial institutions and other corporations. If any of ~~operations~~these counterparties fail, we could belose the principal invested with such counterparties, which would materially adversely impact our business, liquidity, and ~~adversely~~results ~~affected~~of operations.

Certain provisions in our coal sales contracts may provide limited protection during adverse economic conditions or may result in economic penalties or suspension upon a failure to meet contractual requirements.

Price adjustment, “price re-opener” and other similar provisions in our long-term supply contracts may reduce the protection from short-term coal price volatility traditionally provided by these contracts. Most of our contracts with mine customers and some of our contracts with logistics customers contain provisions that allow for the base price of our coal to be adjusted due to new statutes, ordinances or regulations that affect our costs related to performance. Because these provisions only apply to the base price of coal, these terms may provide only limited protection due to changes in regulations. Some of our contracts with mine customers also contain provisions that

Table of Contents

~~Our~~allow ~~operations~~for ~~could~~the bepurchase ~~adversely~~price ~~affected~~to ~~and we may~~ be ~~unable~~renegotiated toat ~~produce~~periodic ~~coal~~intervals. A ifprice ~~our~~re-opener ~~highwalls~~provision ~~fail~~is ~~due~~one toin ~~conditions,~~ which ~~may~~either ~~include~~party ~~geological~~can ~~abnormalities,~~renegotiate ~~poor~~the ~~ground~~price ~~conditions,~~of ~~water~~the orcontract, ~~blasting~~sometimes ~~shocks,~~at ~~among~~pre-determined ~~others~~times. InIndex ~~addition~~provisions toallow ~~making~~for itthe ~~difficult~~adjustment ~~and~~of ~~more~~the ~~costly~~price tobased ~~recover~~on ~~coal,~~ a ~~highwall~~fixed ~~failure~~formula. These ~~could~~provisions ~~also~~may ~~damage~~reduce ~~adjacent~~the ~~infrastructure~~protection ~~such~~available asunder ~~roads,~~long-term ~~power~~contracts ~~lines,~~from ~~railways~~short-term ~~and~~coal ~~gas~~price ~~pipelines~~volatility. ~~Further,~~Our ~~in-pit~~international ~~spoil-pile~~contracts ~~failure~~typically ~~due~~contain toa ~~conditions~~fixed ~~such~~price asfor ~~material~~the ~~type,~~first ~~water~~year ~~ingress,~~of ~~floor~~the ~~angle,~~contract ~~floor~~with ~~roughness,~~future ~~spoil~~years’ ~~volume~~prices orto ~~otherwise,~~be ~~can~~negotiated ~~impact~~at ~~coal~~a ~~removal,~~specific ~~reduce~~point ~~coal~~in ~~recovery,~~time. If ~~increase~~the ~~our~~parties ~~costs~~fail orto ~~interrupt~~satisfactorily ~~our~~negotiate ~~production~~a ~~and~~price, ~~shipments~~the contract could be terminated. ~~Highwall~~Any ~~and~~adjustment ~~spoil-pile~~or ~~failures~~renegotiations ~~could~~leading ~~materially~~to ~~and~~a ~~adversely~~significantly ~~affect~~lower ~~our~~contract ~~operations~~price, ~~thereby~~or ~~reducing~~a ~~our~~termination ~~profitability~~of the contract, could result in decreased revenue.

~~Major~~Our ~~equipment~~coal supply contracts with our mine customers 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. For example, as a result of the very mild 2011/12 winter and ~~plant~~low ~~failures~~natural ~~could~~gas ~~reduce~~prices, a greater than normal number of our ~~ability~~customers in 2012 sought to ~~produce~~reduce ~~and~~the ~~ship~~amount of tons delivered to them under our coal ~~and~~sales ~~materially~~agreements ~~and~~through ~~adversely~~contractual ~~affect~~remedies, such as force majeure provisions. Our contracts with our ~~results~~mine customers also typically allow our customers to suspend performance in the event that the railroad fails to provide its services due to circumstances that would constitute a force majeure. In addition, our contracts with our international logistics customers generally contain a clause that requires us to pay the demurrage fee charged by the vessel for delays in shipping the coal on behalf of ~~operations~~our foreign customers.

WeMost ~~depend~~of onour ~~several~~coal ~~major~~supply ~~pieces~~contracts ofalso ~~equipment~~contain ~~and~~provisions ~~plants~~requiring us to ~~produce~~deliver ~~and~~coal ~~ship~~within ~~our~~certain ~~coal,~~ranges ~~including~~for ~~draglines,~~specific ~~shovels~~coal characteristics, ~~coal~~such ~~crushing~~as ~~plants~~heat content, ~~critical conveyors~~sulfur, ~~major~~ash ~~transformers~~ and ~~coal~~ash ~~silos~~fusion temperature. IfFailure ~~any~~to ofmeet these ~~pieces~~specifications ofcan ~~equipment~~result orin ~~plants~~economic ~~suffered~~penalties, ~~major~~including ~~damage~~price ~~or were destroyed by fire~~adjustments, ~~abnormal wear~~suspension, ~~flooding,~~rejection ~~incorrect~~or ~~operation,~~cancellation ~~damage~~of ~~from~~deliveries ~~highwall~~ or ~~spoil-pile~~termination ~~failures~~of orthe ~~otherwise,~~contracts. A wenumber ~~may~~of beour ~~unable~~contracts toalso ~~replace~~contain orclauses ~~repair~~which, ~~them~~ in asome ~~timely manner or at a reasonable cost~~cases, ~~which~~may ~~would~~allow ~~impact~~customers ~~our ability~~ to ~~produce~~terminate ~~and~~the ~~ship~~contract ~~coal~~in ~~and~~the ~~materially~~event ~~and~~of ~~adversely~~certain ~~affect~~changes ~~our~~in ~~results~~environmental oflaws ~~operations~~and regulations.

~~Significant~~Our ~~increases~~ability into ~~royalties~~operate orour inbusiness ~~severance~~effectively ~~and~~could ~~production~~be ~~taxes~~impaired weif ~~pay on the coal~~ we ~~produce~~fail ~~could~~to ~~materially~~attract and ~~adversely~~retain ~~affect~~key ~~our results of operations~~personnel.

WeOur ~~pay~~ability ~~federal,~~to ~~state~~operate ~~and~~our ~~private~~business ~~royalties~~ and ~~federal,~~implement ~~state~~our ~~and~~strategies ~~county~~depends, ~~production~~in ~~taxes~~part, on the ~~coal~~continued wecontributions ~~produce. A substantial portion~~ of our ~~royalties~~executive officers and ~~production~~other ~~taxes~~key ~~are~~employees. The ~~levied~~loss asof aany ~~percentage~~ of ~~gross~~our ~~revenues~~key ~~with~~senior ~~the~~executives ~~remaining~~could ~~levied~~have on a ~~per~~material ~~ton~~adverse ~~basis. For~~effect ~~example,~~on weour ~~pay~~business ~~production~~unless ~~royalties~~and ofuntil ~~12.5%~~we offind ~~gross~~a ~~proceeds~~qualified ~~to the federal government~~replacement. WeA ~~incurred~~limited ~~royalties~~number ~~and~~of ~~severance~~persons ~~and~~exist ~~production~~with ~~taxes~~the ~~which~~requisite ~~represented~~experience ~~30.5%~~ and ~~29.1%~~skills ofto ~~proceeds~~serve ~~from~~in ~~the~~our ~~coal~~senior wemanagement ~~produced~~positions. We ~~for~~may ~~the~~not ~~years~~be ~~ended~~able ~~December 31,~~to ~~2010~~locate ~~and~~or ~~2009,~~employ ~~respectively. If~~qualified ~~royalties~~executives oron ~~severance~~acceptable terms and ~~production~~our ~~tax~~failure ~~rates were~~ to ~~significantly~~retain ~~increase~~ or ifattract wequalified ~~are~~executives ~~required~~could tohave ~~make~~an ~~additional~~adverse ~~payments~~effect ason aour ~~result~~ability ofto ~~governmental~~operate ~~audits,~~ our ~~results of operations could be materially and adversely affected~~business.

InEfficient ~~addition,~~coal ~~the~~mining ~~Wyoming~~using ~~state~~modern ~~severance~~techniques ~~tax~~and isequipment ~~significantly~~also ~~less~~requires ~~than~~skilled ~~the~~laborers ~~state~~in ~~severance~~multiple ~~tax~~disciplines insuch ~~Montana~~as electricians, equipment operators, mechanics, engineers and welders, among others. ~~Because~~We ahave ~~substantial~~from ~~portion~~time to time encountered shortages for these types of ~~our~~skilled ~~operations~~labor ~~are~~and intypically ~~Wyoming~~compete for such positions with other industries, including oil and ~~therefore~~gas. If ~~subject~~we toexperience shortages of skilled labor in the ~~more~~future, ~~favorable~~our ~~Wyoming~~labor ~~severance~~and ~~tax~~overall ~~rate~~productivity or costs could be materially adversely affected. In the future, ifwe ~~Wyoming~~may ~~were~~utilize toa ~~increase~~greater ~~this~~number ~~tax~~of orexternal ~~any~~contractors ~~other~~for ~~tax~~portions ~~applicable~~of ~~solely~~our tooperations. The costs of these contractors have historically been higher than that of our ~~Wyoming~~employed ~~operations~~laborers. If our labor and contractor prices increase, or if we ~~may~~experience bematerially ~~significantly~~increased ~~impacted~~health and benefit costs with respect to our employees, our results of operations could be materially ~~and~~ adversely affected.

~~Increases~~Our inwork ~~the~~force ~~cost~~could ofbecome ~~raw~~unionized ~~materials~~in ~~and~~the ~~other industrial supplies~~future, orwhich ~~the~~could ~~inability~~negatively toimpact ~~obtain~~the astability ~~sufficient quantity~~ of ~~those supplies, could increase~~ our ~~operating expenses, disrupt or delay our~~ production and materially ~~and~~reduce ~~adversely affect~~ our profitability.

WeAll ~~use considerable quantities~~ of ~~explosives,~~our ~~petroleum-based fuels~~mines, ~~tires,~~other ~~steel~~than ~~and~~the ~~other~~Decker ~~raw materials~~mine, aswhich ~~well~~we asdo ~~spare~~not ~~parts~~operate, ~~and~~are ~~other~~operated ~~consumables~~by innon-union ~~the mining process~~employees. IfOur ~~the~~employees ~~prices~~have ofthe ~~steel,~~right ~~explosives,~~at ~~tires,~~any ~~petroleum~~time ~~products~~under ~~or other materials increase significantly or if~~ the ~~value~~National ofLabor ~~the~~Relations ~~U.S.~~Act ~~dollar declines relative~~ to ~~foreign~~form ~~currencies with respect to certain imported supplies~~ or ~~other~~affiliate ~~products,~~with ~~our~~a ~~operating expenses will increase~~union, ~~which could materially~~ and ~~adversely~~in ~~impact~~the ~~our profitability. Additionally~~past, aunions ~~limited~~have ~~number~~conducted oflimited ~~suppliers~~organizing ~~exist~~activities ~~for~~in ~~certain~~this ~~supplies,~~regard. If ~~such as explosives and tires, as well as certain mining equipment, and any of~~ our ~~suppliers~~employees ~~may~~choose ~~divert their products~~ to ~~buyers~~form ~~in other mines~~ or ~~industries~~affiliate orwith ~~divert~~a ~~their~~union ~~raw~~and ~~materials~~the toterms ~~produce~~of ~~other products that have~~ a ~~higher~~union ~~profit~~collective ~~margin. Shortages~~bargaining inagreement ~~raw~~are ~~materials~~significantly ~~used~~different infrom ~~the~~our ~~manufacturing~~current ofcompensation ~~supplies~~ and ~~mining~~job ~~equipment,~~assignment ~~which,~~arrangements inwith ~~some~~our ~~cases~~employees, dothese ~~not~~arrangements ~~have~~could ~~ready~~negatively ~~substitutes,~~impact or the ~~cancellation~~stability of our ~~supply~~production ~~contracts under which we obtain these raw materials~~ and ~~other~~materially ~~consumables,~~reduce ~~could limit~~ our ~~ability to obtain these supplies or equipment~~profitability. AsIn ~~a result~~addition, weeven ~~may~~if ~~not~~our bemanaged ~~able~~operations toremain ~~acquire~~non-union, ~~adequate~~our ~~replacements~~business ~~for~~may ~~these~~still ~~supplies~~be oradversely ~~equipment~~affected onby awork ~~cost-effective basis or~~ stoppages at ~~all,~~unionized ~~which~~companies ~~could also materially increase our operating expenses~~ or ~~halt,~~unionized ~~disrupt~~transportation orand ~~delay~~service ~~our production~~providers.

~~Significant~~We ~~increases~~hold a 50% non-operating interest in the ~~price~~Decker ofmine, ~~diesel~~which ~~fuel~~has union members. These union-represented employees could ~~materially~~strike, which could adversely affect production at the Decker mine, increase its costs and disrupt shipments of coal from the Decker mine to its customers, all of which could materially adversely affect its results and the value of our ~~earnings~~investment in the Decker joint venture.

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

Table of Contents

~~negative~~Terrorist ~~impact~~attacks onand ~~our~~threats, ~~results~~escalation of ~~operations. See~~military ~~“Management’s~~activity ~~Discussion~~in ~~and~~response ~~Analysis~~to ofthese ~~Financial~~attacks ~~Condition~~or ~~and~~acts ~~Results~~ of ~~Operations—Cost~~war ofmay ~~Product~~materially ~~Sold”~~adversely ~~within~~affect ~~Item~~our 7business and ~~“Quantitative~~results ~~and~~of ~~Qualitative Disclosures About Market Risk—Commodity Price Risks” in Item 7A~~operations.

~~Conflicts~~Terrorist attacks and threats, escalation of ~~interest~~military ~~with~~activity ~~competing~~or ~~holders~~acts of ~~mineral~~war ~~rights~~may ~~could~~have ~~materially~~significant effects on general economic conditions, fluctuations in consumer confidence and ~~adversely~~spending and market liquidity, each of which could negatively impact our business. Furthermore, any such acts which directly affect our ~~ability~~customers and their business may have negative consequences to ~~mine~~our ~~coal~~own operations. Strategic targets such as energy-related assets and transportation assets may be at greater risk of future terrorist attacks than other targets in the U.S. or doin soother oncountries. Disruption aor ~~cost~~significant increases in energy prices could result in government-~~effective~~imposed ~~basis~~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.

~~The~~We ~~federal~~face 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~~risk of ~~those~~systems ~~interests. If~~failures ~~conflicting~~as ~~interests~~well ~~arise,~~as wesecurity ~~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~~risks, orincluding ~~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~~“hacking.”

~~Inaccuracies~~The computer systems and network infrastructure we and others use could be vulnerable to unforeseen problems. These problems may arise in both our ~~estimates~~internally developed systems and the systems of our ~~coal~~third-party ~~reserves~~service ~~could~~providers. Our ~~result~~operations inare ~~decreased~~dependent ~~profitability~~upon our ability to protect computer equipment against damage from ~~lower~~fire, ~~than~~power ~~expected~~loss ~~revenues~~or telecommunication failure. Any damage or ~~higher~~failure ~~than~~that ~~expected~~causes ~~costs~~an interruption in our operations could adversely affect our business. In addition, our computer systems and network infrastructure present security risks, and could be susceptible to hacking.

~~Our~~Risks ~~future~~Related ~~performance~~to 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~~Indebtedness ~~of proven~~ and probable coal reserves as to both quantity and quality are updated annually to reflect the production of coal from the reserves, updated geological models and mining recovery data, the tonnage contained in new lease areas acquired and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, any one of which may vary considerably from actual results. These factors and assumptions include:Liquidity

· quality of the coal;

· geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;

· the percentage of coal ultimately recoverable;

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

· assumptions concerning the timing for the development of the reserves; and

· assumptions concerning equipment and productivity; future coal prices; operating costs, including for critical supplies such as fuel, tires and explosives; capital expenditures and development and reclamation costs.

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

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

The majority of our coal sales contracts are forward sales contracts under which customers agree to pay a specified price under their contracts for coal to be delivered in future years. The profitability of these contracts depends on our ability to adequately control the costs of the coal production underlying the contracts. These production costs are subject to variability due to a number of factors, including increases in the cost of labor, supplies or other raw materials, such as diesel fuel. Historically we have not entered into hedge or other arrangements to offset the cost variability underlying these forward

Table of Contents

sale contracts. In the future, we may enter into these types of arrangements, but we may not be successful in hedging the volatility of our costs. To the extent our costs increase but pricing under these coal sales contracts remains fixed, we will be unable to pass increasing costs on to our customers. If we are unable to control our costs, our profitability under our forward sales contracts may be impaired and our results of operations could be materially and adversely affected.

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

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

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

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

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

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

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

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

Table of Contents

increased and our results could be materially and adversely harmed. If new laws or regulations increase the number and award size of claims, it could materially and adversely harm our business.

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

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

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

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

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

Adverse weather conditions can impact our ability to mine and ship our coal and our customers’ ability to take delivery of our coal. Lower than expected shipments by us during any period could have an adverse effect on our revenues and profitability. For example, previously our volume of coal shipments has been impacted by severe heavy rain, which

Table of Contents

reduced the capacity of the railroads by which our customers contract to transport coal from our mines. In addition, severe weather, including droughts and dust, may adversely affect our ability to conduct our mining operations.

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

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

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

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

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

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

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

We have historically sold most of our coal under long-term coal sales agreements, which we generally define as contracts with a term of one to five years. The remaining amount not subject to long-term coal sales agreements is sold as spot sales in term allotments of less than twelve months. For the year ended December 31, 2010 approximately 97% of our revenues were derived from coal sales that were made under long-term coal sales agreements. The prices for coal sold under

Table of Contents

these agreements are typically fixed for an agreed amount of time. Pricing in some of these contracts is subject to certain adjustments in later years or under certain circumstances, and may be below the current market price for similar type coal at any given time, depending on the time frame of the contract. As a consequence of the substantial volume of our forward sales, we have less coal available to sell under short-term contracts in order to immediately capitalize on higher coal prices, if and when they arise. At times, spot market prices have fallen below the prices established in many of our long-term coal sales agreements, and we have realized prices for our coal that are higher than the prices we would receive from sales in the spot market. However, to the extent spot market prices increase and become higher than the prices established in our long-term coal sales agreements, our ability to realize those higher prices may be restricted when customers elect to purchase additional volumes allowable under some contracts at contract prices that are lower than spot prices.

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

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

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

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

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

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

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

Table of Contents

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.

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

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

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

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

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

Table of Contents

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

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

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

We have focused on strategic acquisitions and subsequent expansions of large, low-cost, low-sulfur operations in the PRB and replacement of, and additions to, our reserves through the acquisition of companies, mines and reserves. We may pursue acquisition opportunities in the future. If we are unable to successfully integrate the businesses or properties we acquire, or reserves that we lease or otherwise acquire, our business, financial condition or results of operations could be negatively affected. Acquisition transactions involve various risks, including:

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

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

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

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

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

· diversion of our management’s attention from other business concerns;

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

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

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

· outstanding permit violations associated with acquired assets;

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

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

Table of Contents

resource needs on acceptable terms or at all. In addition, future acquisitions could result in our assuming significant long-term liabilities relative to the value of the acquisitions.

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

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

We share the profits, operating expenses, reclamation obligations and liabilities and assets associated with the Decker mine equally with the other 50% owner. Under the terms of the joint venture agreement, we are required to contribute cash or other property and equipment as may be necessary to operate the business. While capital contributions to the Decker joint venture have historically been made at the discretion of the management committee, under the terms of the joint venture agreement we may be required to contribute our proportional share of funds to carry on the business of the joint venture or to cover liabilities. In the event that either 50% owner does not contribute its share of operating expenses, including reclamation expenses when due, or other liabilities, the other owner is not required to assume their obligation. However, we may have joint and several liability as a matter of law for these expenses and other liabilities, including for operational liabilities. Accordingly, our financial obligations with respect to the Decker mine are subject to the creditworthiness of the other 50% owner, which is outside of our control. In addition, if we do not provide our proportional share or the other 50% owner does not provide its proportional share, our interest in the profits from the Decker mine will be adjusted proportionally. Our current debt instruments and future credit arrangements may limit our ability to make contributions to the Decker joint venture.

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

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

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

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

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

Table of Contents

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

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

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

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

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

Risks Related to Our Indebtedness

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

At December 31, ~~2010~~2013, we had ~~$600 million~~consolidated indebtedness of ~~senior notes outstanding and approximately~~ $~~8.1~~609 million ~~of other long-term debt incurred in connection with land acquisitions~~. InWe ~~addition,~~also athave ~~December 31,~~significant ~~2010,~~lease ~~$10.5 million~~and ofroyalty ~~capacity~~obligations ~~under~~related ~~our~~to ~~$400 million revolving credit facility was being used for letters of credit securing~~ our ~~reclamation~~federal ~~obligations~~coal ~~reducing the capacity under the revolving credit facility to $389~~leases.~~5 million.~~ Our outstanding indebtedness could have important consequences such as:

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

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

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

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

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

Table of Contents

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

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

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

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

~~We may be able to incur substantially more debt. This could exacerbate the risks associated with our substantial indebtedness.~~39

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

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

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

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

Table of Contents

InWe ~~addition,~~may ~~failure~~incur tosubstantially ~~comply~~more ~~with~~debt ~~any~~in of the ~~covenants~~future. If in our ~~existing~~indebtedness oris ~~future~~further ~~debt~~increased, ~~instruments~~the ~~could~~related ~~result~~risks inthat awe ~~default~~now ~~under~~face, including those ~~debt~~described ~~instruments~~above, ~~and~~could ~~under~~increase. Moreover, ~~other~~these ~~agreements~~risks ~~containing~~also ~~cross-default~~apply ~~provisions. A~~to ~~default~~certain ~~would~~of ~~permit~~CPE ~~lenders~~Resources’s todomestic ~~accelerate~~restricted ~~the~~subsidiaries ~~maturity~~that ofare ~~the~~guarantors ~~debt~~of ~~under~~CPE ~~these~~Resources’s ~~debt~~indebtedness ~~instruments~~ and may apply to ~~foreclose~~CPE ~~upon~~Inc. ~~any~~directly ~~collateral~~if ~~securing~~CPE ~~the~~Inc. becomes a guarantor of CPE Resources’s debt in the future. ~~Under~~In ~~these~~addition ~~circumstances,~~to wethe ~~might~~principal ~~not~~repayments ~~have~~on ~~sufficient~~outstanding ~~funds~~debt, orwe have other demands on our cash resources, toincluding ~~satisfy~~significant ~~all~~maintenance ofand ~~our~~other ~~obligations. In~~capital ~~addition~~expenditures, ~~the~~including ~~limitations~~LBAs, ~~imposed~~and byoperating ~~the~~expenses, ~~debt~~as ~~instruments~~well as required payments on ~~our~~the ~~ability~~tax agreement liability (See “—Other Risks Related to ~~incur~~Our ~~additional~~Corporate ~~debt~~Structure and Common Stock”). Our ability to ~~take~~pay ~~other~~our ~~actions~~debt ~~might~~depends ~~significantly~~upon ~~impair~~our operating performance. In particular, economic conditions could cause revenue to decline, and hamper our ability to ~~obtain~~repay ~~other financing~~indebtedness. WeIf ~~may~~we do not behave ~~granted~~enough ~~waivers~~cash ~~or amendments~~ to ~~these~~satisfy our debt ~~instruments~~service ifobligations, ~~for~~we ~~any~~may ~~reason~~be werequired ~~are~~to ~~unable~~refinance toall ~~comply~~or ~~with~~part ~~these~~of our debt, ~~instruments~~sell assets, ~~and~~limit certain capital expenditures, including LBAs, or reduce spending or we may be required to issue equity. We may not be able to, at any given time, refinance our debt onor ~~terms~~sell ~~acceptable~~assets and we may not be able to, usat any given time, issue equity, in either case on acceptable terms or at all.

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

A failure to comply with any of these restrictions or covenants could have serious consequences to our financial condition or result in a default under those debt instruments and under other agreements containing cross-default provisions. A default would permit lenders to accelerate the maturity of the debt under these debt instruments and to foreclose upon any collateral securing the debt. Furthermore, an event of default or an acceleration under one of our debt instruments could also cause a cross-default or cross-acceleration of another debt instrument or contractual obligation, which would adversely impact our liquidity. Under these circumstances, we might not have sufficient funds or other resources to satisfy all of our obligations. We may not be granted waivers or amendments to these debt instruments if for any reason we are unable to comply with these debt instruments, and we may not be able to refinance our debt on terms acceptable to us, or at all.

Covenants under our revolving credit facility may limit the amount of funds available to us.

Our ability to borrow is subject to the terms and conditions of our revolving credit facility. The financial covenants are based on EBITDA (which is defined in the credit agreement and is not the same as EBITDA or Adjusted EBITDA otherwise presented), requiring us to maintain defined minimum levels of interest coverage and providing for a limitation on our leverage ratio. Our earnings may not be sufficient to allow for the full availability on the revolving credit facility and the A/R Securitization Program. For example, the Amended Credit Agreement requires us to maintain (a) a ratio of trailing twelve months EBITDA to consolidated net cash interest expense equal to or greater than 2.75 to 1 (“Interest Ratio”), and (b) a ratio of funded debt to trailing twelve months EBITDA equal to or less than 3.50 to 1 (“Leverage Ratio”). Based on the Leverage Ratio, our aggregate available borrowing capacity under the revolving credit facility and the A/R Securitization Program was approximately $169 million at December 31, 2013. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Senior Secured Revolving Credit Facility.”

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

~~Certain provisions of our debt instruments could make it more difficult or more expensive for a third party to acquire us.~~ Upon the occurrence of certain transactions constituting a “change in control” as defined in the indenture, holders of the senior notes ~~could~~have the right to require us to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. Furthermore, a “change in control” as defined in our credit facility is considered an event of default. These provisions could make it more difficult or more expensive for a third party to acquire us even where the acquisition could be beneficial to our stockholders.

~~Risks Related to Our Corporate Structure and the IPO Structuring Transactions~~40

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

In connection with the IPO, Holdings entered into the Tax Receivable Agreement with RTEA that requires Holdings to pay to RTEA approximately 85% of the amount of cash tax savings, if any, that Holdings realizes as a result of the increases in tax basis that Holdings obtained in connection with the initial acquisition of Holdings’s interest in us, Holdings’s subsequent acquisition of RTEA’s remaining units in us, as well as payments made by Holdings under the Tax Receivable Agreement. Due to the size of the increases in the tax basis of Holdings’s share of our tangible and intangible assets, as well as the increase in Holdings’s basis in the equity of our subsidiaries and assets held by those subsidiaries, Holdings expects to make substantial payments to RTEA under the Tax Receivable Agreement. As a result of Holdings’s acquisition of RTEA’s remaining units in us, Holdings has received a further step-up in Holdings’s tax basis and, accordingly, Holdings’s obligations under the Tax Receivable Agreement to pay RTEA 85% of any benefits Holdings receives as a result of such further step-up has significantly increased. Holdings’s obligation may further increase if there are changes in law, including the increase of current corporate income tax rates. The payment obligations under the Tax Receivable Agreement are not conditioned upon RTEA’s or its affiliate’s continued ownership of an interest in us or Holdings’s available cash resources. Based on the tax basis of our assets as of December 31, 2010 and our operating plan, the future payments under the Tax Receivable Agreement are estimated to be approximately $190.1 million in the aggregate and are estimated to be payable over the next 20 years. This estimate is based on assumptions related to our business that could change, and the actual payments could differ materially from this estimate. Payments would be greater if we generate income significantly in excess of the amounts used in our operating plan, for example, because we acquire additional LBAs beyond our existing LBAs, and as a result, Holdings realizes the full tax benefit of such increased tax basis (or an increased portion thereof).

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

Table of Contents

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

~~Default~~We are required under the Tax Receivable Agreement ~~will~~to ~~permit~~pay RTEA tofor ~~accelerate~~most ~~Holdings’s~~of ~~obligations. If~~the ~~Holdings~~tax ~~defaults~~benefits onwe ~~its~~may ~~obligations~~claim ~~under~~as ~~the~~a ~~Tax~~result ~~Receivable~~of ~~Agreement~~the ~~(including~~tax bybasis ~~reason~~step-up ofwe ~~insufficient~~received ~~cash~~in ~~distributions~~connection ~~from~~with ~~us)~~the IPO, ~~such~~related ~~default~~IPO ~~will~~structuring ~~permit~~transactions ~~RTEA~~and Secondary Offering. In certain cases, payments to ~~enforce~~RTEA ~~its~~may ~~rights~~be ~~under~~accelerated ~~the~~or ~~Tax~~exceed ~~Receivable~~our ~~Agreement,~~actual ~~including~~cash bytax ~~acceleration~~savings. These ofprovisions ~~Holdings’s~~may ~~obligations~~deter ~~thereunder~~a change in control of our company.

~~Holdings’s~~Due ~~ability~~ to ~~achieve~~the ~~benefits~~size ~~from~~of ~~any~~the increases in the tax basis ~~increase,~~of our share of CPE Resources’s tangible and, ~~therefore~~intangible assets, as well as the ~~payments~~increase ~~expected~~in our basis in the equity of CPE Resources’s subsidiaries and assets held by those subsidiaries, we expect to bemake ~~made~~substantial payments to RTEA under ~~the~~this ~~Tax~~agreement. As ~~Receivable~~a ~~Agreement~~result of our 2010 acquisition of RTEA’s remaining units in CPE Resources, ~~depends~~we ~~upon~~received a ~~number~~further ofstep-up ~~factors~~in our tax basis and, accordingly, our obligations under the agreement to pay RTEA 85% of any benefits we receive as ~~discussed~~a ~~above~~result of such further step-up significantly increased. Our obligation may further increase if there are changes in law, including the ~~timing~~increase ~~and amount~~ of ~~our~~current ~~future~~corporate income tax rates. The ~~U.S.~~payment ~~Internal~~obligations ~~Revenue~~on ~~Service~~the ~~could~~tax ~~challenge~~agreement ~~one~~liability are not conditioned upon RTEA’s or ~~more~~its affiliate’s ownership of ~~our~~an interest in CPE Resources or ~~Holdings~~our available cash resources. Based on the tax basis of our assets as of December 31, 2013 and CPE Resources’s ~~tax~~operating ~~positions~~plan, ~~relevant~~the future payments are estimated to ~~the~~be ~~Tax~~approximately ~~Receivable~~$103.6 ~~Agreement~~million in the aggregate and aare ~~court~~estimated ~~could~~to ~~sustain~~be ~~such~~payable aover ~~challenge~~the next 28 years. ~~Such~~This aestimate ~~challenge~~is ~~could~~based ~~result~~on inassumptions arelated ~~decrease~~to inour ~~Holdings’s~~business ~~tax~~that ~~benefits~~could change, asand ~~well~~the asactual ~~Holdings’s~~payments ~~obligations~~could ~~under~~differ ~~the~~materially ~~Tax~~from ~~Receivable~~this ~~Agreement~~estimate. ~~Holdings~~Payments ~~must~~would ~~obtain~~be ~~RTEA’s~~greater ~~consent~~if ~~prior~~we togenerate ~~settlement~~income significantly in excess of ~~any~~the ~~such~~amounts ~~challenge~~used ifin itour ~~may~~operating ~~affect~~plan, ~~RTEA’s~~for ~~rights~~example, because we acquire additional coal reserves beyond our existing coal reserve base, and ~~obligations~~as ~~under~~a result, we realize the ~~Tax~~full ~~Receivable~~tax ~~Agreement~~benefit of such increased tax basis (or an increased portion thereof).

~~Our~~Certain ~~results~~changes in control require us to make payments to RTEA, which could exceed our actual cash savings and could require us to provide credit support. If we undergo a change in control and we do not otherwise elect to terminate the Tax Receivable Agreement as discussed below, payments to RTEA on the tax agreement liability will continue on a ~~separate~~yearly basis but will be based on an agreed upon set of assumptions. In this case, ~~stand-alone~~our ~~public~~assumed ~~company~~cash ~~are~~tax ~~significantly~~savings, ~~different~~and ~~from~~consequently ~~those~~our ~~portrayed~~payments due on the tax agreement liability, could exceed our actual cash tax savings each year by material amounts. If we undergo such a change in control and our ~~pre-IPO~~credit ~~financial~~rating ~~results~~is impaired, we will be required to obtain credit support with regard to all remaining payments under the agreement. The change in control provisions may deter a potential sale of our company to a third party and may otherwise make it less likely a third party would enter into a change in control transaction with us.

~~The~~Our ~~historical~~debt ~~financial~~instruments ~~information~~contain ~~for~~limitations ~~all~~on ~~periods~~CPE ~~prior~~Resources’s ability to ~~the~~make ~~IPO~~distributions, ~~included~~which incould ~~this~~affect ~~Form 10-K was derived from the consolidated financial statements of Rio Tinto and does not reflect what~~ our ~~financial~~ability ~~position,~~to ~~results~~meet ofthese ~~operations,~~payment ~~cash flows, costs or expenses would have been had we been a separate, stand-alone public company during those periods presented~~obligations. ~~Rio~~These ~~Tinto~~limitations ~~did~~on ~~not~~CPE ~~account~~Resources’s ~~for~~ability ~~us, and we were not operated, as a separate, stand-alone public company for the historical periods presented prior~~ to ~~the~~make ~~IPO. The~~distributions ~~historical~~may ~~costs~~limit ~~and expenses reflected in~~ our ~~consolidated~~ability ~~financial statements for periods prior~~ to ~~the~~engage ~~IPO~~in ~~also include allocations of~~ certain ~~general~~taxable ~~and~~asset ~~administrative~~sales ~~costs~~or ~~and~~dispositions ~~Rio~~outside ~~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~~ordinary ~~costs~~course ~~incurred by Rio Tinto to provide these services required in support~~ of our business.

AsDefault aunder ~~separate,~~the ~~stand-alone~~Tax ~~public~~Receivable ~~company,~~Agreement ~~our~~will ~~cost~~permit ~~structure~~RTEA isto ~~different~~accelerate ~~and~~our ~~includes both additional recurring costs and nonrecurring costs~~obligations. ~~Accordingly,~~If ~~our~~we ~~historical~~default ~~consolidated~~on ~~financial~~the ~~information~~tax isagreement ~~not~~liability ~~reflective~~(including ofby ~~our~~reason ~~financial position, results~~ of ~~operations~~insufficient or cash ~~flows~~distributions orfrom ~~costs~~CPE ~~had~~Resources), wesuch ~~been~~default awill ~~separate,~~permit ~~stand-alone~~RTEA ~~public~~to ~~company~~enforce ~~during~~its ~~all~~rights ofunder ~~the~~this ~~periods presented~~agreement, ~~and~~including ~~the~~by ~~historical~~acceleration ~~financial information is not a reliable indicator~~ of ~~what~~ our ~~financial~~obligations ~~position, results of operations or cash flows will be in the future~~thereunder.

~~Prior~~Our ability to achieve benefits from any tax basis increase, and, therefore, the ~~IPO~~payments expected to be made on the tax agreement liability, ~~Holdings’s~~depends ~~directors~~upon a number of factors, as discussed above, including the timing and ~~executive~~amount ~~officers~~of ~~had~~our ~~potential~~future ~~conflicts~~income. The U.S. Internal Revenue Service could challenge one or more of ~~interest~~our ~~with~~tax ~~Holdings~~positions relevant to this agreement and ~~its~~a ~~shareholders~~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 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 agreement.

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

50We entered into various agreements with Rio Tinto and its affiliates in connection with the IPO and separation from Rio Tinto. CPE Resources agreed to indemnify Rio Tinto for certain losses pursuant to these agreements. Because these agreements were entered into while we were part of Rio Tinto, some of the terms of these agreements are likely less favorable to us than similar agreements negotiated between unaffiliated third parties. Third parties may also seek to hold us responsible for liabilities of Rio Tinto that we did not assume in connection with the IPO and for which Rio Tinto agreed to indemnify us, including liabilities related to the Jacobs Ranch and

Table of Contents

~~Our~~Colowyo ~~agreements~~mines, ~~with~~as ~~Rio~~well ~~Tinto~~as the uranium mining venture that we do not own. If those liabilities are significant and ~~its~~we ~~affiliates~~are ~~related~~ultimately held liable for them, we may not be able to recover the ~~IPO~~full ~~are~~amount ~~likely~~of ~~less~~our ~~favorable~~losses from Rio Tinto. Refer to usthe ~~than~~applicable ~~similar~~exhibits listed in Item 15 of this Form 10-K for the complete terms and conditions of the principal outstanding agreements ~~negotiated~~with ~~between~~Rio ~~unaffiliated~~Tinto ~~third~~entered ~~parties~~into in connection with our 2009 IPO.

WeCPE ~~and~~Inc. ~~Holdings~~is ~~entered~~a ~~into~~holding ~~various~~company ~~agreements~~ with ~~Rio~~no ~~Tinto~~direct ~~and~~operations ~~its affiliates in connection with the IPO which address, among other things, the allocation~~ of assets and liabilities between subsidiaries of Rio Tinto and us, responsibility for the disclosures made in the IPO prospectus and in the offering memorandum used in the senior notes offering, our obligation to provide Rio Tinto financial information needed for its ~~public~~own ~~filings, certain ongoing commercial relationships~~ and ~~Holdings’s~~depends responsibility in its role as our manager to RTEA and KMS as former non-managing members. We have agreed to indemnify Rio Tinto for any losses experienced pursuant to these agreements, in certain instances on adistributions ~~dollar-for-dollar~~from ~~basis~~CPE ~~and~~Resources ~~in certain other instances by providing additional indemnification calculated on a dollar-for-dollar basis plus a fraction of a dollar equal~~ to ~~the~~meet ~~ownership interest of Rio Tinto and~~ its ~~affiliates~~ongoing ~~in us at the time the indemnity is payable to Rio Tinto~~obligations. Because these agreements were entered into while we and Holdings were part of Rio Tinto, some of the terms of these agreements are likely less favorable to us and Holdings than similar agreements negotiated between unaffiliated third parties.

~~Third~~CPE ~~parties~~Inc. ~~may~~is ~~seek~~a holding company with no direct operations of its own and has no independent ability to ~~hold~~generate usrevenue. Consequently, ~~responsible~~its ~~for~~ability ~~liabilities~~to obtain operating funds depends upon distributions from CPE Resources and payments under the management services agreement. Pursuant to its management services agreement, CPE Resources makes payments to CPE Inc. in the form of ~~Rio~~a ~~Tinto~~management ~~that~~fee weand ~~did~~cost ~~not~~reimbursements ~~assume~~to fund CPE Inc.’s day-to-day operating expenses, such as payroll for its officers. However, if CPE Resources cannot make the payments pursuant to the management services agreement, CPE Inc. may be unable to cover these expenses.

~~Third~~The ~~parties~~distribution ~~may~~of ~~seek~~cash toflows ~~hold~~by usCPE ~~responsible~~Resources ~~for~~to ~~liabilities~~CPE ofInc. ~~Rio~~is ~~Tinto~~subject ~~that~~to westatutory ~~did~~restrictions ~~not~~under ~~assume in connection with~~ the ~~IPO,~~Delaware ~~including~~Limited ~~liabilities~~Liability ~~related~~Company toAct ~~the Jacobs Ranch~~ and ~~Colowyo~~contractual ~~mines,~~restrictions asunder ~~well~~CPE asResources’s ~~the~~debt ~~uranium~~instruments ~~mining venture~~ that wemay dolimit ~~not~~the ~~own. Under~~ability ~~certain~~ of ~~the~~CPE ~~IPO~~Resources ~~Structuring Agreements, RTA will indemnify us for certain claims and losses relating~~ to ~~these~~make ~~liabilities~~distributions. IfIn ~~those~~addition, ~~liabilities~~any ~~are~~distributions ~~significant~~ and wepayments ~~are~~of ~~ultimately~~fees ~~held~~or ~~liable~~costs ~~for~~are ~~them,~~subject ~~we may not be able~~ to ~~recover~~CPE ~~the~~Resources’s ~~full~~financial ~~amount of our losses from RTA~~condition.

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

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

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

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

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

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

· provide for a classified Board of Directors, which may delay the ability of our stockholders to change the membership of a majority of our Board of Directors;

· authorize the issuance of “blank check” preferred stock that could be issued by our Board of Directors to thwart a takeover attempt;

Table of Contents

· do not provide for cumulative voting;

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

· limit the calling of special meetings of stockholders;

· provide that stockholders may not act by written consent;

· provide that our directors may be removed only for cause;

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

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

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

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

Coal Reserves

As of December 31, ~~2010~~2013, we controlled approximately ~~970~~1.2 ~~million~~billion tons of proven and probable coal reserves. All of our proven and probable reserves are classified as ~~steam~~thermal coal.

The following table summarizes the tonnage of our coal reserves that is classified as proven or probable, and assigned, as well as our property interest, as of December 31, ~~2010~~2013:

Mine	Proven Preserves	Probable Reserves	Total Proven & Probable Reserves	Assigned Reserves	Reserves Owned	Reserves Leased
	(nearest million, in tons)			(%)	(nearest million, in tons)
Antelope	244	8	252	100	0	252
Owned and Operated Mines
Cordero Rojo	300	84	385	100	48	337
Antelope	463	154	617	100	—	617
Spring Creek	304	25	329	100	0	329
Cordero Rojo	219	71	290	100	57	233
Decker(1)	4	0	4	100	0	4
Spring Creek	258	21	279	100	—	279
Total(2)	852	118	970		48	922
Corporate and Other
Decker (1)	—	—	—	0	—	—
Total (2)	940	247	1,187		57	1,130

(1) Based on our 50% non-operating interest and in accordance with our application of the ~~Decker~~SEC ~~mine~~Industry Guide 7’s specific definitions of proven and probable reserves.

(2) ~~Total~~ Totals ~~reflects~~reflect rounding.

5143

Table of Contents

The following table provides the “quality” (average sulfur content and average Btu ~~content~~ per pound) of our coal reserves as of December 31, ~~2010~~2013:

Mine	Total Proven & Probable Reserves	Average Btu per lb (1)	Average Sulfur Content	Average Sulfur Content~~(2)~~
	(nearest million, in tons)		(%)	(lbs SO2/ mmBtu)
Antelope	252	8,850	0.23	0.52
Owned and Operated Mines
Cordero Rojo	385	8,425	0.29	0.69
Antelope	617	8,875	0.23	0.52
Spring Creek	329	9,350	0.33	0.71
Cordero Rojo	290	8,425	0.29	0.69
Decker(3)	4	9,450	0.42	0.89
Spring Creek	279	9,350	0.34	0.73
Total(4)	970
Corporate and Other
Decker (2)	—	—	—	—
Total (3)	1,187

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

(2) ~~All~~ Based on our ~~coal~~50% isnon-operating ~~considered to be compliance coal under the Clean Air Act~~interest.

(3) ~~Based~~ Totals onreflect ~~our 50% interest in the Decker mine~~rounding.

~~(4) Total~~We ~~reflects~~also ~~rounding~~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 include:

We· 9 ~~also~~million ~~control~~tons ~~certain coal deposits that are contiguous to or~~ near our ~~primary~~Antelope ~~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:~~mine;

~~Antelope~~· 163 ~~Mine: 80~~ million tons near our Cordero Rojo mine;

~~Cordero~~· 6 ~~Rojo Mine: 176~~ million tons near our Spring Creek mine; and

~~Our~~· 287 ~~reserve~~million ~~and~~tons ~~non-reserve~~at ~~coal~~the ~~deposit~~Youngs ~~estimates~~Creek ~~as of December 31, 2010 were prepared by our staff of geologists and engineers, who has extensive experience in PRB coal~~project. ~~These individuals are responsible for collecting and analyzing geologic data within and adjacent to leases controlled by us.~~

AIn ~~review~~addition, ofwe ~~our~~also ~~2010~~control ~~resources~~additional ~~and~~leased ~~reserves assessments was completed in January 2011 by John T. Boyd Company, mining~~ and ~~geological~~private ~~consultants,~~coal ~~and~~related ~~covered~~to ~~our reserves as of December 31, 2010. The results verified our reserve estimates. Our reserve estimates of approximately 970 million tons for~~ the ~~year~~Youngs ~~ended~~Creek ~~December 31,~~project ~~2010~~that ~~were~~has ~~confirmed~~not bybeen ~~John~~evaluated ~~T. Boyd~~and ~~Company,~~is asnot ~~well~~in asany ~~approximately~~mine ~~256 million tons of non-reserve coal deposits we held as of December 31, 2010~~plan.

Our ~~coal~~reserve and non-reserve coal deposit estimates ~~are~~as ~~based~~of onDecember 31, ~~data~~2013 ~~obtained~~were ~~from~~prepared by our ~~drilling~~staff ~~activities~~of geologists and ~~other~~engineers, ~~available~~who ~~geologic~~have ~~data. All~~extensive ofexperience ~~our~~in ~~reserves~~PRB coal. These individuals are ~~assigned,~~responsible ~~associated~~for ~~with~~collecting ~~our~~and ~~active~~analyzing ~~coal~~geologic ~~properties,~~data within and ~~incorporated~~adjacent into ~~detailed~~leases ~~mine~~controlled ~~plans~~by us. ~~Estimates~~An external review of our reserves ~~are~~and ~~based~~non-reserve oncoal ~~more~~deposit ~~than~~estimates ~~7,500~~are ~~drill~~performed ~~holes~~every two years. ~~Our~~The ~~proven~~most ~~reserves~~recent ~~have~~review awas ~~typical~~performed ~~drill~~for ~~hole~~the ~~spacing~~year ofended 1December 31,~~500~~ ~~feet~~2012 orand ~~less~~was completed in January 2013 by John T. Boyd Company, mining and ~~our~~geological ~~probable~~consultants. The ~~reserves~~results ~~have~~verified aour ~~typical~~reserve ~~drill~~and ~~hole~~non-reserve ~~spacing~~coal ofdeposit ~~2,500~~estimates ~~feet~~for orthe ~~less~~year ended December 31, 2012.

~~Along~~Our ~~with the geological data we assemble for our~~ coal reserve estimates, ~~our~~are ~~staff~~based ofon ~~geologists and engineers also analyzes the economic~~ data ~~such~~obtained asfrom ~~cost~~our ofdrilling ~~production,~~activities ~~projected sales price~~ and other ~~data~~available ~~concerning~~geologic ~~permitting and advances in mining technology~~data. ~~Various~~All ~~factors~~of ~~and~~our ~~assumptions~~reserves are ~~utilized in estimating coal reserves~~assigned, ~~including~~associated ~~assumptions~~with ~~concerning~~our ~~future~~active coal ~~prices~~properties, and ~~operating~~incorporated ~~costs. These~~in ~~estimates~~detailed ~~are~~mine ~~periodically~~plans. Estimates ~~updated~~of toour ~~reflect~~reserves ~~past~~are ~~coal~~based ~~production~~on ~~and~~more ~~other~~than ~~geologic~~6,000 ordrill ~~mining data~~holes. ~~Acquisitions~~Our orproven ~~sales~~reserves ofhave ~~coal~~a ~~properties~~typical ~~will~~drill ~~also~~hole ~~change~~spacing ~~these estimates. Changes in mining methods or the utilization~~ of ~~new~~1,500 ~~technologies~~feet ~~may increase~~ or ~~decrease~~less, ~~the~~and ~~recovery~~our ~~basis~~probable ~~for~~reserves have a ~~coal~~typical ~~seam. We~~drill ~~maintain~~hole ~~reserve~~spacing ~~information~~of ~~in secure computerized databases~~2,500 asfeet ~~well~~or ~~as in hard copy~~less.

~~Reserve~~Along ~~Acquisition~~with ~~Process~~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.

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 million44

Table of Contents

~~tons~~Reserve ofAcquisition ~~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.~~Process

WeSince ~~acquire~~our ainception, ~~significant~~we ~~portion~~have offocused ~~our~~on ~~coal~~growth through the ~~LBA~~acquisition ~~process,~~of proven and asprobable acoal ~~result,~~reserves ~~substantially~~and ~~all~~non-reserve ofcoal ~~our~~deposits. Historically, ~~coal~~this iswas ~~held~~accomplished ~~under~~through the federal ~~leases. Under~~competitive ~~this~~leasing process, ~~before~~known aas ~~mining~~the ~~company~~LBA ~~can~~process. For ~~obtain~~example, ~~new~~in ~~federal~~2011 ~~coal,~~we ~~the~~acquired ~~company~~383 ~~must~~million ~~nominate~~tons aof ~~coal~~proven ~~tract~~and ~~for~~probable ~~lease~~coal ~~and~~reserves ~~then~~in ~~win~~two ~~the~~federal ~~lease~~coal ~~through~~leases afor ~~competitive~~our ~~bidding~~Antelope ~~process~~mine. ~~The~~However, ~~LBA~~in ~~process~~2012, ~~can~~we ~~last~~also ~~anywhere~~acquired ~~from~~significant ~~two~~coal todeposits ~~five~~when ~~years~~we ~~from~~completed the ~~time~~acquisition of the ~~coal~~Youngs ~~tract~~Creek isproject, ~~nominated~~a tonon-operating ~~the~~mine ~~time~~in aNortheast ~~final~~Wyoming ~~bid~~in isthe ~~accepted~~Northern byPRB, ~~the~~whereby ~~BLM. After~~we ~~the~~acquired ~~LBA~~287 ismillion ~~awarded,~~tons ~~the~~of ~~company~~non-reserve ~~then~~coal ~~conducts~~deposits ~~the~~along ~~necessary~~with ~~testing~~significant torelated ~~determine~~surface ~~what~~assets. We ~~amount~~also ~~can~~announced bein ~~classified~~2013 asthat ~~reserves~~we signed an Option Agreement and ~~begins~~a ~~the~~corresponding ~~process~~Exploration toAgreement ~~permit~~with the ~~coal~~Crow ~~for~~Tribe ~~mining,~~of ~~which~~Indians ~~generally~~for ~~takes~~the ~~another~~exploration ~~two~~and topotential ~~five~~development ~~years. Third-party~~of ~~legal~~significant ~~challenges,~~coal ~~such~~resources ason ~~legal~~the ~~challenges~~Crow ~~filed~~Indian Reservation in ~~2010~~southeast ~~against~~Montana ~~the~~in ~~BLM and~~ the ~~Secretary~~Northern ofPRB ~~the~~region. We ~~Interior~~intend byto ~~environmental~~continue ~~groups~~to ~~with~~seek ~~respect~~opportunities to ~~the~~acquire ~~LBA~~additional ~~process~~coal inthrough the ~~PRB~~federal ~~and~~leasing ~~the~~process ~~West~~as ~~Antelope~~well IIas ~~LBA,~~through ~~may~~private ~~result~~transactions inwith ~~delays~~third ~~and~~parties ~~other~~or ~~adverse~~sovereign ~~impacts~~nations onsuch as the ~~LBA~~Crow ~~process~~Tribe of Indians.

We acquire a large portion of our coal through the LBA process, and as a result, most of our coal is held under federal leases. Under this process, before a mining company can obtain a new federal coal lease, the company must nominate a coal tract for lease and then win the lease through a competitive bidding process. The LBA process can last anywhere from two to five years or more from the time the coal tract is nominated to the time a final bid is accepted by the BLM. After the LBA is awarded, the company then conducts the necessary testing to determine what amount can be classified as reserves and begins the process to permit the coal for mining, which generally takes another two to five years. Third-party legal challenges, such as legal challenges filed against the BLM and the Secretary of the Interior by environmental groups with respect to the LBA process in the PRB, including the West Antelope II LBA, may result in delays and other adverse impacts on the LBA process. See Item 3 “Legal Proceedings—West Antelope II LBA Challenges.”

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 athe LBM 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. InFor ~~June~~example, in December ~~2010~~2012, we ~~entered~~applied ~~into~~for atwo ~~modified~~separate ~~coal~~LBMs ~~lease~~ with the BLM: one ~~through~~at the ~~LBM~~Spring ~~process~~Creek tomine ~~add~~and ~~approximately~~one 48at ~~million~~the ~~tons~~Antelope mine. As of ~~proven~~December 31, ~~and~~2013, ~~probable~~an ~~reserves~~environmental toassessment ~~one~~was ofunderway for the Antelope LBM and the Spring Creek ~~mine’s~~application ~~existing~~was ~~federal~~being ~~coal~~processed ~~leases~~by the BLM.

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

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

The federal coal leasing process is designed to be a public process, giving stakeholders and other interested parties opportunities to comment on the BLM’s proposed and final actions and allow third-party comments. Because of this, third parties, including non-governmental organizations, can challenge the BLM’s actions, which may delay the leasing process. If45

Table of Contents

~~these~~and ~~challenges~~extent ~~prove successful or are litigated for a prolonged period~~ of ~~time,~~its a coal ~~company’s~~holdings ~~ability~~ to ~~bid~~the onU.S. orDepartment ~~acquire~~of aJustice ~~new~~for ~~coal~~a ~~lease~~30-day ~~could~~antitrust bereview ~~significantly~~of ~~delayed, or could cause~~ the ~~BLM to not offer a~~ lease ~~for bid at all~~. InIf ~~2010,~~the ~~environmental~~successful ~~organizations~~bidder ~~filed~~was ~~legal~~not ~~challenges~~the ~~against~~initial applicant, the BLM’s ~~findings~~will onrefund the ~~final~~initial ~~EIS~~applicant ~~and~~certain ~~other~~fees ~~matters~~it ~~associated~~paid in connection with the ~~West~~application ~~Antelope II LBA~~process, ~~which~~for ~~was~~example ~~nominated~~the byfees ~~our~~associated ~~Antelope mine. These challenges have created some uncertainty~~ with ~~respect to~~ the ~~timing~~environmental ofanalysis ~~the~~or ~~LBA~~EIS, ~~bid~~ and ~~lease acquisition and may ultimately delay~~ the ~~leasing~~winning ~~process~~bidder orwill ~~prevent~~bear ~~mining~~those ~~operations~~costs. ~~Even~~Coal ~~after~~awarded athrough ~~lease~~the ~~has~~LBA ~~been~~process ~~issued~~ and asubject ~~successful~~to ~~bidder~~federal ~~has~~leases ~~paid~~are ~~installment~~administered ~~money~~by to the ~~BLM,~~U.S. ~~legal~~Department ~~challenges~~of ~~may~~Interior ~~still~~under ~~seek~~the toFederal ~~delay~~Coal orLeasing ~~prevent~~Amendment ~~mining~~Act ~~operations~~of 1976. ItOnce isthe ~~possible~~BLM ~~that~~has ~~subsequent~~issued ~~EISs~~a ~~for~~lease, ~~other~~the ~~mines~~company inmust ~~the~~next ~~PRB~~complete ~~currently~~the ~~underway~~permitting ~~but~~process ~~not~~before ~~yet~~it ~~final~~can ~~could~~mine bethe ~~similarly challenged~~coal. ~~There~~See ~~also~~Item ~~exists~~1 ~~the~~“Business—Environmental ~~possibility~~and ofOther ~~similar~~Regulatory ~~challenges~~Matters—Mining toPermits ~~the permitting~~ and ~~licensing process, which is also a public process designed to allow public comments~~Approvals.”

~~Each~~The ~~of our~~ federal coal ~~leases~~leasing ~~has~~process anis ~~initial~~designed ~~term~~to ofbe 20a ~~years~~public process, ~~renewable~~giving ~~for~~stakeholders ~~subsequent 10-year periods~~ and ~~for~~other sointerested ~~long~~parties ~~thereafter~~opportunities asto ~~coal~~comment ison ~~produced~~the inBLM’s ~~commercial~~proposed ~~quantities. The~~and ~~lease~~final ~~requires~~actions ~~diligent~~and ~~development~~allow ~~within~~third-party ~~the~~comments. Because ~~first~~of 10this, ~~years~~third ofparties, ~~the~~including ~~lease~~non-governmental ~~award~~organizations, ~~with~~can achallenge ~~required~~the ~~coal~~BLM’s ~~extraction~~actions, ofwhich 1%may ofdelay the ~~total~~leasing ~~coal~~process. If ~~under~~these ~~the~~challenges ~~lease~~prove bysuccessful ~~the~~or ~~end~~are oflitigated ~~that~~for ~~10-year~~a prolonged period~~. At~~ ~~the end~~ of ~~the 10-year development period~~time, ~~the~~a ~~lessee~~coal iscompany’s ~~required~~ability to ~~maintain~~bid ~~continuous~~on ~~operations,~~or asacquire ~~defined~~a innew ~~the~~coal ~~applicable~~lease ~~leasing~~could ~~regulations. In~~be ~~certain~~significantly ~~cases~~delayed, aor ~~lessee~~could ~~may~~cause ~~combine~~the ~~contiguous~~BLM ~~leases~~to ~~into~~not offer a ~~logical~~lease ~~mining~~for ~~unit,~~bid orat ~~LMU~~all. ~~This~~For ~~allows~~example, ~~the~~environmental ~~production~~organizations offiled ~~coal~~legal ~~from~~challenges ~~any~~against of the ~~leases~~BLM’s ~~within~~findings on the ~~LMU~~final toEIS beand ~~used~~other tomatters ~~meet~~associated ~~the~~with ~~continuous operation requirements for~~ the ~~entire~~West ~~LMU. We~~Antelope ~~currently~~II ~~have~~LBA, anwhich ~~LMU~~was ~~for~~nominated by our Antelope mine. WeSee ~~pay~~Item ~~to the federal government an annual rent of $~~3~~.00~~ ~~per~~“Legal ~~acre~~Proceedings—West ~~and~~Antelope ~~production~~II ~~royalties~~LBA ~~of 12~~Challenges.~~5% of gross revenues on surface mined coal.~~” ~~The~~These ~~federal~~types ~~government~~of ~~remits~~challenges ~~approximately~~create ~~50%~~some ofuncertainty ~~the~~with ~~production~~respect ~~royalty payments~~ to the ~~state~~timing ~~after deducting administrative expenses. Some~~ of ~~our~~future ~~mines~~LBA ~~are~~bids ~~also~~and ~~subject~~lease toacquisitions ~~coal~~and ~~leases~~may ~~with~~ultimately delay the ~~states~~leasing ofprocess ~~Montana~~ or ~~Wyoming,~~prevent asmining ~~applicable,~~operations. Even ~~and~~after ~~have~~a ~~different~~lease ~~terms~~has ~~and~~been ~~conditions~~issued ~~that~~and wea ~~must~~successful ~~adhere~~bidder tohas inpaid ainstallment ~~similar~~money ~~way~~ to ~~our~~the ~~federal leases. Under these federal and state leases~~BLM, iflegal ~~the~~challenges ~~leased~~may ~~coal~~still isseek ~~not~~to ~~diligently~~delay ~~developed~~or ~~during~~prevent ~~the~~mining ~~initial~~operations. It ~~10-year~~is ~~development~~possible ~~period~~that orsubsequent ifEISs ~~certain~~for other ~~terms~~mines ofin the ~~leases~~PRB ~~are~~currently underway but not ~~complied~~yet ~~with,~~final ~~including~~could ~~the~~be ~~requirement~~similarly tochallenged. There ~~produce~~also aexists ~~minimum~~the ~~quantity~~possibility of ~~coal~~similar orchallenges ~~pay~~to athe ~~minimum~~permitting ~~production~~and ~~royalty,~~licensing ~~if applicable~~process, ~~the~~which ~~BLM~~is oralso ~~the~~a ~~applicable~~public ~~state~~process ~~regulatory~~designed ~~agency can terminate the lease prior~~ to ~~the~~allow ~~expiration~~public ~~of its term~~comments.

~~Most~~Each of ~~the~~our federal coal weleases ~~lease~~has ~~from~~an ~~the~~initial ~~United~~term ~~States~~of ~~comes~~20 ~~from~~years, ~~“split~~renewable ~~estate”~~for ~~lands~~subsequent in10-year ~~which~~periods ~~one~~and ~~party,~~for ~~typically~~so ~~the~~long ~~federal~~thereafter ~~government,~~as ~~owns the~~ coal ~~and~~is aproduced ~~private~~in ~~party~~commercial ~~owns the surface~~quantities. InThe ~~order~~lease torequires ~~mine~~diligent ~~the~~development ~~coal~~within ~~we acquire through~~ the ~~LBA~~first ~~process,~~10 weyears ~~must also acquire rights to mine from the owners~~ of the ~~surface~~lease ~~lands~~award ~~overlying~~with ~~the~~a required coal~~. Certain~~ ~~federal~~extraction ~~regulations~~of ~~provide~~1% ~~a specific class~~ of ~~surface~~the ~~owners,~~total ~~Qualified~~coal ~~Surface~~under ~~Owners, or QSOs, with~~ the ~~ability~~lease toby ~~prohibit~~ the ~~BLM~~end ~~from~~of ~~leasing~~that ~~its~~10-year ~~coal~~period. ~~For~~At ~~example,~~the inend ~~connection~~of ~~with~~the a10-year ~~pending~~development ~~LBA~~period, ~~that~~the welessee ~~nominated~~is ~~for~~required ~~our~~to ~~Cordero~~maintain ~~Rojo~~continuous ~~mine~~operations, ~~the~~as ~~BLM~~defined ~~has~~in ~~indicated that certain surface owners satisfy~~ the ~~regulatory~~applicable ~~definition~~leasing ~~of QSO~~regulations. IfIn ~~the~~certain ~~land~~cases, ~~overlying~~ a ~~coal~~lessee ~~tract~~may iscombine ~~owned~~contiguous byleases ainto ~~QSO,~~an ~~federal~~LMU. This ~~laws~~allows ~~prohibit~~the usproduction ~~from~~of ~~leasing~~coal ~~the~~from ~~coal~~any ~~tract~~of ~~without~~the ~~first~~leases ~~securing~~within ~~surface~~the ~~rights~~LMU to ~~the~~be ~~land,~~used orto ~~purchasing~~meet the ~~surface~~continuous ~~rights~~operation ~~from~~requirements for the ~~QSO,~~entire ~~which~~LMU. We ~~would~~currently ~~allow~~have usan toLMU ~~conduct~~for our ~~mining~~Antelope ~~operations~~mine. ~~Furthermore,~~We ~~the~~pay ~~state permitting process requires us~~ to ~~demonstrate~~the ~~surface~~federal ~~owner~~government ~~consent~~an ~~for~~annual ~~split~~rent ~~estate~~of ~~lands~~$3.00 ~~before~~per ~~the~~acre ~~state~~and ~~will~~production ~~issue~~royalties aof ~~permit to mine coal~~12. ~~This~~5% ~~consent~~of isgross ~~separate~~revenue ~~from~~on ~~the~~surface ~~QSO~~mined ~~consent required before leasing federal~~ coal. The ~~right~~federal ofgovernment ~~QSOs~~remits ~~and~~approximately ~~certain~~50% ~~other~~of ~~surface~~the ~~owners~~production ~~allows~~royalty ~~them~~payments to ~~exercise~~the ~~significant~~state ~~influence~~after ~~over~~deducting ~~negotiations~~administrative ~~and~~expenses. Some ~~prices~~of toour ~~acquire~~mines ~~surface~~are ~~rights~~also ~~and~~subject ~~can~~to ~~delay~~coal ~~the~~leases ~~LBA~~with orthe ~~permitting~~states ~~processes~~of Montana or ~~ultimately~~Wyoming, ~~prevent~~as ~~the~~applicable, ~~acquisition~~and ofhave ~~the~~different ~~LBA~~terms orand ~~permit~~conditions ~~over~~ that ~~land~~we ~~entirely. There~~must ~~are~~adhere ~~QSOs~~to ~~that~~in ~~own~~a ~~land~~similar ~~adjacent~~way to orour ~~near~~federal ~~our~~leases. Under ~~existing~~these ~~mines~~federal ~~that~~and ~~may~~state beleases, ~~attractive~~if ~~acquisition~~the ~~candidates~~leased ~~for~~coal ~~us. Typically,~~is wenot ~~seek~~diligently todeveloped ~~purchase~~during the ~~land~~initial ~~overlying~~10-year ~~our~~development ~~coal~~period or ~~enter~~if ~~into~~certain ~~option~~other ~~agreements~~terms ~~granting~~of usthe anleases ~~option~~are tonot ~~purchase~~complied ~~the~~with, ~~land~~including ~~upon~~the ~~acquiring~~requirement anto ~~LBA. In~~produce ~~some~~a ~~instances,~~minimum ~~however,~~quantity weof ~~enter~~coal ~~into~~or ~~separate~~pay ~~lease~~a ~~arrangements~~minimum ~~with~~production ~~surface~~royalty, ~~owners~~if ~~allowing~~applicable, usthe toBLM ~~conduct~~or ~~our~~the ~~mining~~applicable ~~operations~~state onregulatory ~~the~~agency ~~land. We~~can ~~own~~terminate ~~substantially~~the ~~all~~lease ofprior to the ~~land~~expiration ~~over~~of ~~our~~its ~~reserves~~term.

WeMost ~~also~~of ~~enter~~the ~~into~~coal ~~surface~~we ~~leases~~lease ~~with~~from ~~other~~the ~~third~~United ~~parties~~States comes from ~~time~~“split toestate” ~~time. The~~lands ~~majority~~in ofwhich ~~these~~one ~~third-~~party, ~~leases~~such ~~have~~as the federal government, owns the coal and a ~~term~~private ~~that~~party ~~continues~~owns ~~until~~the surface. In order to mine the ~~exhaustion~~coal we acquire, we must acquire rights to mine from certain owners of the ~~“mineable~~surface ~~and~~lands ~~merchantable”~~overlying the coal. Certain infederal regulations provide a specific class of surface owners, QSOs, with the ~~lease~~ability ~~area~~to prohibit the BLM from leasing its coal. ~~Some~~For ofexample, ~~our~~in ~~leases~~connection ~~extend~~with an LBA tract that we previously nominated for aour ~~specific~~Cordero ~~number~~Rojo ofmine, ~~years~~the ~~rather~~BLM ~~than~~indicated tothat certain surface owners satisfied the ~~exhaustion~~regulatory definition of QSO. If the ~~particular~~land ~~mine’s~~overlying ~~reserves,~~a ~~but~~coal intract ~~all~~is ~~these~~owned ~~cases~~by a QSO, wefederal ~~believe~~laws ~~that~~prohibit us from leasing the ~~term~~coal oftract ~~years~~without ~~will~~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 ~~recoverable~~state ~~reserve~~permitting process requires us to bedemonstrate ~~fully~~surface ~~extracted~~owner inconsent ~~accordance~~for ~~with~~split ~~our~~estate ~~projected~~lands before the state will issue a permit to mine ~~plan~~coal. ~~Consistent~~This ~~with~~consent ~~industry~~is ~~practice,~~separate wefrom ~~conduct~~the ~~only~~QSO ~~limited~~consent ~~investigations~~required before leasing federal coal. The right of ~~title~~QSOs and certain other surface owners allows them to ~~our~~exercise ~~coal~~significant ~~properties~~influence ~~prior~~over negotiations and prices to ~~leasing~~acquire surface rights and can delay the federal coal lease or permitting processes or ultimately prevent the acquisition of the federal coal lease or permit over that land entirely. ~~Title~~There are QSOs that own land adjacent to ~~properties~~or ~~leased~~near ~~from~~our ~~private~~existing ~~third~~mines ~~parties~~that ismay ~~not~~be ~~usually~~attractive ~~fully~~acquisition ~~verified~~candidates ~~until~~for us. Typically, we ~~make~~seek ato ~~commitment~~purchase the land overlying our coal or enter into option agreements granting us an option to ~~develop~~purchase the land upon acquiring a ~~property,~~federal ~~which~~coal lease. We own substantially all of the land over our reserves. We may not ~~occur~~own ~~until~~or wecontrol ~~have~~the ~~obtained~~land ~~the~~over ~~necessary~~our ~~permits~~non-reserve ~~and~~coal ~~completed~~deposits, ~~exploration~~which ofwould ~~the~~be ~~property~~required before these non-reserve coal deposits could be classified as reserves and mined.

~~Office Space~~46

Our corporate headquarters is located in Gillette, Wyoming, where we own approximately 32,000 square feet of office space. In addition, we lease approximately 7,500 square feet of additional office space in Gillette, Wyoming, under

Table of Contents

~~two~~Most ~~annual~~of the coal we have acquired from private third parties is in the form of coal leases ~~expiring~~obtained onthrough ~~June 30~~private negotiations with one or more third parties. These leases generally include, ~~2011~~among other terms and ~~May 31~~conditions, ~~2012,~~a set term of years with the right to renew the lease for a stated period and weroyalties to be paid to the lessor as a percentage of the sales price. These leases may require payment of a lease ~~approximately~~bonus 28or minimum royalty,~~100~~ ~~square~~payable ~~feet~~either at the time of ~~office~~execution ~~space~~of the lease or in ~~Broomfield~~periodic installments, ~~Colorado~~and ~~under~~ a ~~lease~~minimum ~~that~~production ~~expires~~of coal from the leased areas in ~~February 2021~~order to hold the leases by active production. AsWe ofbelieve ~~December 31,~~that ~~2010,~~the ~~all~~term of ~~our~~years ~~long-lived~~will ~~assets~~allow ~~were~~the ~~located~~recoverable reserve to be fully extracted in ~~the~~accordance Uwith our projected mine plan.S. ~~See~~Consistent ~~Note~~with 18industry practice, we conduct only limited investigations of ~~Notes~~title to ~~Consolidated~~our ~~Financial~~coal ~~Statements~~properties inprior ~~Item~~to 8leasing. 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 31,000 square feet of office space. In addition, we lease approximately 7,500 square feet of additional office space in Gillette, Wyoming, under two annual leases expiring on April 15, 2015 and January 31, 2014, and we lease approximately 28,100 square feet of office space in Broomfield, Colorado under a lease that expires in February 2021. As of December 31, 2013, all of our long-lived assets were located in the U.S. See Note 16 of Notes to Consolidated Financial Statements in Item 8.

Item 3. Legal Proceedings.

~~MMS~~West ~~Litigation~~Antelope —II ~~Decker~~LBA ~~Mine~~Challenges

~~The~~Challenges ~~Minerals~~Against ~~Management~~the ~~Service,~~BLM’s orLeasing ~~MMS,~~Process; aIntervention ~~federal~~by ~~agency~~Cloud ~~with~~Peak ~~responsibility~~Energy ~~for~~and ~~collecting~~Others ~~royalties~~— onOn ~~coal~~May 3, ~~produced~~2010, ~~from~~WildEarth ~~federal~~Guardians, ~~coal~~Defenders ~~leases,~~of ~~issued~~Wildlife ~~two~~and ~~disputed~~Sierra ~~assessments~~Club ~~against~~(collectively, ~~Decker~~“WildEarth”) ~~Coal~~and ~~Company:~~the ~~one~~Powder ~~for~~River ~~coal~~Basin ~~produced~~Resource ~~from~~Council ~~1986-1992,~~(“PRBRC”) ~~and~~filed ~~the~~appeals ~~other~~with ~~for~~the ~~coal~~Interior ~~produced~~Board ~~from~~of ~~1993-2001. Both~~Land ~~assessments~~Appeals ~~concern~~(“IBLA”) ~~coal~~regarding ~~sold~~the byBLM ~~Decker~~decision to ~~Big~~offer ~~Horn~~the ~~Coal~~West ~~Company,~~Antelope orII ~~Big~~(“WAII”) ~~Horn,~~coal ~~and~~tracts ~~Black~~for ~~Butte~~lease. ~~Coal~~On ~~Company~~June 29, ~~or Black Butte~~2010, ~~and~~WildEarth involuntarily ~~turn~~dismissed ~~resold~~its byappeal. On ~~those~~July 13, ~~entities~~2010, toWildEarth ~~Commonwealth~~filed ~~Edison~~a ~~Company~~complaint toin ~~satisfy~~the ~~requirements~~United ~~under~~States ~~long-term~~District ~~contracts~~Court ~~between~~for ~~those~~the ~~entities~~District ~~and~~of ~~Commonwealth~~Columbia ~~Edison~~(“D. ~~The~~C. ~~MMS~~District ~~maintained~~Court”) ~~that~~challenging ~~Decker~~the BLM’s ~~royalties~~decision. On ~~should~~November 2, ~~not~~2010, bethe ~~based~~IBLA onissued ~~the~~a ~~prices~~decision atin ~~which~~PRBRC’s ~~Decker~~appeal, ~~actually~~rejecting ~~sold~~all ~~coal~~of toPRBRC’s ~~Big~~arguments ~~Horn~~ and ~~Black~~affirming ~~Butte~~the ~~because~~BLM’s ~~MMS~~decision ~~did~~in ~~not~~all ~~believe~~respects. On ~~those~~January 3, ~~prices~~2011, ~~represented~~PRBRC filed a complaint in the ~~results~~D.C. ofDistrict ~~arm’s~~Court ~~length~~appealing ~~negotiation~~the IBLA decision. ~~MMS~~On ~~based~~May 8, ~~this~~2011, ~~conclusion~~the onD.C. ~~the~~District ~~facts~~Court ~~that~~consolidated ~~those~~the ~~entities~~WildEarth ~~were~~and ~~both~~PRBRC ~~affiliates~~challenges. Antelope ofCoal ~~KCP~~LLC, ~~Inc.,~~ ~~formerly~~a ~~known~~wholly-owned assubsidiary ~~Kiewit~~of ~~Coal~~CPE ~~Properties~~Resources, ~~Inc.,~~ ~~which~~(along iswith ~~also~~the aNational ~~50%~~Mining ~~owner~~Association and the State of ~~Decker,~~Wyoming) ~~and~~intervened ~~that~~in the ~~sales~~consolidated ~~were~~action ~~contingent~~ on ~~Big~~the ~~Horn’s~~side ~~and~~of ~~Black~~the ~~Butte’s~~BLM. In ~~ability~~the toconsolidated ~~resell~~action, ~~the~~WildEarth ~~coal~~and toPRBRC ~~Commonwealth~~requested ~~Edison,~~that ~~which~~the ~~did~~court ~~not~~vacate ~~leave~~the ~~Big~~BLM’s ~~Horn~~authorization, sale and ~~Black~~issuance ~~Butte~~of atthe ~~market~~WAII ~~risk. Instead,~~leases ~~the~~and ~~MMS~~enjoin ~~assessed~~any ~~Decker’s~~coal ~~royalties~~mining ~~based~~activity on the ~~higher~~leases ~~prices~~until ~~set~~the ~~under~~BLM ~~Big~~and ~~Horn’s~~the U.S. Fish and ~~Black~~Wildlife ~~Butte’s~~Service ~~separate~~had ~~long-term~~undertaken ~~contracts~~additional ~~with~~environmental ~~Commonwealth~~analysis ~~Edison~~requested by the plaintiff organizations.

~~With~~Award ~~respect~~of LBAs to ~~the~~Cloud ~~period~~Peak ~~1986-1992~~Energy — On May 11, 2011, the ~~MMS~~BLM ~~assessment~~held ~~did~~a ~~not~~competitive ~~contain~~sale afor ~~specific~~the ~~dollar~~WAII ~~amount~~North Tract. ~~Decker~~On ~~appealed~~June ~~the~~15, ~~assessment~~2011, ~~through~~ the ~~administrative~~BLM ~~process~~held ~~with~~a ~~the~~competitive ~~MMS~~sale ~~and~~for ~~that~~the ~~appeal~~WAII ~~was~~South ~~unsuccessful~~Tract. AAntelope ~~further~~Coal ~~appeal~~LLC was ~~filed~~the ~~before~~successful ~~the~~high ~~United~~bidder ~~States~~in ~~District~~both ~~Court~~sales, ~~for~~and the ~~District~~BLM ofissued ~~Montana. In~~leases ~~March 2009,~~to ~~the~~Antelope ~~District~~Coal ~~Court~~LLC ~~set~~for ~~aside~~ the ~~MMS~~North ~~assessment~~Tract ~~and~~effective ~~entered~~July 1, ~~judgment~~2011 and for ~~Decker~~South ~~(“Decker~~Tract ~~I”). The~~effective ~~MMS~~September ~~did~~1, ~~not appeal the ruling~~2011.

~~With~~District ~~respect~~Court toRejection ~~the~~of ~~period~~Challenges; ~~1993-2001,~~Appeal ~~the~~by ~~MMS~~Plaintiffs ~~assessed~~— ~~approximately~~On $7July 30, 2012, the D.5C. ~~million~~District ~~plus~~Court ~~interest,~~rejected ~~which~~WildEarth’s ~~was~~and ~~estimated~~PRBRC’s consolidated challenge to bethe ~~approximately~~IBLA ~~$11~~decision ~~million~~and ~~inclusive~~denied oftheir ~~interest. Decker~~request ~~appealed~~that the ~~MMS~~court ~~assessment~~vacate ~~through~~ the ~~administrative~~WAII ~~process~~leases ~~with~~as ~~the~~well ~~MMS~~as ~~and~~their ~~that~~requested ~~appeal~~injunction ~~was~~against ~~unsuccessful~~coal mining activity on the leases. AOn ~~further~~September 25, ~~appeal~~2012 ~~was~~and September 26, 2012, PRBRC and WildEarth, respectively, filed ~~before~~notices of appeal in the United States ~~District~~Circuit Court of Appeals for the District of ~~Montana~~Columbia. InOral ~~February~~argument was held in November ~~2010,~~2013. Both groups appealed the ~~District~~decision ~~Court~~issued ~~vacated~~by the ~~administrative~~D.C. ~~order~~District ~~from~~Court ~~the~~and ~~Interior~~did ~~Board~~not ofspecify ~~Land~~what ~~Appeals~~relief ~~affirming~~they sought from the ~~MMS~~appellate ~~assessment. The~~court ~~District~~other ~~Court~~than ~~remanded~~for the ~~case~~appellate court to reverse the ~~MMS~~decision ~~for~~of ~~further~~the ~~review~~D.C. ~~and~~District ~~noted~~Court. Antelope ~~that~~Coal ~~the~~LLC ~~remand~~was ~~would~~a ~~not~~respondent-intervenor ~~unduly~~in ~~prejudice~~the ~~Decker~~consolidated inappeal. On ~~light~~December 24, 2013, the Court of Appeals affirmed the District Court’s ~~opinion~~grant inof ~~Decker~~summary Ijudgment to the defendants. ~~There~~It is nopossible ~~MMS~~the ~~assessment~~plaintiffs ~~currently~~could ~~pending~~seek ~~against~~review ~~Decker~~by ~~for~~the U.S Supreme Court. Any adverse outcome of the ~~1993~~appeal —could ~~2001~~adversely ~~period~~impact or delay our ability to mine the coal subject to the leases.

We have not accrued a liability in our consolidated financial statements with respect to this matter as any potential losses are not considered to be probable and reasonably estimable. If the MMS issues a new assessment for the 1993 — 2001 period, Decker believes it will have substantive challenges to any such assessment in light of the District Court’s decision in Decker I. Decker also believes that it has contractual price escalation protection from any increased assessments for 1993-2001; and that, in addition, Commonwealth Edison has indemnified Black Butte with respect to the 1993-2001 assessment, and that in furtherance of that obligation, Commonwealth Edison or its parent company, Exelon Generation, Inc., has therefore agreed to indemnify Decker directly for such matters. If a new assessment is issued by the MMS for the 1993 — 2001 period and is upheld and the indemnities and/or price protections were ultimately not available to Decker, the resulting Decker liability could be material. As a result of our 50% ownership interest in Decker, our financial results could in turn be materially adversely affected. We consider Decker’s conclusions to be reasonable; however, we have not relied upon Decker’s conclusions in reaching our decision that any potential losses are not considered probable and reasonably estimable.47

Caballo Coal Company Litigation — Spring Creek

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

Table of Contents

reasonably estimable. If, however, the case was determined in an adverse manner to us, the payment of any judgment could be material to our results of operations.

Other Legal Proceedings

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

Item 4. ~~Reserved.~~Mine Safety Disclosures

56The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Form 10-K.

~~Table of Contents~~48

~~PART II~~Table of Contents

PART II

AsCPE ofInc.’s ~~December 31~~common stock, ~~2010~~$0.01 par value, ~~there~~has ~~was~~traded noon ~~public~~the ~~trading~~New ~~market~~York ~~for~~Stock ~~our~~Exchange ~~common~~(“NYSE”) ~~membership~~under ~~units~~the symbol “CLD” since November 20, ~~100%~~2009. Prior ofto ~~which~~November 20, ~~were~~2009, ~~held~~there bywas ~~Cloud~~no ~~Peak~~public ~~Energy~~market for CPE Inc.’s common stock.

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

	High		Low
Fiscal 2013
First Quarter 2013	$	19.99	$	15.44
Second Quarter 2013	$	20.30	$	16.17
Third Quarter 2013	$	17.43	$	14.25
Fourth Quarter 2013	$	18.58	$	14.38

Fiscal 2012
First Quarter 2012	$	20.22	$	15.93
Second Quarter 2012	$	16.91	$	14.09
Third Quarter 2012	$	19.74	$	15.51
Fourth Quarter 2012	$	21.47	$	17.94

As of the close of business on January 31, 2014, there were 157 holders of record of CPE Inc.’s common stock.

Dividend Policy

We dohave not ~~pay~~historically paid, and we do not anticipate ~~paying~~that we will pay in the near term, ~~any~~cash dividends on ~~our~~CPE ~~membership~~Inc.’s ~~units~~common stock. ~~Periodically~~Any wedetermination ~~have~~to ~~made,~~pay ~~and~~dividends ~~will~~to ~~continue~~holders toof ~~make,~~CPE ~~distributions~~Inc.’s tocommon ~~Holdings~~stock ~~pursuant~~in tothe future will be at the ~~limited~~discretion ~~liability~~of ~~company~~our ~~agreement~~Board toof ~~fund~~Directors ~~Holdings’s~~and ~~required~~will ~~payments~~depend toon ~~RTEA~~many ~~under~~factors, ~~the~~including ~~Tax~~our ~~Receivable~~financial ~~Agreement. The~~condition; ~~indenture~~results ~~that~~of ~~governs~~operations; ~~the~~general ~~senior~~business ~~notes~~conditions; ~~restricts~~contractual restrictions, including those under our debt instruments; capital requirements; business prospects; restrictions on the payment of dividends under Delaware Law; and ~~distributions~~any other factors our Board of Directors deems relevant. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”—Liquidity and ~~Note~~Capital 9Resources—Senior ~~within~~Notes” ~~Item~~and 8. “~~Notes~~—Senior toSecured ~~Consolidated~~Revolving ~~Financial~~Credit ~~Statements~~Facility.”

Stock Performance Graph

The following performance graph compares the cumulative total return on CPE Inc.’s common stock with the cumulative total return of the following indices: (i) the Standard & Poor’s (“S&P”) MidCap 400 stock index and (ii) the Custom Composite Index. The Custom Composite Index is comprised of the peer group that is associated with our performance-based share units issued under our Long-Term Incentive Plan. In 2012, this group was comprised of Alpha Natural Resources, Inc., Arch Coal, Inc., CONSOL Energy, Inc., Peabody Energy Corp., James River Coal Company, Walter Energy, Inc., Alliance Resource Partners, Berry Petroleum, Cabot Corporation, EQT Corporation, Forest Oil Corporation, Newfield Exploration Company, Noble Energy Inc., Penn Virginia Corporation, Sandridge Energy Inc., SM Energy Company, and Whiting Petroleum Corporation (collectively, the “Old Index”). Each year the compensation committee of our Board of Directors seeks to refine this group, if deemed appropriate in the judgment of the compensation committee, to be the most representative comparable companies for purposes of our performance-based share units. The current group includes those listed above, adds Oxford Resources Partners, Rhino Resource Partners, SunCoke Energy Inc., and Westmoreland Coal Co., and replaces the Cabot Corporation with the Cabot Oil and Gas Corporation (collectively, the “New Index”).

The graph assumes that you invested $100 in CPE Inc.’s common stock and in each index at the closing price on November 20, 2009, that all dividends were reinvested and that you continued to hold your investment through December 31, 2013.

Table of Contents

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

Company/ Market/ Peer Group	Nov 2009		Dec 2009		Dec 2010		Dec 2011		Dec 2012		Dec 2013
CPE Inc.	$	100.00	$	98.11	$	156.54	$	130.19	$	130.26	$	121.29
S&P MidCap 400 Index	$	100.00	$	105.90	$	134.11	$	131.78	$	155.34	$	207.39
New Index	$	100.00	$	108.69	$	142.45	$	110.53	$	99.25	$	124.42
Old Index	$	100.00	$	108.53	$	145.50	$	106.65	$	92.11	$	111.23

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.

Issuer Purchases of Equity Securities

The table below represents information pursuant to Item 703 of Regulation S-K regarding all share repurchases for the three-month period ended December 31, 2013:

	Total Number of Shares Purchased (1)	Average Price per Share
October 1 through October 31, 2013	—	$	—
November 1 through November 30, 2013	—	—
December 1 through December 31, 2013	650	17.48
Total	650	$	17.48

(1) Represents shares withheld to cover withholding taxes upon the vesting of restricted stock.

Item 6. Selected Financial Data.

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

We have derived the historical consolidated financial data as of December 31, 2010 and 2009 and for each of the three years in the period ended December 31, 2010 from our audited consolidated financial statements included in Item 8 of this report. We have derived the historical consolidated balance sheet data as of December 31, 2008, 2007 and 2006 and the historical consolidated statement of operations data for the years ended December 31, 2007 and 2006 from the audited consolidated financial statements of RTEA not included in this report.50

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

As a result of the IPO and the IPO structuring transactions, we now conduct substantially all activities necessary for Holdings to fulfill its responsibilities as a separate, stand-alone public company. Consequently, our cost structure is different than it was when we were a subsidiary of Rio Tinto. It includes both additional recurring costs and nonrecurring costs. Accordingly, our historical consolidated financial information is not reflective of our financial position, results of operations or cash flows had Holdings been a separate, stand-alone public company during all of the periods presented, and is not a reliable indicator of what our financial position, results of operations or cash flows will be in the future.

Table of Contents

We have derived the historical consolidated financial data as of December 31, 2013 and 2012 and for each of the three years in the period ended December 31, 2013 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, 2011, 2010 and 2009 and the historical consolidated statements of operations data for the years ended December 31, 2010 and 2009 from our audited consolidated financial statements not included in this report.

Our historical financial information for all periods prior to the IPO included in this Form 10-K was derived from the consolidated financial statements of Rio Tinto and also includes allocations of certain general and administrative costs and Rio Tinto’s headquarters costs. These expenses are estimates and were based on what we and Rio Tinto considered to be reasonable allocations of the historical costs incurred by Rio Tinto to provide these services required in support of our business. As a separate, stand-alone public company, our cost structure is different; accordingly, our historical consolidated financial information is not necessarily reflective of our financial position, results of operations or cash flows or costs had we been a separate, stand-alone public company during all of the periods presented.

Selected Consolidated Financial and Other Data

	Year Ended December 31,
	2010		2009		2008			2007			2006
CPE Inc.	2013		2012		2011			2010			2009
	(dollars in thousands)
	(in millions, except per share amounts)
Statement of Operations Data
Revenues	$	1,370,761	$	1,398,200	$	1,239,711		$	1,053,168		$	942,841
Revenue	$	1,396.1	$	1,516.8	$	1,553.7		$	1,370.8		$	1,398.2
Operating income(1)	211,923		255,003		124,936			102,731			88,868
Operating income	112.4		241.9		250.5			211.9			255.0
Income from continuing operations	~~170,453~~52.0		~~186,688~~173.7		~~88,340~~189.8			~~53,789~~117.2			~~40,537~~182.5
Income (loss) from discontinued operations(2)	—		211,078		(25,215		)	(21,482		)	(2,599		)
Income (loss) from discontinued operations	—		—		—			—			211.1
Net income	~~170,453~~52.0		~~397,766~~173.7		~~63,125~~189.8			~~32,307~~117.2			~~37,938~~393.6
Amounts attributable to controlling interest (1)
Income from continuing operations	52.0		173.7		189.8			33.7			170.6
Income (loss) from discontinued operations	—		—		—			—			211.1
Net income	52.0		173.7		189.8			33.7			381.7
Earnings per share attributable to controlling interest — basic (1)(2)
Income from continuing operations	$	0.86	$	2.89	$	3.16		$	1.06		$	3.01
Income (loss) from discontinued operations	$	—	$	—	$	—		$	—		$	3.73
Net income	$	0.86	$	2.89	$	3.16		$	1.06		$	6.74

Filing Compare · Cloud Peak Energy Resources LLC