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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC  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 fiscal year ended December 31, 2015

or

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

For the transition period from          to

Commission File Number: 001-34547

Cloud Peak Energy Inc.

(Exact name of registrant as specified in its charter)

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

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:
None

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

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

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

As of June 30, 2015, the last business day of Cloud Peak Energy Inc.’s most recently completed second fiscal quarter, the aggregate market value of the voting and non-voting common stock held by non-affiliates of Cloud Peak Energy Inc. was approximately $284 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 $4.66 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,  61,170,093  shares outstanding as of February 11, 2016.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Cloud Peak Energy Inc.’s proxy statement to be filed with the Securities and Exchange Commission in connection with Cloud Peak Energy Inc.’s 2016 annual meeting of stockholders (the “Proxy Statement”) are incorporated by reference into Part III hereof.  Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.

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CLOUD PEAK ENERGY INC.

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Unless the context indicates otherwise, the terms “Cloud Peak Energy,” the “Company,” “we,” “us,” and “our” refer to Cloud Peak Energy Inc. and its subsidiaries.

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CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

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

·                  the timing and extent of any recovery of the currently depressed coal industry, domestically and internationally, and the impact of ongoing or further depressed industry conditions on our financial performance and liquidity;

·                  the prices we receive for our coal and logistics services, our ability to effectively execute our forward sales strategy, and changes in utility purchasing patterns resulting in increased short-term and spot purchases of coal;

·                  competition with other producers of coal and with traders and re-sellers of coal, including the current oversupply of thermal coal in the marketplace, the impacts of currency exchange rate fluctuations and the strong U.S. dollar, and government environmental, energy and tax policies and regulations that make foreign coal producers more competitive for international transactions;

·                  competition with natural gas and other non-coal energy resources, which may continue to increase as a result of low domestic natural gas prices and due to environmental, energy and tax policies, regulations, subsidies and other government actions that encourage or mandate use of alternative energy sources;

·                  coal-fired power plant capacity and utilization, including the impact of climate change and other environmental regulations and initiatives, energy policies, political pressures, NGO activities, international treaties or agreements and other factors that may cause domestic and international electric utilities to continue to phase out or close existing coal-fired power plants, reduce or eliminate construction of any new coal-fired power plants, or reduce consumption of coal from the Powder River Basin (“PRB”);

·                  the failure of economic, commercially available carbon capture technology to be developed and adopted in a timely manner;

·                  the impact of well-funded, anti-coal initiatives by environmental activist groups and others;

·                  the impact of weather and economic conditions on demand for overall power generation and coal-fired generation, domestically and internationally;

·                  our ability to offset declining U.S. demand for coal and achieve longer term growth in our business through our logistics revenue and export sales, including the significant impact of Chinese and Indian thermal coal import demand on overall seaborne coal prices;

·                  railroad, export terminal and other transportation performance, costs and availability, including the availability of sufficient and reliable rail capacity to transport PRB coal, the development of future export terminal capacity and our ability to access capacity on commercially reasonable terms;

·                  the impact of our substantial rail and terminal take-or-pay commitments if we do not meet our required export shipment obligations;

·                  timing of reductions or increases in customer coal inventories;

·                  weather conditions and weather-related damage that impact our mining operations, our customers, or transportation infrastructure;

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·                  risks inherent to surface coal mining;

·                  our ability to successfully acquire coal and appropriate land access rights at economic prices and in a timely manner and our ability to effectively resolve issues with conflicting mineral development that may impact our mine plans;

·                  our ability to adjust our planned production levels to respond to market conditions and effectively manage the costs of our operations;

·                  the impact of asset impairment charges if required as a result of challenging industry conditions or other factors;

·                  our plans and objectives for future operations and the development of additional coal reserves, including risks associated with acquisitions;

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

·                  the impact of required regulatory processes and approvals to lease coal and obtain permits for coal mining operations or to transport coal to domestic and foreign customers, including third-party legal challenges to regulatory approvals that are required for some or all of our current or planned mining activities;

·                  any increases in rates or changes in regulatory interpretations or assessment methodologies with respect to royalties or severance and production taxes and the potential impact of associated interest and penalties;

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

·                  our ability to obtain required surety bonds and provide any associated collateral on commercially reasonable terms and our ability to continue to self-bond;

·                  disruptions in delivery or increases in pricing from third-party vendors of raw materials and other consumables which are necessary for our operations, such as explosives, petroleum-based fuel, tires, steel, and rubber;

·                  our assumptions concerning coal reserve estimates;

·                  our relationships with, and other conditions affecting, our customers (including our largest customers who 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;

·                  the results of our hedging strategies for commodities, including our hedging programs for domestic and international 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 debt and equity capital and credit market conditions for the coal sector or in general, changes in our credit rating, our compliance with the covenants in our debt agreements, the increasing credit pressures on our industry due to depressed conditions, or any demands for cash collateral by our surety bond providers;

·                  volatility and recent decline in the price of our common stock, including the impact of any delisting of our stock from the New York Stock Exchange (“NYSE”) if we fail to meet the minimum average closing price listing standard;

·                  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.

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GLOSSARY FOR SELECTED TERMS

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

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

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

Bituminous coal.  The most common type of coal that is between subbituminous and anthracite in rank.  Bituminous 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.

Btu.  British thermal unit.  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).

CAA.  Clean Air Act.

CAIR.  Clean Air Interstate Rule.

CEQ.  Council on Environmental Quality.

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

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

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.

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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.

IR.  Incident rate.  The rate of injury occurrence, as determined by MSHA, based on 200,000 hours of employee exposure and calculated as follows:

IR = (number of cases 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 BLM then reviews the proposed tract to ensure maximum coal recovery.  The BLM also requires completion of a detailed environmental assessment or an 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.

NEPA. National Environmental Policy Act.

NGO.  Non-governmental organization.

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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.

ONRR. Department of the Interior, Office of Natural Resources Revenue.

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 coal mining operations.  Reclamation is closely regulated by both state and federal laws.

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

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

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

Riverine habitat.  A habitat occurring along a river.

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

SMCRA.  Surface Mining Control and Reclamation Act of 1977.

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

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

Sulfur.  One of the elements present in varying quantities in coal.  Sulfur dioxide (“SO2”) is produced as a gaseous by-product of coal combustion.

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

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

Tax agreement liability.  The undiscounted estimated future liability previously owed by CPE Inc. to Rio Tinto under the Tax Receivable Agreement.

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.

TRA. 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 required us to pay to RTEA 85% of the amount of cash tax savings, if any, that we realized 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.  In August 2014, we entered into an acceleration and release agreement with Rio Tinto whereby we agreed to pay $45 million to Rio Tinto to terminate the Tax Receivable Agreement.

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.

UP.  Union Pacific Railroad.

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PART I

Item 1.  Business.

Overview

We are one of the largest producers of coal in the United States of America (“U.S.”) and the PRB, based on our 2015 coal sales.  We operate some of the safest mines in the coal industry.  According to the most current MSHA data, we have one of the lowest employee all injury incident rates among the largest U.S. coal producing companies.  We currently operate solely in the PRB, the lowest cost region of the major coal producing regions in the U.S., where we own and operate three surface coal mines: the Antelope Mine, the Cordero Rojo Mine, and the Spring Creek Mine.

Our Antelope Mine and Cordero Rojo Mine are located in Wyoming and 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.  In 2015, the coal we produced generated approximately 3% of the electricity produced in the U.S.  As of December 31, 2015, we controlled approximately 1.1 billion tons of proven and probable reserves.

On August 24, 2015, we entered into a surface rights agreement that provided our Cordero Rojo Mine with access to approximately 95 million tons of additional coal contained within a federal coal lease controlled by the mine.  These additional tons were evaluated as part of the year-end reserve reporting process and were determined to be proven and probable reserves as of December 31, 2015.  The agreement involved a land exchange and production payments from any future sales of the underlying coal, including certain recoupable advance production payments.

In addition, we have two development projects.  The Youngs Creek project, an undeveloped surface mine project in the Northern PRB region, is located in Wyoming, approximately 13 miles north of Sheridan, Wyoming, seven miles south of our Spring Creek Mine and seven miles from the mainline railroad, contiguous with the Wyoming-Montana state line.  We have not been able to classify the Youngs Creek project mineral rights as proven and probable reserves as they remain subject to further exploration and evaluation based on market conditions.  We also have an option to lease agreement and a corresponding exploration agreement with the Crow Tribe of Indians (the “Big Metal project”).  The Big Metal project is located on the Crow Indian Reservation in southeast Montana and is near the Youngs Creek project.  We are in the process of evaluating development options for the Youngs Creek project and the Big Metal project and believe that their proximity to the Spring Creek Mine represents an opportunity to optimize our mine developments in the Northern PRB.  For purposes of this report, the term “Northern PRB” refers to the area within the PRB that lies within Montana and the northern part of Sheridan County, Wyoming.

In 2015, we addressed the impact of current low seaborne thermal coal prices for international coal sales and mitigated our associated losses and take-or-pay exposure in our logistics business.  On October 28, 2015, we announced an amended agreement with Westshore Terminals Limited Partnership (“Westshore”) providing an upfront payment during the fourth quarter of 2015 and quarterly payments from 2016 through 2018 in lieu of the previous take-or-pay commitments during this three-year period.  Except as amended, the throughput agreement remains in place through the end of 2024.  On December 1, 2015, we announced a similar amendment to our transportation agreement with BNSF.  We will continue to meet regularly with Westshore and BNSF during the next several years to discuss market conditions, potential shipments, and the terms for such shipments.  Spring Creek Mine production volumes will be reduced as export shipments do not occur.

In addition to our agreement with Westshore, we hold option contracts to potentially increase our future export capacity through two proposed Pacific Northwest export terminals.  We have a throughput option agreement, which provides us with an option for up to 17.6 million tons of capacity per year through the planned dry bulk cargo Gateway Pacific Terminal (“GPT”) at Cherry Point in Washington State.

We also have a throughput option for up to 7.7 million tons per year at the proposed Millennium Bulk Terminals (“MBT”) coal export facility in Washington State.  Our options in each of these proposed terminals are exercisable following the successful completion of the ongoing permit process, each of which is currently in the environmental impact statement phase.  The timing and outcome of these permit processes, and therefore the construction of the terminals, are uncertain.

On August 13, 2015, we announced that we and the Crow Tribe joined SSA Marine as 49% partners in GPT.  Under the new ownership structure, SSA Marine remained the majority owner, retaining 51% of the equity.  The Crow Tribe has an option to secure up to 5%, with a corresponding reduction in our ownership.  For our 49% ownership interest, we paid $2

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million upon signing and will pay all future permitting expenses up to $30 million, which we anticipate will cover such expenses through 2019.  Thereafter, the owners will share any permitting expenses in excess of $30 million in proportion with their ownership interests.  As of December 31, 2015, we have paid $6.6 million toward permitting expenses as a partner in GPT.  We have the right to exit the partnership, at our discretion at any time during the permitting phase, with no further obligation, beyond any pending capital calls requested by the joint venture prior to our exit of the partnership.

Segment Information

Our reportable segments include Owned and Operated Mines and Logistics and Related Activities.  For a discussion on these segments, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations as well as Note 24 of Notes to Consolidated Financial Statements in Item 8.

History

CPE Inc., a Delaware corporation organized on July 31, 2008, is a holding company that manages its 100% 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 100% 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 100% owned subsidiary of RTA on March 1, 1993.  Between 1993 and 1998, RTEA acquired the Antelope Mine, Colowyo Mine, Jacobs Ranch Mine and Spring Creek Mine and the Cordero and Caballo Rojo coal mines, which are operated together as the Cordero Rojo Mine, and a 50% non-operating interest in the Decker 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, and on September 12, 2014, we sold our 50% interest in the Decker Mine to an affiliate of Ambre Energy North America, Inc. (“Ambre Energy”), now known as Lighthouse Resources Inc.

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 100% 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 economic marketing and transportation of thermal coal.  We mine, process, and market low sulfur content, subbituminous 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 thermal coal.

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.

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Sulfur Content

Federal and state environmental regulations, including regulations that limit the amount of sulfur dioxide that may be emitted as a result of combustion, have affected and may continue to affect the demand for certain types of coal.  See “Environmental and Other Regulatory Matters—Clean Air Act.”  The sulfur content of coal can vary from seam to seam and within a single seam.  The concentration of sulfur in coal affects the amount of sulfur dioxide produced in combustion.  Coal-fired power plants can comply with sulfur dioxide emissions regulations by burning coal with low sulfur content, blending coals with various sulfur contents, purchasing emission allowances on the open market and/or using sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by up to 90%.

PRB coal typically has a lower sulfur content than eastern U.S. coal and generally emits no greater than 1.2 pounds of sulfur dioxide per million Btus.

Other

Ash is the inorganic residue remaining after the combustion of coal.  As with sulfur content, ash content varies from seam to seam.  Ash content is an important characteristic of coal because it impacts boiler performance and electric generating plants must handle and dispose of ash following combustion.  The ash content of PRB coal is generally low, representing approximately 5% to 10% by weight.  The composition of the ash, including the proportion of sodium oxide, as well as the ash fusion temperatures are important characteristics of coal and help determine the suitability of the coal to specific end users.  In limited cases, 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 20% to 30%.

Mercury and chlorine are trace elements within coal that are of primary consideration relative to utility plant emissions and performance.  Trace amounts of mercury and chlorine in PRB coal are relatively low compared to coal from other 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 with explosives.  The overburden is then removed with draglines, trucks, shovels, and dozers.  Trucks and shovels then remove the coal.  The final step involves replacing the overburden and topsoil after the coal has been excavated, reestablishing vegetation into the natural habitat and making other changes designed to provide local community benefits.  We typically recover 90% or more of the economic coal seam for the mines we operate.

Coal Preparation and 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, 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 Mine’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 currently own the majority of the equipment utilized in our mining operations.  We employ preventative maintenance and rebuild programs and upgrade our equipment as part of our efforts to ensure that it is productive, well-

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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, 2015.

(1)                                 We expect to reduce Spring Creek production to approximately 12 million tons per year for 2016 primarily due to the lack of any anticipated export sales.

(2)                                 Tons sold numbers reflect our 50% non-operating interest through our September 12, 2014 divestiture.

(3)                                 The tonnage shown for “Other” represents our purchases from third-party sources that we have resold.  See “—Mining Operations—Broker Sales and Third-Party Sources.”

Our Owned and Operated Mines segment includes our Antelope Mine, Cordero Rojo Mine, and Spring Creek Mine.  Our Antelope and Cordero Rojo mines are served by the BNSF and UP railroads.  Our Spring Creek Mine is served solely by the BNSF railroad.

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 thermal coal from the Anderson and Canyon Seams, with up to 44 and 36 feet, respectively, in thickness.  Significant areas of unleased coal north and west of the mine are available for nomination by us or other mining operations or persons.  Based on the average sulfur content of 0.50 lbs SO2/mmBtu, the reserves at our Antelope Mine are considered to be compliance coal under the Clean Air Act, and this coal is some of the lowest sulfur coal produced in the PRB.

Cordero Rojo Mine

The Cordero Rojo Mine is located approximately 25 miles south of Gillette, Wyoming.  The mine extracts thermal coal from the Wyodak Seam, which ranges from approximately 55 to 70 feet in thickness.  On August 24, 2015, we entered into a surface rights agreement that provided our Cordero Rojo Mine with access to approximately 95 million tons of

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additional coal contained within a federal coal lease controlled by the mine.  These additional tons were evaluated as part of the year-end reserve reporting process and were determined to be proven and probable reserves as of December 31, 2015.  We previously nominated as an LBA a large coal tract adjacent to our existing operation.  The BLM divided this LBA into two tracts, Maysdorf II North and Maysdorf II South.  The Maysdorf II North tract was offered in August 2013 and no bids were submitted.  Our decision not to bid was made in light of market conditions and access issues to the coal.  We understand that the BLM is expecting to delay any future lease sale on the Maysdorf II South tract until current weak markets improve and the expiration of the BLM’s moratorium on new coal leases.  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.

Spring Creek Mine

The Spring Creek Mine is located in Montana approximately 20 miles north of Sheridan, Wyoming.  The mine extracts thermal coal from the Anderson-Dietz Seam, which averages approximately 80 feet in thickness.  The location of the mine relative to the Great Lakes is attractive to our customers in the northeast because of lower transportation costs.  The location of the Spring Creek Mine also provides access to export terminals in the Pacific Northwest, providing a geographic advantage relative to other PRB mines.  In 2015, we shipped approximately 3.6 million tons of Spring Creek coal through terminals located in British Columbia, Canada.  In light of depressed international conditions, we currently do not expect to export any Spring Creek Mine coal in 2016.  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.

Development Projects

Youngs Creek Project

The Youngs Creek project, an undeveloped surface mine project in the Northern PRB region, is located in Wyoming, approximately 13 miles north of Sheridan, Wyoming, seven miles south of our Spring Creek Mine and seven miles from the mainline railroad, contiguous with the Wyoming-Montana state line.  It is near the Big Metal 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 approximately 272 million tons benefit from a royalty rate of 8.0% of the coal sales price free on board (“FOB”) at the mine site, payable to the sellers, which is below the normal 12.5% royalty rate payable on federal coal.  We control additional leased and private coal related to the Youngs Creek project that has not yet been evaluated and is not yet in any mine plan.  We also acquired approximately 38,800 acres of surface rights which includes land extending north to our Spring Creek Mine, and onto the Crow Indian Reservation to the west.  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 Big Metal project represent an opportunity to optimize our mine developments in the Northern PRB region.

Big Metal Project

In January 2013, we entered into 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.  In 2014 and 2013, we paid the Crow Tribe $1.5 million and $3.75 million, respectively, for the option agreement.  During the year ending December 31, 2015, we made additional option payments of $1.5 million.  We will continue to make annual option payments throughout the term of the option agreement, which, during the initial option period could total up to $10 million.  The option and 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 price FOB at the mine site and contain standard coal production taxes to be paid to the Crow Tribe.  The coal located at the Big Metal project is similar quality to that of our Spring Creek Mine and offers lower sodium levels.  We completed the exploration program and are 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.

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The map below shows where the Youngs Creek project and Big Metal project (Squirrel Creek, Tanner Creek, and Upper Youngs Creek coal deposits) are located relative to our Spring Creek Mine.

(1)                                 Non-reserve coal deposits are not reserves under SEC Industry Guide 7.  Estimates of non-reserve coal deposits are subject to further exploration and development, are more speculative, and may not be converted to future reserves of the company.

Customers, Contracts and Logistics Services

We focus on building long-term relationships with customers through our reliable performance and commitment to customer service.  We supply coal to 55 domestic and foreign electric utilities and over 71% of our sales were to customers with an investment grade credit rating as of December 31, 2015.  Furthermore, 86% of our 2015 sales were to customers with whom we have had relationships for more than 10 years.  During 2015, approximately 47% of our consolidated revenue was derived from our top ten customers.  No customer accounted for 10% or more of our total revenue in 2015.  A significant portion of our 2015 revenue for the Logistics and Related Activities segment was derived from entities owned or controlled by Korea Electric Power Corporation.  For 2016, in light of depressed international conditions, we currently do not expect to have any export sales.

Coal produced approximately 34% of electricity generation in the U.S. through November 2015.  The following map shows the percentage of our tons sold by state of destination during 2015 from coal produced at the three mines we own and operate.  Our coal supplies fueled approximately 3% of the electricity generated in the U.S. in 2015.  We also supplied approximately 5% of the tons produced at our mines to customers outside of the U.S. in 2015.

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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 typically 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, at market prices, as well as the contracting and coordination of the transportation and other handling services from third-party operators, which are typically rail and terminal companies.  Our 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.

Mine Customers

Long-term Coal Sales Agreements

As is customary in the coal industry, we generally enter into fixed price, fixed volume supply contracts with our mine customers.  Contracts with our mine customers generally have terms of one to five years, although some are as short as one to six months and others may be longer than ten years.  For the year ended December 31, 2015, approximately 67% of our total revenue attributable to our Owned and Operated Mines segment was derived from long-term supply contracts with terms of one year or greater, and approximately 16% of our committed tons to mine customers was associated with contracts that had three years or more remaining on their 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.

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

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.  Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts.  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-delivered average sulfur content of our coal, or both.

Contracts with our mine customers also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers for the duration of specified events beyond the control of the affected party, including

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events such as strikes, adverse mining conditions, mine closures or serious transportation problems that affect us or unanticipated plant outages that may affect the buyer.  These contracts generally provide that, in the event a force majeure circumstance exceeds a certain time period (e.g., 60-90 days), the unaffected party may have the option to terminate the transaction or transactions under the agreement.  Some of those contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer.  Generally, contracts with our mine customers 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 under the terms of the contract between the mine customer and the railroad.

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

Generally, under the terms of our coal supply contracts, we agree to indemnify or reimburse our customers for damage to their or their rail carrier’s equipment resulting from our negligence, and for damage to their equipment due to non-coal materials being included with our coal before leaving our property.

Transportation

Transportation is typically one of the largest components of a purchaser’s total cost.  Coal used for domestic consumption by our mine customers is typically sold FOB at the mine or nearest loading facility, and the purchaser of the coal bears the transportation costs and risk of loss.  Most electric generators arrange long-term shipping contracts with rail or barge companies to assure stable delivery costs.  Our Antelope and Cordero Rojo mines are served by the BNSF and UP railroads.  Our Spring Creek Mine is served solely by the BNSF railroad.

Although the purchaser pays the freight, transportation costs still are important to coal mining companies because the purchaser will consider the delivered cost of coal, including transportation costs, in determining from which mines it will purchase.  Transportation costs borne by the customer vary greatly based on each customer’s proximity to the mine.

Logistics Customers

Long-term Coal Sales Agreements

We generally enter into binding contracts that are fixed-price, fixed-volume supply contracts with our domestic logistics customers.  Contracts with these 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.

With our international logistics customers, we have contracts that contain evergreen clauses, meaning that there is an expectation of sales, provided that mutual agreement on pricing can be reached.  Given the current depressed pricing environment, we have agreed with customers to halt shipments until prices recover.  This is consistent with conventional industry standards for sales into the Asian Pacific region.  Should sales recommence it is expected that our Asian delivered shipments will be 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 75% of the forward Newcastle price.

Contracts with our logistics customers include terms similar to those described for our mine customers and may also include terms relating to:

·                  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

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·                  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 port 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.  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 agreement with 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 export sales, 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 make 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 for a portion of our anticipated export sales through their export terminal in Vancouver, British Columbia.  In August 2014, we increased our long-term committed capacity at Westshore from 2.8 million tons to 6.3 million tons initially and increasing to 7.2 million tons in 2019.  In addition, the revised agreement extended the term of our throughput agreement by two years through the end of 2024.

In 2015, we addressed the impact of current low seaborne thermal coal prices for international coal sales and mitigated our associated losses and take-or-pay exposure in our logistics business.  On October 28, 2015, we announced an amended agreement with Westshore providing an upfront payment during the fourth quarter of 2015 and quarterly payments from 2016 through 2018 in lieu of the previous take-or-pay commitments during this three-year period. Except as amended, the throughput agreement remains in place through the end of 2024.  On December 1, 2015, we announced a similar amendment to our transportation agreement with BNSF.  We will continue to meet regularly with Westshore and BNSF during the next several years to discuss market conditions and any potential shipments and the terms for any shipments.  Spring Creek Mine production volumes will be reduced as export shipments do not occur.

In addition to our agreement with Westshore, we hold option contracts to potentially increase our future export capacity through proposed Pacific Northwest export terminals.  We have a throughput option agreement with SSA Marine, which provides us with an option for up to 17.6 million tons of capacity per year through the planned GPT in Washington State.

We also have a throughput option for up to 7.7 million tons per year at the proposed MBT coal export facility in Washington State.  Our throughput capacity will have an initial term of 10 years, with four renewal options for five-year terms.  Our options in each of these proposed terminals are exercisable following the successful completion of the ongoing permit process, each of which is currently in the environmental impact statement phase.  The timing and outcome of these permit processes, and therefore the construction of the terminals, are uncertain.

On August 13, 2015, we announced that we and the Crow Tribe are joining SSA Marine as 49% partners in GPT.  Under the new ownership structure, SSA Marine remains the majority owner, retaining 51% of the equity. The Crow Tribe has an option to secure up to 5%, with a corresponding reduction in our ownership.  For the 49% ownership interest, we paid $2 million upon signing and will pay all future permitting expenses up to $30 million, which we anticipate will cover such expenses through 2019.  Thereafter, the owners will share any permitting expenses in excess of $30 million in proportion with their ownership interests.  As of December 31, 2015, we have paid $6.6 million toward permitting expenses as a partner in GPT.  We have the right to exit the partnership, at our discretion at any time during the permitting phase, with no further obligation, beyond any pending capital calls requested by the joint venture prior to our exit of the partnership.

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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.  We also sell any excess produced coal to brokers and third-party sources, including brokers who sell to end users in foreign countries.  For delivery during the year ended December 31, 2015, we purchased and resold 0.3 million tons through brokers and third-party sources.

Sales and Marketing

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

·                  Sales and Marketing, which focuses on traditional requests for proposals by our mine customers;

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

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

·                  Trading and Revenue Management, which provides industry insight, recommends pricing strategies and participates in the spot and forward markets; and

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

As of February 11, 2016, we had 22 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 adversely affect our profitability.”

Competition

The coal industry is highly competitive.  See Item 1A “Risk Factors—Risks Related to Our Business and Industry—Competition with domestic and foreign coal producers, with traders and re-sellers of coal and with producers of natural gas and other competing energy sources may continue to negatively affect our sales volumes and our ability to sell coal at a favorable price.”  We compete with other coal producers, with traders and re-sellers of coal and 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 and with traders and re-sellers of coal are coal price, coal quality and characteristics, costs 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 industries.  These coal consumption patterns are influenced by factors beyond our control, including weather and economic conditions,  the supply and demand for domestic and foreign electricity, domestic and foreign governmental regulations and taxes, environmental and other regulatory changes, global climate change initiatives, technological developments, the price and availability of other fuels, such as natural gas and crude oil, the availability of subsidies, and 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.

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Employees

As of February 11, 2016, we had approximately 1,500 full-time employees.  None of our employees are currently parties to collective bargaining agreements.  We believe that we have good relations with our employees.  As of February 11, 2016, we had approximately 250 external contractors on a full-time, equivalent basis.

Executive Officers

Set forth below is information concerning our current executive officers as of December 31, 2015.

Colin Marshall has served as our President, Chief Executive Officer and a director since July 2008. Previously, he served as the President and Chief Executive Officer of RTEA from June 2006 until November 2009. From March 2004 to May 2006, Mr. Marshall served as General Manager of Rio 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.  From 1996 to 2000, he was Finance Director of the Rio Tinto Pacific Coal business unit based in Brisbane Australia.  Mr. Marshall worked for Rio Tinto plc in London as an analyst in the Business Evaluation Department from 1992 to 1996.  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.

Heath Hill has served as our Executive Vice President and Chief Financial Officer since March 2015.  Prior to that appointment, he was the Vice President and Chief Accounting Officer beginning in September 2010.  Previously, Mr. Hill served in various capacities with PricewaterhouseCoopers LLP, our independent public accountants, from September 1998 to September 2010, including Senior Manager from September 2006 to September 2010, and Manager from September 2003 to September 2006. While with PricewaterhouseCoopers LLP, Mr. Hill’s responsibilities included assurance services primarily related to SEC registrants, including annual audits of financial statements and internal controls, public debt offerings and IPO transactions. From June 2003 to June 2005 he held a position with PricewaterhouseCoopers in Germany serving U.S. registrants throughout Europe. Mr. Hill never worked on any engagements or projects for CPE Inc. or its predecessor, Rio Tinto, while he was with PricewaterhouseCoopers LLP. Mr. Hill earned his Bachelor’s degree in accounting from the University of Northern Colorado and is an active certified public accountant.

Gary Rivenes has served as our Executive Vice President and Chief Operating Officer since October 2009. Previously, he served as Vice President, Operations, of RTEA from December 2008 until November 2009, and as Acting Vice President, Operations, of RTEA from January 2008 to November 2008. From September 2007 to December 2007, Mr. Rivenes served as General Manager for RTEA’s Jacobs Ranch Mine, from October 2006 to September 2007, he served as General Manager for RTEA’s Antelope Mine and from November 2003 to September 2006, he served as Manager, Mine Operations for RTEA’s Antelope Mine. Prior to that, he worked for RTEA in a variety of operational and technical positions for RTEA’s Antelope, Colowyo and Jacobs Ranch mines since 1992. Mr. Rivenes holds a Bachelor of Science in mining engineering from Montana College of Mineral, Science & Technology.

Bryan Pechersky has served as our Executive Vice President since January 2015, our General Counsel since January 2010, and our Corporate Secretary since March 2013.  Prior to his promotion to Executive Vice President, he served as Senior Vice President beginning in 2010.  Previously, Mr. Pechersky was Senior Vice President, General Counsel and Secretary for Harte-Hanks, Inc., a worldwide, direct and targeted marketing company from March 2007 to January 2010.  Prior to that, he also served as Senior Vice President, Secretary and Senior Corporate Counsel for Blockbuster Inc., a global

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movie and game entertainment retailer from October 2005 to March 2007, and was Deputy General Counsel and Secretary for Unocal Corporation, an international energy company acquired by Chevron Corporation in 2005, from March 2004 until October 2005.  While in these capacities, Mr. Pechersky’s responsibilities included advising on various legal, regulatory and compliance matters, transactions and other responsibilities that are common for a general counsel and corporate secretary.  Mr. Pechersky was in private practice for approximately seven years with the international law firm Vinson & Elkins L.L.P. before joining Unocal Corporation.  Mr. Pechersky also served as a Law Clerk to the Hon. Loretta A. Preska, Chief Judge of the U.S. District Court for the Southern District of New York in 1995 and 1996.  Mr. Pechersky earned his Bachelor’s degree and Juris Doctorate from the University of Texas, Austin, Texas.

Bruce Jones has served as our Senior Vice President, Technical Services since July 2013, with responsibilities in strategic and long-term mine planning, geological services, land management and environmental affairs.  Prior to his appointment as Senior Vice President, Mr. Jones was General Manager of our Spring Creek Mine from March 2007 to July 2013.  Before joining the Spring Creek Mine, Mr. Jones was the Operations Manager for Kennecott Utah Copper at the Bingham Canyon Mine in Bingham Canyon, Utah.  Mr. Jones began his career as a mining engineer for Inspiration Coal, Inc. in 1982 and has worked in several sectors of the mining industry.  During his career, Mr. Jones has held engineering and operations management positions at gold, copper, and coal mining operations.  Mr. Jones holds a Bachelor of Science degree in mining engineering from the University of Wisconsin-Platteville and a Master of Business Administration from the University of Utah.  Mr. Jones is a registered professional engineer in Kentucky and Utah.

Cary Martin has served as our Senior Vice President, Human Resources since October 2009. Previously, he served as Vice President / Corporate Officer of Human Resources for OGE Energy Corp., an electric utility and natural gas processing holding company from September 2006 until March 2008, and as a Segment Vice President for several different divisions of SPX Corporation, an international multi-industry manufacturing and services company from December 1999 until May 2006. In these capacities, Mr. Martin’s responsibilities included oversight of employee and labor relations, workforce planning, employee development, compensation administration, policies and procedures and other responsibilities that are common for a human resources executive. From 1982 until 1999, Mr. Martin served in various management and officer positions for industries ranging from medical facilities to cable manufacturers. Mr. Martin received his Bachelor’s degree in business administration from the University of Missouri and his Master’s degree in management sciences from St. Louis University.

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

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

Kendall Carbone has served as our Vice President and Chief Accounting Officer since March 2015.  Prior to joining Cloud Peak Energy, Ms. Carbone served as Vice President, Controller and Chief Accounting Officer for both Cool Planet Energy Systems, Inc. from 2013 to 2014 and QEP Resources, Inc. from 2010 to 2013. Ms. Carbone has extensive experience in the energy industry including bio-fuel, natural gas and oil refining as well as previous experience in mining. Ms. Carbone is a CPA and holds a Master’s Degree in accounting from New York University and a Bachelor’s degree in economics from Dartmouth College.

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Environmental and Other Regulatory Matters

Federal, state and local authorities regulate the U.S. coal mining industry with respect to various matters, including air quality standards, water pollution, plant and wildlife protection, the discharge of materials into the environment and the effects of mining on surface and groundwater quality and availability.  These laws and regulations, which are extensive, change frequently, and have tended to become stricter over time, have had, and will continue to have, a significant adverse effect on our production costs and our competitive position relative to certain other sources of electricity generation.  Future laws, regulations, orders, or treaties, including those relating to global climate change, may continue to cause coal to become a less attractive fuel source, thereby further reducing coal’s share of the market for fuels and other energy sources used to generate electricity.  See “Environmental and Other Regulatory Matters—Global Climate Change.”

We are committed to conducting our mining operations in compliance with all applicable federal, state and local laws and regulations.  We have procedures in place that are designed to enable us to comply with these laws and regulations.  As an example, all of the mines we operate are certified to the international standard for environmental management systems (“ISO 14001”).  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 guarantee that we have been or will be at all times in complete compliance.

Mining Permits and Approvals

Numerous governmental permits or approvals are required for mining operations.  When we apply for these permits and approvals, we may be required to prepare and present data to federal, state or local authorities pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment.  For example, in order to obtain a federal coal lease, an EIS must be prepared to assist the BLM in determining the potential environmental impact of lease issuance, including any direct and indirect effects from the mining, transportation and burning of coal.  In recent years, particular attention has been focused on the impact of the production and usage of coal on global climate change.  This has resulted in extensive comments and regulatory litigation from environmental groups, including, for example, unsuccessful challenges related to the EIS prepared in connection with the West Antelope II LBA.  See also Note 20 of Notes to Consolidated Financial Statements in Item 8 for a discussion regarding challenges by environmental activist groups against various regulatory processes impacting our mines.  Draft guidance released by the Council on Environmental Quality (“CEQ”) regarding climate change considerations in the NEPA analyses may increase the likelihood of future challenges to the NEPA documents prepared for actions requiring federal approval.  Accordingly, our nominations or lease applications may be subject to delays or challenges.  In order to obtain mining permits and approvals from federal and state regulatory authorities, mine operators must also 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.  In the states where we operate, the applicable laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if officers, directors, stockholders with specified interests or certain other affiliated entities with specified interests in the applicant or permittee have, or are affiliated with another entity that has, outstanding permit violations.  Thus, past or ongoing violations of applicable laws and regulations by these interested persons and entities could provide a basis to revoke our existing permits and to deny the issuance of additional permits.  As a result of these requirements, 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.  Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under governing laws, rules, and regulations.  Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.

Permitting requirements also require, under certain circumstances, that we 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 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.

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 federal Office of Surface Mining (“OSM”) or from the applicable state agency if the state agency has obtained regulatory primacy by developing a mining

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regulatory program no less stringent than that established 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: 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, which address the provisions and performance standards of the state’s equivalent SMCRA regulatory program.  SMCRA permit applications also include information used for documenting surface and mineral ownership, variance requests, access roads, mining methods, mining phases, other agreements that may relate to coal, other minerals, oil and gas rights, water rights, permitted areas and ownership and control information required to determine compliance with OSM’s regulations, including information regarding mining and compliance history.  A mine operator must also submit a bond or otherwise secure the performance of all reclamation obligations associated with the proposed activities.

Upon submission to the regulatory agency, a permit application goes through an administrative completeness review and a thorough technical review.  Public notice of the proposed permit is required, beginning a notice and comment period that is required 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 or more years for the permit to be issued, depending primarily on the regulatory authority’s approach to handling comments and objections 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.

From time to time, OSM will also update its mining regulations under SMCRA. For example, the OSM published a proposed rule on July 27, 2015 to revise its regulations related to protecting streams and related wildlife from adverse impacts of surface coal mining operations. This proposed rule, or other new SMCRA regulations,  could result in additional material costs, obligations and restrictions associated with our operations.

In addition to the bond requirement described above, 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 $0.28 per ton of coal produced from surface mines.  In 2015, we recorded $20.9 million of expense related to these reclamation fees.

Surety Bonds

Federal and state laws require a mine operator to secure the performance of its reclamation and lease obligations required under SMCRA through the use of surety bonds or other approved forms of security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations.  As of December 31, 2015, there were approximately $433.9 million in third-party surety bonds outstanding to primarily secure the performance of our reclamation and lease obligations, and we were self-bonded for $200 million.  At some point, federal and state laws may be amended to require certain forms of financial assurance that are more costly to obtain, such as letters of credit.  Recently, there has been heightened regulatory pressure on reclamation bonding and self-bonding in particular.  In January 2016, the federal Office of Surface Mining Reclamation and Enforcement (“OSMRE”) sent Ten-Day Notices to the Wyoming Department of Environmental Quality regarding self-bonding of certain other coal companies who have filed for bankruptcy.  In its notices, OSMRE asserted that a violation of the Wyoming approved state program may exist by allowing the specified companies to continue mining without sufficient reclamation bonding in place.  In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand cash collateral as a condition to providing or maintaining surety bonds.  Any such demands, depending on the amount of any cash collateral required, could have a material adverse impact on our liquidity and financial position.  If we are unable to meet cash collateral requirements and cannot otherwise obtain or retain required surety bonds, we may be unable to satisfy legal requirements necessary to conduct our mining operations.

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Mine Safety and Health

Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969.  The Federal Mine Safety and Health Act of 1977 (the “Mine Act”), significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations.  In addition to federal regulatory programs, all of the states in which we operate also have state programs for mine safety and health regulation and enforcement.  Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive and pervasive systems for protection of employee health and safety affecting any segment of U.S. industry.  The Mine Act is a strict liability statute that requires mandatory inspections of surface and underground coal mines and requires the issuance of enforcement action when it is believed that a standard has been violated.  A penalty is required to be imposed for each cited violation.  Negligence and gravity assessments result in a cumulative enforcement arrangement that may result in the issuance of withdrawal orders.  The Mine Act also contains criminal liability provisions.  For example, it imposes criminal liability for corporate operators who knowingly or willfully authorize, order or carry out violations and for any person who knowingly falsifies records required under the Mine Act.  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 2006, in response to underground mine accidents, Congress enacted the Mine Improvement and New Emergency Response Act (the “MINER Act”). The MINER Act significantly amended the Mine Act, requiring improvements in mine safety practices, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection and enforcement activities.   Since passage of the MINER Act, and particularly since the April 2010 explosion at Massey Energy Company’s (now Alpha Natural Resources) Upper Big Branch Mine, enforcement scrutiny has increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions and related penalties. Various states also have enacted their own new laws and regulations addressing many of these same subjects. MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards.  Our compliance with these or any new mine health and safety regulations could increase our mining costs.

We have implemented various internal standards to promote employee health and safety.  In addition, we are also Occupational Health and Safety Assessment Series 18001 certified.  According to MSHA data, we have one of the lowest employee all injury incident rates among the largest U.S. coal producing companies.  Nevertheless, if we were to be found in violation of mine safety and health regulations, we could face penalties or restrictions that may materially and adversely impact our operations, financial results and liquidity.

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 2015, we recorded $36.3 million of expense related to this excise tax.

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 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 CAA 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 CAA permitting requirements and emission control requirements relating to air pollutants, including particulate matter, which may include controlling fugitive dust.  The CAA indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide,

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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 materially and adversely affect our operations, financial results, liquidity, and demand for our coal, directly or indirectly, include, but are not limited to, the following:

·                  Acid Rain.  Title IV of the CAA 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, which is scheduled to require implementation beginning in 2015.

·                  NAAQS for Criterion Pollutants.  The CAA requires the EPA to set standards, referred to as NAAQS, for six common air pollutants, including nitrogen oxide, sulfur dioxide, particulate matter, and ozone.  Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels.  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.  Over the past several years, the EPA has revised its NAAQS for nitrogen oxide, sulfur dioxide, and particulate matter, and, in November 2014, proposed a revised standard for ozone, in each case making the standards more stringent.  The EPA has determined that the areas in which we operate are classified under the new nitrogen oxide standard as “unclassifiable/attainment”.  However, the EPA and the state environmental authorities in the areas where we operate have not yet finalized new requirements under the revised sulfur dioxide NAAQS.  In November 2015, the EPA also revised the NAAQS for ground level ozone to a stricter, lower standard of 70 parts per billion.  The EPA has not yet designated which areas of the country are out of attainment with the new ground level ozone standard, and it will take the states several years to develop compliance plans for their non-attainment areas.  Certain areas of the country previously in compliance with the various NAAQS standards may be reclassified as non-attainment.  Such reclassification may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas.

·                  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 U.S.to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states.  Nitrogen oxide and sulfur dioxide emissions reductions were scheduled to commence in 2012, with further reductions effective in 2014.  However, in August 2012, the U.S. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) vacated CSAPR and ordered the EPA to continue enforcing CAIR.  In April 2014, the U.S. Supreme Court reversed the D.C. Circuit’s decision vacating CSAPR.  The EPA subsequently moved the Appeals Court for an order lifting the stay of CSAPR and extending the CSAPR compliance deadlines.  In October 2014, the Court granted the EPA’s request to lift the stay, and in November 2014, the EPA issued an interim final rule reconciling the CSAPR rule with the Court’s order, which calls for Phase 1 implementation in 2015 and Phase 2 implementation in 2017.  For states to meet their requirements under CSAPR, a number of coal-fired electric generating units will likely need to be retired, rather than retrofitted with the necessary emission control technologies, reducing demand for thermal coal.

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

·                  Mercury and Hazardous Air Pollutants.  In February 2012, the EPA formally adopted a rule to regulate emissions of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal- and oil-fired power plants, referred to as “MATS”.  In March 2013, the EPA finalized reconsideration of the MATS rule as it pertains to new power plants, principally adjusting emissions limits for new coal-fired units to levels considered attainable by existing control technologies.  In subsequent litigation, the U.S. Court of Appeals for the D.C. Circuit upheld various portions of the rulemaking in two separate decisions issued in March and April 2014, respectively.  In June 2015, the U.S. Supreme Court struck down the MATS rule based on the EPA’s failure to take costs into consideration and

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remanded the case back to the D.C. Circuit.  The D.C. Circuit has remanded the rule to the EPA, but allowed the current rule to stay in place until the EPA issues a new finding.  Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed.  Regulation of mercury emissions by the EPA, states, Congress, or pursuant to an international treaty may further decrease the demand for coal.  Like CSAPR, MATS and other similar future regulations could accelerate the retirement of a significant number of coal-fired power plants, in addition to the significant number of plants and units that have already been retired as a result of environmental and regulatory requirements and uncertainties adversely impact coal-fired generation.  Such retirements would likely adversely impact our business.

·                  Regional Haze, New Source Review and Methane.  The EPA has initiated a regional haze program to protect and improve visibility at and around national parks, national wilderness areas and international parks.  In December  2011, the EPA issued a final rule under which the emission caps imposed under CSAPR for a given state would supplant the obligations of that state with regard to visibility protection.  In May  2012, the EPA finalized a rule that allows the trading programs in CSAPR to serve as an alternative to determining source-by-source Best Available Retrofit Technology (“BART”). This rule provides that states in the CSAPR region can substitute participation in CSAPR for source-specific BART for sulfur dioxide and/or nitrogen oxides emissions from power plants.  The Tenth Circuit Court of Appeals is hearing Wyoming’s challenge to the EPA’s partial disapproval of the State’s related plan for reducing emissions of haze-causing nitrogen dioxide.  Wyoming’s current plan to mitigate nitrogen dioxide will continue during the appeal. In September 2014, the Court stayed the EPA’s rejection of Wyoming’s plan and the litigation is still ongoing.  An adverse outcome in this case could result in additional regulatory requirements and compliance costs for our operations.

·                  In addition, the EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringent air emissions control equipment required of new plants.  Litigation seeking to force the EPA to list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the CAA and establish standards to reduce emissions from sources of methane and other emissions related to coal mines was dismissed by the D.C. Circuit in May 2014.  In that case, the Court denied a rulemaking petition citing agency discretion and budgetary restrictions, and ruled the EPA has reasonable discretion to carry out its delegated responsibilities, which includes determining the timing and relative priority of its regulatory agenda.  In July 2014, the D.C. Circuit denied a petition seeking a rehearing of the case en banc.  Litigation around these issues may continue, and could result in the need for additional air pollution controls for coal fired units and our operations.

Global Climate Change

Global climate change initiatives and public perceptions have resulted, and are expected to continue to result, in decreased coal-fired power plant capacity and utilization, phasing out and closing many existing coal-fired power plants, reducing or eliminating construction of new coal-fired power plants in the United States and certain other countries, increased costs to mine coal and decreased demand and prices for thermal coal, including PRB coal.

There are three important sources of GHGs associated with the coal industry.  The end use of our coal in electricity generation is the largest of the three sources 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 subject to pending and proposed regulation as part of initiatives to address global climate change.

The Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (the “Kyoto Protocol”) became effective in 2005, and bound those developed countries that ratified it (which the U.S. did not do) to reduce their global GHG emissions.  Discussions to develop a treaty to replace the Kyoto Protocol after its expiration in 2012 are still ongoing.  Most recently, the United Nations Framework Convention on Climate Change met in Paris, France in December 2015 and agreed to an international climate agreement.  Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions.  These commitments could further reduce demand and prices for our coal.

The EPA has adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including coal-fired electric power plants, and begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA.  These rules were legally challenged, but in June 2012, the D.C. Circuit denied these challenges.  Among the rules promulgated after the EPA’s endangerment finding was the Tailoring Rule, which

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requires that all new or modified stationary sources of GHGs that will emit more than 75,000 tons of carbon dioxide per year and are otherwise subject to CAA regulation, and any other facilities that will emit more than 100,000 tons of carbon dioxide per year, to undergo prevention of significant deterioration (“PSD”) permitting, which requires that the permitted entity adopt the best available control technology.   As a result, the EPA is now requiring new sources, including coal-fired power plants, to undergo control technology reviews for GHGs (predominately carbon dioxide) as a condition of permit issuance.  These reviews may impose limits on GHG emissions, or otherwise be used to compel consideration of alternative fuels and generation systems, as well as increase litigation risk for—and so discourage development of—coal-fired power plants.

Additionally, the U.S. Supreme Court, in a decision issued in June 2014, addressed whether the EPA’s regulation of GHG emissions from new motor vehicles properly triggered GHG permitting requirements for stationary sources under the CAA.  The decision reversed, in part, and affirmed, in part, a 2012 D.C. Circuit decision that upheld the EPA’s GHG-related regulations.  Specifically, the Court held that the EPA exceeded its statutory authority when it interpreted the CAA to require PSD and Title V permitting for stationary sources based on their potential GHG emissions. However, the Court also held that the EPA’s determination that a source already subject to the PSD program due to its emission of conventional pollutants may be required to limit its GHG emissions by employing the “best available control technology” was permissible.

In August 2015, the EPA issued its final Clean Power Plan (“CPP”) rules that establish carbon pollution standards for power plants, called CO2 emission performance rates.  The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the CPP.  The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour) or mass-based tonnage limits for CO2.  The state plans are due in September 2016, subject to potential extensions of up to two years for final plan submission. The compliance period begins in 2022, and emission reductions will be phased in up to 2030.  The EPA also proposed a federal compliance plan to implement the CPP in the event that an approvable state plan is not submitted to the EPA.  Judicial challenges have been filed.  On February 9, 2016, the U.S. Supreme Court granted a stay of the implementation of the CPP before the United States Court of Appeals for the District of Columbia (“Circuit Court”) even issued a decision.  By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted.   The stay suspends the rule, including the requirement that states submit their initial plans by September 2016.  The Supreme Court’s stay applies only to EPA’s regulations for CO2 emissions from existing power plants and will not affect EPA’s standards for new power plants.  It is not yet clear how either the Circuit Court or the Supreme Court will rule on the legality of the CPP.  If the rules were upheld at the conclusion of this appellate process and were implemented in their current form, demand for coal will likely be further decreased, potentially significantly, and adversely impact our business.

Various states and regions have adopted GHG initiatives and certain governmental bodies, including the State of California, have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities.  A number of states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power.

These and other current or future global climate change laws, regulations, court orders or other legally enforceable mechanisms, or related public perceptions regarding climate change, are expected to require additional controls on coal-fired power plants and industrial boilers and may cause some users of coal to further switch from coal to alternative sources of fuel, thereby depressing demand and pricing for coal.

Clean Water Act

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

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

·                  Wastewater Discharge.  Section 402 of the CWA creates a process for establishing effluent limitations for discharges to streams that are protective of water quality standards through the National Pollutant Discharge Elimination System (“NPDES”), and corresponding programs implemented by state regulatory agencies.  Regular monitoring, reporting and compliance with performance standards are preconditions for the issuance and renewal of NPDES permits that govern discharges into waters of the U.S.  Failure to comply with the CWA or NPDES permits

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can lead to the imposition of significant penalties, litigation, compliance costs and delays in coal production. Furthermore, the imposition of future restrictions on the discharge of certain pollutants into waters of the U.S. could increase the difficulty of obtaining and complying with NPDES permits, which could impose additional time and cost burdens on our operations.  For instance, waters that states have designated as impaired (i.e., as not meeting present water quality standards) are subject to Total Maximum Daily Load regulations, which may lead to the adoption of more stringent discharge standards for our coal mines and could require more costly treatment.

Likewise, when water quality in a receiving stream is better than required, states are required to conduct an anti-degradation review before approving discharge permits. Anti-degradation policies may increase the cost, time and difficulty associated with obtaining and complying with NPDES permits and may also require more costly treatment.

·                  Dredge and Fill Permits.  Many mining activities, including the development of settling ponds and other impoundments, require a Section 404 permit from the Army Corps of Engineers (the “Corps”).  Generally speaking, these Section 404 permits allow the placement of fill materials into navigable waters of the U.S. including wetlands, streams, and other regulated areas.  The Corps has issued general “nationwide” permits for specific categories of activities that are similar in nature and that are determined to have minimal adverse effects on the environment. Permits issued pursuant to Nationwide Permit 21 (“NWP 21”) generally authorize the disposal of dredged or fill material from surface coal mining activities into waters of the U.S., subject to certain restrictions.  NWP 21s are typically reissued for a five-year period and require appropriate mitigation, and permit holders must receive explicit authorization from the Corps before proceeding with proposed mining activities.  The Corps reauthorized use of NWP 21 for surface coal mines in February 2012.  The new NWP 21 imposes new limits on stream impacts and prohibits valley fills as well as limits applicability of NWP 21 to very small wetland areas.  Expansion of our mining operations into new areas may trigger the need for individual Corps approvals which could be more costly and take more time to obtain.

Because of the U.S. Supreme Court’s divided decision in Rapanos v. United States, there is some regulatory uncertainty about what constitutes jurisdictional waters and wetlands.  Consequently, in April 2014, the EPA and the Corps released a proposed rule to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs.  The EPA subsequently released the WOTUS rule, which went into effect in August 2015. The U.S. Court of Appeals for the Sixth Circuit has stayed the WOTUS rule nationwide pending further action of the court. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” Those regulations will be implemented as they were prior to the effective date of the new WOTUS rule.  The WOTUS rule could significantly expand federal control of land and water resources across the U.S., triggering substantial additional permitting and regulatory requirements.

In March 2010, the Corps made a determination that there are no jurisdictional wetlands at our Spring Creek Mine.  Similarly, in September 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.  In September 2014, the Corps authorized proposed operations under NWP 21 for our Cordero Rojo Mine.  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.

·                  Cooling Water Intake.  In May 2014, the EPA issued a new final rule pursuant to Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment.  The rule is expected to affect over 500 power plants.  These requirements could increase our customers’ costs and may adversely affect the demand for coal, which may materially impact our results or operations.

Resource Conservation and Recovery Act

The EPA determined that coal combustion 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 do not regulate CCR as hazardous wastes.  The EPA also concluded that beneficial uses of 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 minefill.  In December 2014, the EPA finalized regulations that address the management of coal ash as a non-hazardous solid waste under Subtitle D.  The rules impose engineering, structural and siting standards on surface impoundments and landfills that hold coal combustion wastes and mandate regular inspections.  The rule also requires fugitive dust controls and imposes various monitoring, cleanup, and

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closure requirements.  There have also been several legislative proposals that would require the EPA to further regulate the storage of CCR.  These requirements, as well as any future changes in the management of CCR, could increase our customers’ operating costs and potentially reduce their ability or need 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 further 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.  These liabilities could be significant and materially and adversely impact our financial results and liquidity.

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.  Other species in the vicinity of our operations, such as the mountain plover, which the USFWS determined not to list as threatened in May 2011, may have their listing status reviewed in the future.

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 Mine applied for lease modification under the BLM leasing regulations and a mine permit amendment to add lands to the permit area.  Portions of these lands have been designated as core habitat for the greater sage grouse by the Montana Fish, Wildlife and Parks Department. While the USFWS has determined that the greater sage grouse should not be listed as a threatened or endangered species, the BLM has developed Conservation Plans designed to preserve and protect greater sage-grouse habitat.  Montana has also developed sage grouse conservation plans through Governor’s executive order.  Our approvals to mine or otherwise affect these areas will be subject to review by the BLM and the Montana Department of Environmental Quality and determinations of our ability to adequately mitigate impacts to sage grouse and sage grouse habitat. The plans do however, recognize the right to mine where there are valid existing rights. The BLM has stated that ensuring that sagebrush habitat will be an important consideration in the BLM review of proposed coal mines or coal mine expansions. The plans also recommend that the Secretary of the Interior withdraw 10 million acres from hardrock mining for up to 20 years. The BLM is beginning that separate, public withdrawal process by putting in place a temporary, two-year prohibition for new hardrock mining location and entry in certain areas. Our mines are not located within the areas that the BLM has designated for withdrawing from hardrock mining.

These and any similar future actions could result in more stringent requirements being issued by the BLM and other agencies involved in the leasing and permitting process.  The USFWS must review its 2015 decision to not list the sage grouse again in five years.  Should more stringent protective measures be applied or if the greater sage-grouse is listed as a threatened species by the USFWS, this could significantly impair our ability to conduct our mining operations or result in increased operating costs, heightened difficulty in obtaining future mining permits, or the need to implement additional mitigation measures.

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

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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.  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 has yet to be issued.  In December 2014, the OSM announced its decision to pursue a rulemaking to revise regulations under SMCRA which will address all blast generated fumes and toxic gases.  OSM has not yet issued a proposed rule to address these blasts.  The outcome of these rulemakings could materially adversely impact our cost or ability to conduct our mining operations.

National Environmental Policy Act

NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment, such as issuing a permit or other approval. In the course of such evaluations, an agency will typically prepare an environmental assessment to assess the potential direct, indirect and cumulative impacts of a proposed project. Where the activities in question have significant impacts to the environment, the agency must prepare an EIS. Compliance with NEPA can be time-consuming and may result in the imposition of mitigation measures that could affect the amount of coal that we are able to produce from mines on federal lands, and may require public comment. Whether agencies have complied with NEPA is subject to protest, appeal or litigation, which can delay or halt projects. The NEPA review process, including potential disputes regarding the level of evaluation required for climate change impacts, may extend the time and/or increase the costs and difficulty for obtaining necessary governmental approvals, and may lead to litigation regarding the adequacy of the NEPA analysis, which could delay or potentially preclude the issuance of approvals or grant of leases.

In December 2014 the CEQ released updated draft guidance discussing how federal agencies should consider the effects of GHG emissions and climate change in their NEPA evaluations. The guidance encourages agencies to provide more detailed discussion of the direct, indirect, and cumulative impacts of a proposed action’s reasonably foreseeable emissions and effects. This guidance could create additional delays and costs in the NEPA review process or in our operations, or even an inability to obtain necessary federal approvals for our operations, including due to the increased risk of legal challenges from environmental groups seeking additional analysis of climate impacts.

DOI Moratorium and Programmatic EIS

On January 15, 2016, the Secretary of the Department of the Interior (“DOI”) announced a moratorium on the issuance of new leases for coal resources on federally-owned lands in order to allow for a “comprehensive review” of the federal coal programs.  The terms of this moratorium preclude the BLM from accepting new applications for thermal coal sales, or modifying existing leases subject to certain exceptions.  The Secretary did not set a deadline for completing this analysis but estimated that it may take three years to finalize.  The moratorium does not preclude a company holding a lease from developing coal resources and thus should not interfere with our on-going operations.  We are having discussions with the BLM as to whether certain pending applications to modify existing coal leases by adding additional resources fall within the exceptions set out by BLM.

It remains to be seen what the ultimate outcome of this comprehensive review of the federal program will mean for the future of developing coal on federal lands.  Part of the analysis that DOI will undertake involves determining whether the “federal coal program conflicts with the Administration’s climate policy” and whether the system provides a “way to systematically consider the climate impacts and costs to taxpayers of Federal coal development.”  This analysis will include a “Programmatic EIS” under NEPA.  Depending on the outcome of this comprehensive review including the Programmatic EIS, either we may not be able obtain leases for developing coal resources on federal lands, or the terms of any such leases that we may be able to obtain may not be economically viable.  Our business of leasing coal on federal lands may not remain economically viable at the conclusion of this “comprehensive review.”

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 appropriate transportation of our coal both nationally and internationally.  Laws, regulations, 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.

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Available Information

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

We also make the documents listed above available without charge through our website, www.cloudpeakenergy.com, as soon as practicable after we file or furnish them with the SEC.  You may also request copies of the documents, at no cost, by telephone at (720) 566-2900 or by mail at Cloud Peak Energy Inc., 385 Interlocken Crescent, Suite 400, Broomfield, Colorado, 80021, Attention:  Vice President, Investor Relations.  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.

Item 1A.  Risk Factors.

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

Risks Related to Our Business and Industry

Numerous political and regulatory authorities, along with well-funded environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal, including PRB coal, and potentially materially and adversely impacting our future financial results, liquidity and growth prospects.

Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion in many jurisdictions, unfavorable lending policies by government-backed lending institutions and development banks toward the financing of new overseas coal-fueled power plants and divestment efforts affecting the investment community, which could significantly affect demand for our products or our securities. Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth and Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions of carbon dioxide from coal combustion by power plants. The 2015 Paris climate summit agreement resulted in voluntary commitments by numerous countries to reduce their GHG emissions, and could result in additional firm commitments by various nations with respect to future GHG emissions.  These commitments could further disfavor coal-fired generation, particularly in the medium- to long-term.

Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the United States, some of its states or other countries, or other actions to limit such emissions, could also result in electricity generators further switching from coal to other fuel sources or additional coal-fueled power plant closures.  Further, policies limiting available financing for the development of new coal-fueled power plants could adversely impact the global demand for coal in the future.

There have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves.  In California, for example, legislation was signed into law in October 2015 that requires California’s state pension funds to divest investments in companies that generate 50% or more of their revenue from coal mining by July 2017.  Other activist campaigns have urged banks to cease financing coal-driven businesses.  As a result, at least ten major banks have enacted such policies in 2015.  The impact of such efforts may adversely affect the demand for and price of securities issued by us, and impact our access to the capital and financial markets.

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Additional regulatory developments are slated to take place over the next few years that appear oriented at increasing the regulatory burden associated with mining coal and coal-fired generation.  Regulatory initiatives that have been proposed, adopted, or enacted in the United States include: the MATS rule, the national emission standards for hazardous air pollutants boiler rules, the new source performance standards for fossil-fuel fired power plants, revisions to the nitrogen oxide and sulfur dioxide NAAQS, the CAIR rule, the Clean Power Plan, the regional haze program, regulation of CCR, revisions to the Corps’ Section 404 permitting regime, and OSM’s stream protection rule. See Item 1 “Business—Environmental and Other Regulatory Matters.”   These and other governmental actions that directly or indirectly affect the coal mining industry and coal-fired power generation have made, and will continue to make, it more difficult and costly to mine and ship coal, and operate coal-fired assets.  Meanwhile, substantial government subsidies are available to fund various aspects of renewable power generation and supply, which may hurt our ability to compete against these alternative forms of electric generation.

In addition, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation.  For example, the goals of Sierra Club’s “Beyond Coal” campaign include retiring one-third of the nation’s coal-fired power plants by 2020, replacing retired coal plants with “clean energy solutions,” and “[k]eeping coal in the ground.”  It has been reported that the Beyond Coal campaign has been funded by several high-profile, high-net-worth individuals and organizations, including approximately $80 million from Michael Bloomberg and his philanthropic foundation, Bloomberg Philanthropies.  In an effort to stop or delay coal mining activities, the Sierra Club and other activist groups have brought, and continue to bring, numerous lawsuits, including against the BLM to challenge not only the issuance of individual coal leases, but also the federal coal leasing program more broadly.  Other lawsuits continue to be brought challenging historical and pending regulatory approvals, permits and processes that are necessary to conduct coal mining operations or to operate coal-fueled power plants, including so-called “sue and settle” lawsuits where regulatory authorities reach private agreements with environmental activists that often involve additional regulatory restrictions or processes being implemented without formal rulemaking.  The recent announcement on January 15, 2016 by the Secretary of the DOI of a moratorium on the issuance of new leases by the BLM for developing coal resources on federally-owned lands appears to be another regulatory initiative of the current administration that is oriented at reducing the availability of coal for power production domestically and internationally.

The net effect of these developments is to make it more costly and difficult to maintain our business and to continue to depress the market for our coal.  A substantial or extended decline in the prices we receive for our coal due to these or other factors could further reduce our revenue and profitability, cash flows, liquidity, and value of our coal reserves and result in losses.

Coal prices are subject to change based on a number of factors and coal prices are currently depressed.  If coal prices remain depressed, or if there is a substantial or extended decline in prices, it could materially reduce our revenue and profitability, cash flows, liquidity, and value of our coal reserves and result in losses.

Our revenue, results of operations, and the value of our coal reserves depend on the prices we receive for our coal and logistics services.  Over the last several years, prices for coal have become more volatile and depressed due to an oversupply of coal in the marketplace and, particularly in the United States, significantly reduced demand in various countries.  The prices we receive for our coal and logistics services depend upon factors beyond our control, including:

·                  domestic and foreign supply and demand for coal, including Asian and other foreign demand for PRB coal exports, and the impact of domestic and foreign government environmental, energy and tax policies and currency exchange rate fluctuations;

·                  domestic and foreign demand for electricity and steel;

·                  domestic and foreign economic conditions;

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

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

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

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

·                  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;

·                  changes in coal-fired power plant capacity and utilization, including the extent to which new coal plants are built in the United States and other countries;

·                  market price fluctuations for sulfur dioxide emission allowances;

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

·                  the other risks described in this Item 1A.

If coal prices remain depressed, or if there is a substantial or extended decline in the prices we receive for our coal and logistics services due to these or other factors, it could materially reduce our revenue and profitability, cash flows, liquidity, and value of our coal reserves and result in losses.

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

The coal industry is highly competitive.  We compete with other domestic and many foreign coal producers, with traders and re-sellers of coal and 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 or supplies of coal;

·                  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 has fluctuated over the last decade because of these and other factors and, in recent years, has declined substantially due to global climate change initiatives and other regulatory initiatives that favor natural gas or non-fossil fuel sources of electricity generation, sustained low natural gas prices in the United States, weak global economic conditions and other factors, including those described in this Item 1A.  A decline in domestic demand for coal, or a decline in foreign demand for U.S. coal, has caused, and could continue to cause, additional significant competition among coal producers and 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.

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In addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas.  A decline in the price of natural gas has made natural gas more competitive against coal and resulted in utilities switching from coal to natural gas.  Sustained low natural gas prices may also cause utilities to continue to phase out or close existing coal-fired power plants or reduce or eliminate 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 grow our longer term logistics revenue and export sales at favorable prices, we may incur losses in our logistics business and be subject to significant take-or-pay obligations.

Although we currently do not expect to make export sales in 2016 as a result of ongoing depressed international prices, over the longer term we are seeking to make additional export sales to Asia and potentially other international locations.  Our ability to grow our export sales revenue and logistics margins depends on a number of factors, including the price we receive for our coal and our logistics services, 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.

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 factors, 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, which is volatile and is heavily influenced by Chinese and Indian thermal coal import demand.  For example, on December 31, 2014, spot Newcastle prices were $63.53 per tonne.  As of December 31, 2015, spot Newcastle prices decreased significantly to $51.96 per tonne.  Fluctuations in this index may be affected by a wide range of international supply and demand factors, including those listed above.  Our export sales may also be negatively impacted by currency exchange rate fluctuations that make coal from other countries more economical than PRB coal and provide competitive advantages to non-U.S. producers when the U.S. dollar is strong in comparison to those foreign currencies.  For example, the Newcastle benchmark price index is denominated in U.S. dollars.  Since 2014, the conversion rate of U.S. dollars to Australian dollars increased from 1.12 at January 1, 2014 to 1.37 as of December 31, 2015.  If demand for exports remains low or declines or we are unable to secure a favorable price for the export of our coal and logistics services, our cash flows, profitability, liquidity, and results of operations may be materially adversely affected.

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 GPT and MBT in which we have options 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 future export transactions will be materially adversely affected.

In addition, we have significant long-term 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 or the prices we receive for our coal or logistics services.  If we fail to make 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.  As of December 31, 2015, we had take-or-pay obligations of $549.0 million that could be potentially payable through 2024 if we fail to meet our minimum shipment obligations.

The regulatory environment may also adversely impact our logistics business and future export sales.  For example, the ONRR has proposed changes to how coal royalties are calculated for sales to affiliated entities, which could adversely impact export sales for vertically integrated mining and logistics entities, such as our logistics business, and place vertically integrated entities at a competitive disadvantage to independent coal brokers.  Moreover, the ONRR proposal includes a so-called “default provision”, which creates further uncertainty as to how the ONRR would apply its proposed royalty rules to

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our export sales.  The potential regulatory cost increases from this ONRR proposal, combined with already depressed international prices, influenced our decision not to make 2016 export sales.

Our long-term growth may be materially adversely impacted if economic, commercially available carbon capture technology for power plants is not developed and adopted in a timely manner.

Federal or state laws or regulations may be adopted that would impose new or additional limits on the emissions of GHGs, including, but not limited to, CO2 from electric generating units using fossil fuels such as coal or natural gas.  In order to comply with such regulations, electric generating units using fossil fuels may be required to implement carbon capture technology.  For example, in October 2015, the EPA released a rule that establishes, for the first time, new source performance standards under the federal Clean Air Act for CO2 emissions from new fossil fuel-fired electric utility generating power plants.  The EPA has designated partial carbon capture and sequestration as the best system of emission reduction for newly constructed fossil fuel-fired steam generating units at power plants to employ to meet the standard.  However, there is currently no large-scale use of carbon capture technologies in domestic coal-fired power plants, and as a result, there is a risk that such technology, which may include storage, conversion, or other commercial use for captured carbon, may not be commercially practical in limiting emissions as otherwise required by the proposed rule or similar rules that may be proposed in the future.  If such legislative or regulatory programs are adopted, and economic, commercially available carbon capture technology for power plants is not developed or adopted in a timely manner, it would negatively affect our customers and would further reduce the demand for coal as a fuel source, causing coal prices and sales of our coal to decline, perhaps materially.

As a result of ongoing depressed industry conditions and recent coal producer bankruptcy filings, the coal industry has experienced increasing credit pressures that could result in demands for credit support by third parties or decisions by banks, surety bond providers, investors or other companies to reduce or eliminate their exposure to the coal industry, including our company.  These credit pressures could materially and adversely impact our liquidity and ability to meet our regulatory requirements.

Ongoing depressed industry conditions and recent coal producer bankruptcy filings have resulted in increased credit pressures on the coal industry.  These credit pressures include, for example, (a) vendors, suppliers, customers and other commercial counterparties seeking prepayments, security deposits, letters of credit and other credit protections, and (b) banks, surety bond providers, investors and other companies reducing or eliminating their exposure to the coal industry.  Although some of these credit pressures may be company-specific, many are directed to the coal industry in general due to the current overall negative investor sentiment toward the industry.  Any credit demands by third parties or refusals by banks, surety bond providers, investors or others to extend, renew or refinance credit on commercially reasonable terms may adversely impact our business, financial condition, results of operations, cash flows and liquidity.  In some cases, such as any collateral requirements imposed by surety bond providers to issue surety bonds that secure our future performance under various federal and state laws, our ability to meet regulatory requirements may also be adversely impacted if we are not able to satisfy cash or other collateral requirements. As of December 31, 2015, there were approximately $433.9 million in third-party surety bonds outstanding to primarily secure the performance of our reclamation and lease obligations, and we were self-bonded for $200 million.

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 various European and Asian economies, and global financial and credit market disruptions had a negative impact on us and the coal industry generally.  For example, the economic downturn in recent years has negatively impacted electricity demand and led to an oversupply of coal in the marketplace and depressed prices.

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

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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 further negatively impact the demand for U.S. coal and result in a continuing oversupply of coal in the marketplace.  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 further 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;

·                  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.

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

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

Our ability to sell coal to our customers depends primarily upon third-party rail systems and export terminals.  If our customers are unable to obtain transportation services, or to do so on a cost-effective basis, our business and growth strategy

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could be adversely affected.  Alternative transportation and delivery systems are generally inadequate and not suitable to handle the quantity of our shipments or to ensure timely delivery to our customers.  Export terminals, including the proposed GPT and MBT in which we have options for potential future capacity, are also subject to permit requirements and challenges from environmental organizations which may make it complicated or expensive to expand existing terminal capacity or open new export terminals in a timely and cost-effective manner.  In addition, much of the PRB is served by two rail carriers, and the Northern PRB is only serviced by one rail carrier.  The loss of sufficient and reliable access to rail capacity in the PRB, as we have experienced in recent years, could create disruption until this access was restored; significantly impairing our ability to supply coal and resulting in materially decreased revenue.  Similarly, being denied access to an export terminal could significantly affect our future export sales, materially decreasing our logistics revenue and growth opportunities.  Our ability to open new mines or expand existing mines may also be affected by the access to, and availability and cost of rail, export terminal or other transportation systems available for servicing these mines.

Typically, our mine customers contract and pay directly for transportation of coal from the mine or port to the point of use.  However, for contracts with our logistics customers, we are required to enter into transportation agreements pursuant to which we arrange and pay for all rail transport, terminal, and for our international customers, demurrage charges.  As the volume of deliveries coordinated to customer contracted destinations increases, so do our costs and risks.  Our ability to supply coal to our customers and our customers’ ability to take our coal may be impacted by the disruption of these transportation services because of weather-related problems; mechanical difficulties; maintenance shut-downs; environmental, political and regulatory issues; train derailment; bridge or structural concerns; infrastructure damage, whether caused by ground instability, accidents or otherwise; strikes; lock-outs; lack of fuel or maintenance items; fuel costs; accidents; terrorism or domestic catastrophe or other events.  For example, in the spring and summer of 2011, the Midwest region experienced severe flooding which disrupted rail service to mines in the PRB and affected the ability of those customers who were impacted by the flooding to take coal deliveries.  During 2014, we also experienced rail interruptions due to increased competition for rail crews from crude oil and grain shipments, which negatively impacted our shipments and financial results.  Any similar disruption in the future could negatively impact our results of operations.  In addition, some scientists have opined that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur in areas where we or our clients operate, they could have an adverse effect on our assets and operations.

If we are unable to acquire or develop additional coal reserves that are economically recoverable, our future 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;

·                  delays or changes in the federal leasing process due to third-party legal challenges, regulatory developments or climate change initiatives; 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 at profitability levels achieved at times in the past.  The price we receive for our coal also impacts how economically we can recover our existing coal.  Our ability to develop

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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, including due to third party legal challenges or changes in the federal coal leasing program.

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 or give preference to any LBA applicant, which means our bids for federal coal leases may compete with other coal producers’ bids.  Federal coal leases are expensive to obtain and the review process to submit an LBA for bid continues to lengthen.  We expect this trend to continue.  The size of potential LBA tracts may also make it easier for new mining operators to enter the market on economic terms and may, therefore, further increase competition for federal coal leases.  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 are not published.  Any failure or delay in acquiring a coal lease through the LBA process, or the inability to do so on economic terms, could cause our production to decline, materially adversely affecting our business, cash flows and results of operations.

Increased opposition from non-governmental organizations and other third parties may also lengthen, delay or adversely impact the LBA process.  For example, the West Antelope II leases we were awarded through the LBA process in 2011 were subject to legal challenges against the BLM and the Secretary of the Interior by environmental organizations.  Though these challenges were unsuccessful and the plaintiffs abandoned their efforts for appeal, our nominations or lease applications may be subject to similar delays or challenges, which may result in difficulties in obtaining leases or impact our ability to mine the coal subject to those leases and/or delay our access to mine the coal.  See Note 20 of Notes to Consolidated Financial Statements in Item 8 for a discussion regarding challenges by environmental activist groups against a potential lease modification for our Antelope Mine.  If the plaintiff’s claims are successful, the timing and ability of our company to lease and mine the coal underlying the applicable surface acres would be materially adversely impacted.

In addition to third party regulatory challenges, the Department of the Interior continues to actively review and consider new regulations governing the valuation of federal coal resources, as well as expanded guidance on the production of coal on public lands issued by the BLM.  On January 15, 2016, the Secretary of the DOI announced a moratorium on the issuance of new leases for coal resources on federally-owned lands in order to allow for a “comprehensive review” of the federal coal programs.  The outcome of this moratorium and other initiatives is uncertain, but is expected to lead to further difficulty and increased costs to acquire leases to federal coal.  See Item 1 “Business—Environmental and Other Regulatory Matters—DOI Moratorium and Programmatic EIS.”

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 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

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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 continue to increase the frequency of these potential conflicts.

Further, the 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.

We may not recover our investments in our mining, exploration, port access rights, and other assets, which may require us to recognize impairment charges related to those assets.

The value of our assets may be adversely affected by numerous uncertain factors, some of which are beyond our control, including:

·                  unfavorable changes in the economic environments in which we operate;

·                  unfavorable regulatory or legal developments impacting our industry;

·                  lower-than-expected domestic and international demand and coal pricing;

·                  technical and geological operating difficulties;

·                  an inability to economically extract our coal reserves;

·                  unanticipated increases in operating costs; and

·                  an inability to obtain additional export terminal capacity due to extensive permit requirements and challenges from environmental organizations.

These may cause us to fail to recover all or a portion of our investments in those assets and may trigger the recognition of impairment charges, which could have a substantial adverse impact on our results of operations.  For example, due to the weak market outlook for 8400 Btu coal, we recorded a non-cash impairment charge of $33.4 million related to goodwill at our 8400 Btu Cordero Rojo Mine during the year ended December 31, 2015.  This represented a full write down of the Cordero Rojo Mine’s goodwill.  Additionally, in consideration of consensus projections of weak export pricing, a weak outlook for coal exports, and our associated decision to amend the port and rail contracts to require no export shipments from 2016 through 2018 in exchange for ongoing quarterly payments less than the prior take-or-pay requirements, we determined

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that the carrying values of certain intangible assets in our Logistics and Related Activities segment were impaired.  Therefore, we have written off the full value of our port access rights of $52.2 million and our $6.0 million equity investment in GPT during the year ended December 31, 2015.  Because of the volatile nature of U.S. and international coal markets, it is reasonably possible that our current estimates of projected future cash flows from our mining assets may change in the near term, which may result in the need for further adjustments to the carrying value of mineral rights and other assets.

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.

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We may be unable to obtain, maintain or renew permits or licenses necessary for our operations, including due to third party legal challenges or climate change-related assessments that are increasingly required as part of our regulatory processes, which would materially reduce our production, cash flows and profitability.

As a mining company, we must obtain a number of permits and licenses from various federal, state and local agencies and regulatory bodies that impose strict regulations on environmental and operational matters in connection with our coal operations, including restricting the number of tons we may mine under our air quality permits.  The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by the regulators, all of which make compliance more difficult or impractical, and may possibly preclude the continuance 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 EISs 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.  These challenges were unsuccessful and the plaintiffs abandoned their efforts for appeal.  Refer to Note 20 of Notes to Consolidated Financial Statements in Item 8 for a discussion regarding other challenges by environmental activist groups against regulatory permits and approvals for our mines.  These challenges seek to vacate prior regulatory decisions and authorizations that are legally required for some or all of our current or planned mining activities.  If we are required to reduce or modify our mining activities as a result of these challenges, the impact could have a material adverse effect on our shipments, financial results and liquidity, and could result in claims from third parties if we are unable to meet our commitments under pre-existing commercial agreements as a result of any such required reductions or modifications to our mining activities.

A group of organizations have also challenged BLM’s federal coal management program, under which BLM issues lease to leases for mining on federal lands. These groups allege that BLM cannot rely on an EIS conducted in 1979 to serve as the basis of the program because the EIS has not been updated to include an assessment of climate change. The district court dismissed the case, and the organizations have appealed to the U.S. Court of Appeal for the District of Columbia, which has not yet ruled on the case.  At this time we cannot predict the outcome of this litigation. However, an unfavorable ruling could adversely impact our ability to receive future permits.

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 further reduce the demand for coal as a fuel source, causing coal prices and sales of our coal to materially decline.

Global climate change initiatives and public perceptions have resulted, and are expected to continue to result, in decreased coal-fired power plant capacity and utilization, phasing out and closing many existing coal-fired power plants, reducing or eliminating construction of new coal-fired power plants in the United States and certain other countries, increased costs to mine coal and decreased demand and prices for thermal coal, including PRB coal. See Item 1 “Business—Environmental and Other Regulatory Matters—Global Climate Change.”

There are three important sources of GHGs associated with the coal industry.  The end use of our coal in electricity generation is the largest of the three sources 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 subject to pending and proposed regulations 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.  For example, the United States recently joined nearly 200 other nations in an agreement to voluntarily limit GHG emissions.  These voluntary pledges could further decrease demand and pricing for our coal.  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.  For example, the EPA released the CPP,

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which requires reductions in emissions from existing power plants, as well as new source performance standards for GHG emissions for new coal and oil-fired power plants, which require partial carbon capture and sequestration.  See “Risks Related to Our Business and Industry— Our long-term growth may be materially adversely impacted if economic, commercially available carbon capture technology for power plants is not developed and adopted in a timely manner.”  These regulatory initiatives may increase our costs and decrease demand and pricing for our coal and logistics services, 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.

Extensive environmental laws, including existing and potential future legislation, treaties and regulatory requirements relating to air emissions, affect our customers and could further 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 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.  In August 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR and ordered the EPA to continue enforcing CAIR.  More recently, the U.S. Supreme Court reversed the D.C. Circuit’s vacation of CSAPR, and the D.C. Circuit has granted a request by the EPA to lift the stay of the rule.  Subsequently, in November 2014, the EPA issued an interim final rule reconciling the CSAPR rule with the Court’s order to lift the stay, calling for Phase 1 implementation in 2015 and Phase 2 implementation in 2017.  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 new requirements for CCR management, which were finalized in December 2014 and further regulate the handling of wastes from the combustion of coal.  In addition, in March 2013, the EPA formally adopted a revised final rule to reduce emissions of toxic air pollutants from power plants.  Specifically, these MATS for power plants will reduce emissions from new and existing coal- and oil-fired electric utility steam generating units.  In June 2015, the U.S. Supreme Court struck down the MATS rule based on the EPA’s failure to take costs into consideration and remanded the case back to the D.C. Circuit.  The D.C. Circuit remanded the rule to the EPA, but the current rule will stay in place until EPA issues a new finding.

Considerable uncertainty is associated with air emissions initiatives.  New regulations are in the process of being developed, and many existing and potential regulatory initiatives are subject to review by federal or state agencies or the courts.  Stringent air emissions limitations are either in place or are likely to be imposed in the short to medium term, and these limitations will likely require significant emissions control expenditures for many coal-fired power plants.  As a result, these power plants may switch to other fuels that generate fewer of these emissions or may install more effective pollution control equipment that reduces the need for low-sulfur coal.  Any further switching of fuel sources away from coal, closure of existing coal-fired power plants, or reduced construction of new coal-fired power plants could have a material adverse effect on demand for, and prices received for, our coal.  Alternatively, less stringent air emissions limitations, particularly related to sulfur, to the extent enacted, could make low-sulfur coal less attractive, which could also have a material adverse effect on the demand for, and prices received for, our coal.  See Item 1 “Business—Environmental and Other Regulatory Matters.”

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

Our mining operations are subject to extensive federal, state and local environmental, health and safety, transportation, labor and other laws and regulations. See Item 1 “Business—Environmental and Other Regulatory Matters”.  Examples include those relating to:

·                  employee health and safety;

·                  emissions to air and discharges to water;

·                  plant and wildlife protection, including endangered species protections;

·                  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.

The costs, liabilities and requirements associated with complying with these requirements are often significant and time-consuming and may delay commencement or continuation of exploration or production.  These factors could have a material adverse effect on our results of operations, cash flows and financial condition.  New legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations may also require us to change operations significantly or incur increased costs.  For example, in November 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.  In that case, the Court denied the groups’ rulemaking petition, and in July 2014, also denied a petition seeking a rehearing of the case en banc.  Any imposition of air emission standards on coal mines or any other such changes could have a material adverse effect on our financial condition and results of operations.

The President’s Budget for Fiscal Year 2017 proposes to restore fees on coal production to pre-2006 levels in order to fund the reclamation of abandoned mines.  If enacted into law, this proposal would increase the fees on surface mining to $0.35 per ton and $0.15 for underground mines.  Given the market for coal, it is unlikely that coal mining companies would be able to recover all of these fees from their customers.

Because of the extensive regulatory environment in which we operate, we cannot assure complete compliance with all laws and regulations.  Failure to comply with these laws may result in significant costs to us to correct such violations, as well as civil or criminal penalties and limitations or shutdowns of our operations.  These laws and regulations may also significantly impair our ability to conduct our mining operations or result in increased operating costs.

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

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

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

Our operations use hazardous materials and generate hazardous and non-hazardous wastes.  In addition, many of the locations that we own, lease or operate were used for coal mining and/or 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 cleanup of soil, surface water, groundwater and other media.  These claims may arise, for example, out of current or former conditions at sites that we own, lease or operate currently, as well as at sites that we or predecessor entities owned, leased or operated in the past, and at contaminated third-party sites at which we have disposed of hazardous substances and waste.  As a matter of law, and despite any contractual indemnity or allocation arrangements or acquisition agreements to the contrary, our liability for these claims may be joint and several, so that we may be held responsible for more than our share of any contamination, or even for the entire share.

We may incur material costs and liabilities resulting from claims for damage to property or injury to persons arising from our operations.  If we are pursued for sanctions, costs and liabilities in respect of these matters, our mining operations and, as a result, our profitability could be materially adversely affected.

Significant increases in taxes we pay on the coal we produce at our mine sites or deliver through our logistics business, such as royalties or severance and production taxes, including as a result of governmental audits, legislative, regulatory, or interpretive changes, could materially and adversely affect our profitability.

We pay federal, state and private royalties and federal, state and county severance and production taxes on the coal we sell.  A substantial portion of our royalties and severance and production taxes are levied as a percentage of gross revenue with the remaining levied on a per ton basis.  For example, we pay production royalties of 12.5% of gross proceeds to the federal government on all coal sold at the mine sites.  We incurred royalties and severance and production taxes totaling $277.1 million, $331.6 million and $327.9 million for the years ended December 31, 2015, 2014 and 2013, respectively.  The calculations used to determine royalty or severance and production tax payments can be complex and subject to interpretation, making it difficult in some cases to estimate such payments.  If royalties or severance and production tax rates were to significantly increase, or if the methodology by which the government agencies assess royalties or severance and production tax rates materially changes, our results of operations could be materially adversely affected.  See Note 20 of Notes to Consolidated Financial Statements in Item 8.  Examples that could materially adversely affect our results include:

·                  the federal government has recently proposed to significantly alter the method for valuing royalty payments;

·                  a state government could increase severance or production taxes or any other tax applicable to our operations in that state; and

·                  we could be required to make additional payments (including significant related interest and penalties) as a result of pending or future governmental audits, which can date back many years.

Additionally, from time to time legislation is proposed that could result in the reduction or elimination of certain U.S. federal income tax incentives currently available to coal companies.  These include the elimination of percentage depletion for coal and the elimination of the domestic manufacturing deduction for income from the production of coal.   It is unclear whether these or similar changes will be enacted, and if enacted, how soon any such changes would take effect.

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

Federal and state laws require us to secure the performance of certain long-term obligations, such as mine closure costs, reclamation costs, and federal and state workers’ compensation costs, including black lung.  The primary methods we use to meet those obligations are to provide a third-party surety bond or a letter of credit.  As of December 31, 2015, we had outstanding surety bonds with third parties of $433.9 million and were self-bonded for $200 million.  Surety bond issuers and holders may demand additional collateral, unfavorable terms or higher fees.  In addition, we could fail to meet the requirements to continue to qualify for self-bonding which would result in us needing to increase our surety bonds which may not be available to us at attractive terms or at all.  Recently, there has been heightened regulatory pressure on reclamation bonding and self-bonding in particular.  In January 2016, the OSMRE sent Ten-Day Notices to the Wyoming Department of Environmental Quality regarding self-bonding of certain other coal companies who have filed for bankruptcy.  In its notices, the OSMRE asserted that a violation of the Wyoming approved state program may exist by allowing the specified companies to continue mining without sufficient reclamation bonding in place.  Our failure to retain, or inability to acquire, surety bonds or letters of credit or to provide a suitable alternative could adversely affect our ability to mine or lease coal, which would materially adversely affect our business and results of operations.  That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety bonds and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of any credit arrangements then in place.  In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand cash collateral as a condition to providing or maintaining surety bonds.  Any such demands, depending on the amount of any cash collateral required, could have a material adverse impact on our liquidity and financial position.  If we are unable to meet cash collateral requirements and cannot otherwise obtain or retain required surety bonds, we may be unable to satisfy legal requirements necessary to conduct our mining operations.

Furthermore, while we have maintained a history of timely payments related to our LBAs, if we are unable to maintain our “good payer” status, we would be required to seek bonding for any remaining payments, which could adversely impact our cash flows and the amount of availability under our credit facility, if such bonds could be obtained at all.

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

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

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

·                  acquisition of surface rights;

·                  equipment and the development of our mining operations;

·                  capital renovations;

·                  export terminal development projects;

·                  maintenance and expansions of plants and equipment; and

·                  compliance with environmental laws and regulations.

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

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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.  The amounts recorded are dependent upon a number of variables, including the estimated future asset retirement costs, estimated proven reserves, assumptions involving profit margins of third-party contractors, inflation rates, discount rates and assumed credit-adjusted, risk-free rates.  Furthermore, these obligations are unfunded.  If our accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be materially adversely affected.

The President’s Budget for Fiscal Year 2017 proposes to restore fees on coal production to pre-2006 levels in order to fund the reclamation of abandoned mines.  If enacted into law, this proposal would increase the fees on surface mining to $0.35 per ton and $0.15 for underground mines.  Given the market for coal, it is unlikely that coal mining companies would be able to recover all of these fees from their customers.

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

We use considerable quantities of explosives, petroleum-based fuels, tires, steel and other raw materials, as well as spare parts and other consumables in the mining process.  If the prices of steel, explosives, tires, petroleum products or other materials increase significantly or if the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses will increase, which could materially adversely impact our profitability.  Additionally, a limited number of suppliers exist for certain supplies, such as explosives and tires, as well as certain mining equipment, and any of our suppliers may divert their products to buyers in other mines or industries or divert their raw materials to produce other products that have a higher profit margin.  For example, we previously experienced a severe tire shortage in 2005 that lasted several years.  This tire shortage increased the direct cost of tires and caused us to change our operating practices to increase tire life.  Shortages in raw materials used in the manufacturing of supplies and mining equipment, which, in some cases, do not have ready substitutes, or the cancellation of our supply contracts under which we obtain these raw materials and other consumables, could limit our ability to obtain these supplies or equipment.  As a result, we may not be able to acquire adequate replacements for these supplies or equipment on a cost-effective basis or at all, which could also materially increase our operating expenses or halt, disrupt or delay our production.

Furthermore, operating expenses at our mining locations are sensitive to changes in certain variable costs, including diesel fuel prices, which is one of our largest variable costs.  Our results depend on our ability to adequately control our costs, including 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 Analysis of Financial Condition and Results of Operations—Years Ended December 31, 2015, 2014 and 2013 —Cost of Product Sold” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risks.”

Our hedging activities for diesel fuel may prevent us from benefiting from cost price decreases.

We enter into derivative financial instruments to help manage our exposure to market price changes to our diesel fuel costs, which are indexed to the West Texas Intermediate (“WTI”) crude oil price as quoted on the New York Mercantile Exchange.  As such, the nature of the derivative financial instruments does not directly offset market changes to our diesel fuel costs.

As of December 31, 2015, we had approximately 0.3 million WTI crude oil barrels hedged under costless collars, which approximates 50% of our forecasted 2016 diesel fuel needs.  We also held swap positions for 0.9 million WTI crude oil barrels for our remaining forecasted 2016 diesel fuel needs and for all of our forecasted 2017 diesel fuel needs. While our hedging strategy provides us protection in the event of crude oil price increases, it reduces our benefit when crude oil prices decrease below our floor and may require substantial payments by us to settle our financial instruments.  See Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” and Note 7 of Notes to Consolidated Financial Statements in Item 8.

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Our hedging activities for coal sales prices may result in a negative impact from sales price changes.

As part of our logistics business, we periodically enter into derivative financial instruments in the form of international coal forward contracts to help manage our exposure to future coal sales prices by fixing a price now for a future contracted coal delivery.  This type of hedge is designed to protect us from any price decreases.  While our hedging strategy provides us some degree of protection in the event future coal prices decrease it may also prevent us from benefiting if future coal prices increase above our hedged price and may require substantial payments by us to settle our financial instruments.  As of December 31, 2015, we had coal forward contracts for approximately 0.3 million tons, of which 0.3 million tons have been fixed under offsetting contracts.

In addition, we periodically use domestic coal futures contracts to help manage our exposure to market changes in domestic coal prices.  This type of hedge is designed to benefit us when prices change relative to our current open positions.  If there are significant and extended unfavorable price movements against our positions, our earnings and liquidity could be negatively impacted.  As of December 31, 2015, we held domestic coal futures contracts for approximately 0.1 million tons, which will settle in 2016.  See Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” and Note 7 of Notes to Consolidated Financial Statements in Item 8.

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

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 rises in our diesel costs.  Derivative financial instruments are recognized as either assets or liabilities and are measured at fair value.  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 or future reductions 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;

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

·                  future coal prices and demand;

·                  equipment and productivity;

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

·                  capital expenditures and development and reclamation costs;

·                  the percentage of coal ultimately recoverable;

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

·                  timing for the development of the reserves.

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

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

We have historically sold most of our coal under long-term coal sales agreements, which we generally define as contracts with a term of one to five years.  For the year ended December 31, 2015, approximately 67% 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.

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

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

The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenue and profitability.

For the year ended December 31, 2015, we derived approximately 22% of our total revenue from sales to our three largest customers and approximately 47% of our total revenue from sales to our ten largest customers.  We may be unsuccessful in obtaining and renewing coal supply agreements with these customers, and 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.

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

In recent years, we have experienced customers being less willing to enter into long-term coal sales contracts as they continue to adjust to relatively low U.S. natural gas prices, increased price volatility, increased fungibility of coal products, frequently changing regulations and the increasing deregulation of their industry.  In addition, the prices for coal in the spot market may be lower than the prices previously set under many of our long-term coal sales agreements.  As our contracts with customers expire or are otherwise renegotiated, our customers may be less willing to extend or enter into new long-term coal sales agreements under their existing or similar pricing terms or our customers may decide to purchase fewer tons of coal than in the past.

To the extent our customers shift away from long-term supply contracts, it will be more difficult to predict our future sales.  As a result, we may not have a market for our future production at acceptable prices.  The prices we receive in the spot market may be less than the contractual price an electric utility is willing to pay for a committed supply.  Furthermore, spot market prices tend to be more volatile than contractual prices, which could result in decreased revenue and profitability.  For example, as of February 2016, we had approximately 65 million tons of committed sales for 2016 and 41 million tons for 2017, which is below our typical forward sales levels, leaving more coal left to be sold for those periods.

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

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

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

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

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

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 allow for the purchase price to be renegotiated at periodic intervals.  A price re-opener provision is one in which either party can renegotiate the price of the contract, sometimes at pre-determined times.  Index provisions allow for the adjustment of the price based on a fixed formula.  These provisions may reduce the protection available under long-term contracts from short-term coal price volatility.  Our international contracts typically contain a fixed price for the first year of the contract with future years’ prices to be negotiated at a specific point in time.  If the parties fail to satisfactorily negotiate a price, the contract could be terminated.  Any adjustment or renegotiations leading to a significantly lower contract price, or a termination of the contract, could result in decreased revenue.

Our 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 low natural gas prices, a greater than normal number of our customers in 2012 sought to reduce the amount of tons delivered to them under our coal sales agreements through contractual remedies, such as force majeure provisions.  Our contracts with our 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 our foreign customers.

Most of our coal supply contracts also contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics, such as heat content, sulfur, ash and ash fusion temperature.  Failure to meet these specifications can result in economic penalties, including price adjustments, suspension, rejection or cancellation of deliveries or termination of the contracts.  A number of our contracts also contain clauses which, in some cases, may allow customers to terminate the contract in the event of certain changes in environmental laws and regulations.

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

Our ability to operate our business and implement our strategies depends, in part, on the continued contributions of our executive officers and other key employees.  The loss of any of our key senior executives could have a material adverse effect on our business unless and until we find a qualified replacement.  A limited number of persons exist with the requisite experience and skills to serve in our senior management positions.  We may not be able to locate or employ qualified executives on acceptable terms and our failure to retain or attract qualified executives could have an adverse effect on our ability to operate our business.

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

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

All of our mines are operated by non-union employees.  Our employees have the right at any time under the National Labor Relations Act to form or affiliate with a union, and in the past, unions have conducted limited organizing activities in this regard.  If our employees choose to form or affiliate with a union and the terms of a union collective bargaining agreement are significantly different from our current compensation and job assignment arrangements with our employees, these arrangements could negatively impact the stability of our production and materially reduce our profitability.  In addition, even if our managed operations remain non-union, our business may still be adversely affected by work stoppages at unionized companies or unionized transportation and service providers.

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

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

We face the risk of systems failures as well as cybersecurity risks, including “hacking.”

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

Risks Related to Our Indebtedness and Liquidity

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

As of December 31, 2015, we had consolidated indebtedness of $508.9 million.  We also have lease and royalty obligations related to our federal coal leases.  Our outstanding indebtedness could have important consequences such as:

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

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

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

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

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

·                  limiting our ability to compete effectively with companies that are not as leveraged and that may be better positioned to withstand economic downturns, including competitors who may become less leveraged when they emerge from bankruptcy;

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

·                  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

·                  a downgrade in the credit rating of our indebtedness, which could increase the cost of further borrowings and negatively impact our available liquidity.

We may incur substantially more debt in the future.  If our indebtedness is further increased, the related risks that we now face, including those described above, could increase.  In addition to the principal repayments on outstanding debt, we have other demands on our cash resources, including significant maintenance and other capital expenditures, including LBAs, and operating expenses.  Our ability to pay our debt depends upon our operating performance.  In particular, economic conditions could cause revenue to decline, and hamper our ability to repay indebtedness.  If we do not have enough cash to satisfy our debt service obligations, we may be required to refinance all or part of our debt, sell assets, limit certain capital expenditures, including future LBAs, or reduce spending or we may be required to issue equity.  We may not be able to, at any given time, refinance our debt or sell assets and we may not be able to, at any given time, issue equity, in either case on acceptable terms or at all.

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

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.  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 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 for the preceding four fiscal quarters (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 Accounts Receivable Securitization Facility (“A/R Securitization Program”).  For example, the Credit Agreement requires us to maintain (a) a ratio of EBITDA to consolidated net cash interest expense equal

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to or greater than 1.50 to 1 (“Interest Ratio”), and (b) a ratio of senior secured funded debt less unrestricted cash and marketable securities (net secured debt) to EBITDA equal to or less than 4.00 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 $530.3 million as of December 31, 2015.  See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Senior Secured Revolving Credit Facility.”  As of December 31, 2015, our trailing twelve month EBITDA, as defined within the financial covenants of the Credit Agreement, was $127.5 million, and we had full availability under our Credit Agreement.  If the trailing twelve month EBITDA plus our unrestricted cash less our capital leases were to fall below $125 million in the future, our borrowing capacity would begin to be reduced pursuant to the Leverage Ratio covenant based on our net secured debt position at that time.

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

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

Other Risks Related to Our Corporate Structure and Common Stock

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

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

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

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

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

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.  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.

The price of our common stock has recently declined significantly and could decline further for a variety of reasons, resulting in a substantial loss on investment and negatively impacting our ability to raise equity capital.

Our stock price decreased from $9.26 per share on January 2, 2015 to $2.08 per share on December 31, 2015.  It declined to $1.40 per share on February 11, 2016, and could decline further.  Such further decline could result from a variety of factors, including, among other things, actual or anticipated fluctuations in our operating results or financial condition,

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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.

The current trading price of our common stock, or any further decline thereof, 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.

The closing market price of our common stock has recently declined significantly.  If the average closing price of our common stock declines to less than $1.00 over 30 consecutive trading days, our common stock could be delisted from the NYSE or trading could be suspended.

Our common stock is currently listed on the NYSE. In order for our common stock to continue to be listed on the NYSE, we are required to comply with various listing standards, including the maintenance of a minimum average closing price of at least $1.00 per share during a consecutive 30 trading-day period. A renewed or continued decline in the closing price of our common stock on the NYSE could result in a breach of these requirements. Although we would have an opportunity to take action to cure such a breach, if we did not succeed, the NYSE could commence suspension or delisting procedures in respect of our common stock. The commencement of suspension or delisting procedures by an exchange remains, at all times, at the discretion of such exchange and would be publicly announced by the exchange. If a suspension or delisting were to occur, there would be significantly less liquidity in the suspended or delisted securities. In addition, our ability to raise additional necessary capital through equity or debt financing, and attract and retain personnel by means of equity compensation, would be greatly impaired. Furthermore, with respect to any suspended or delisted securities, we would expect decreases in institutional and other investor demand, analyst coverage, market making activity and information available concerning trading prices and volume, and fewer broker-dealers would be willing to execute trades with respect to such securities. A suspension or delisting would likely decrease the attractiveness of our common stock to investors and cause the trading volume of our common stock to decline, which could result in a further decline in the market price 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;

·                  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.

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Item 2.  Properties.

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

Coal Reserves

As of December 31, 2015, we controlled approximately 1.1 billion tons of proven and probable coal reserves.  All of our proven and probable reserves are classified as thermal coal.

The following table summarizes the tonnage of our coal reserves that is classified as proven or probable, and assigned, as well as our property interest, as of December 31, 2015:

(1)                                 Totals reflect rounding.

The following table provides the “quality” (average sulfur content and average Btu per pound) of our coal reserves as of December 31, 2015:

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

(2)                                 Totals reflect rounding.

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

·                        8 million tons near our Antelope Mine;

·                        53 million tons near our Cordero Rojo Mine;

·                        4 million tons near our Spring Creek Mine; and

·                        287 million tons at the Youngs Creek project.

Non-reserve coal deposits are not reserves under SEC Industry Guide 7.  Estimates of non-reserve coal deposits are subject to further exploration and development, are more speculative and may not be converted to future reserves of the company.

Our reserve and non-reserve coal deposit estimates as of December 31, 2015 were prepared by our staff of geologists and engineers, who have extensive experience in PRB coal.  These individuals are responsible for collecting and analyzing geologic data within and adjacent to leases controlled by us.  Our Manager, Geology is the technical person primarily responsible for the preparation of our reserves estimates.  He has a Bachelor of Science degree in Geology and 10 years of industry experience with positions of increasing responsibility in mining geology and reserve determination.  He reports to our Director, Geological Services and Special Projects, who has a Bachelor of Science degree in Mining Engineering and over 30 years of industry experience with positions of increasing responsibility in coal quality and mine planning, operations, project evaluations, risk management, and technical management at CPE Inc.  The Director, Geological

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Services and Special Projects reports directly to our Senior Vice President, Technical Services.  An external review of our reserves and non-reserve coal deposit estimates is performed every two years.  The most recent review was performed for the year ended December 31, 2014 and was completed in January 2015 by John T. Boyd Company, mining and geological consultants.  The results verified our reserve and non-reserve coal deposit estimates for the year ended December 31, 2014.

Our coal reserve estimates are based on data obtained from our drilling activities and other available geologic data.  All of our reserves are assigned, associated with our active coal properties, and incorporated in detailed mine plans.  Estimates of our reserves are based on more than 7,000 drill holes.  Our proven reserves have a typical drill hole spacing of 1,500 feet or less, and our probable reserves have a typical drill hole spacing of 2,500 feet or less.

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

Reserve Acquisition Process

Since our inception, we have focused on growth through the acquisition of proven and probable coal reserves and non-reserve coal deposits.  Historically, this was accomplished through the federal competitive leasing process, known as the LBA process.  For example, in 2011 we acquired 383 million tons of proven and probable coal reserves in two federal coal leases for our Antelope Mine.

On January 15, 2016, the Secretary of the DOI announced a moratorium on the issuance of new leases for coal resources on federally-owned lands in order to allow for a “comprehensive review” of the federal coal programs.  The terms of this moratorium preclude the BLM from accepting new applications for thermal coal sales, or modifying existing leases subject to certain exceptions.  See Item 1 “Business—Environmental and Other Regulatory Matters—DOI Moratorium and Programmatic EIS.”  The following disclosure describes the LBA process by which we have historically acquired coal.

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 has lasted 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 may result in delays and other adverse impacts on the LBA process.

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

The BLM also allows for small tracts of coal to be acquired through the LBM leasing process.  An LBM is a non-competitive leasing process and is used in circumstances where a lessee is seeking to modify an existing federal coal lease by adding less than 960 acres in a configuration that is deemed non-competitive to other coal operators.  For example, in December 2012, we applied for two separate LBMs with the BLM:  one at the Spring Creek Mine and one at the Antelope Mine.  As of December 31, 2015, a Decision Record to issue the Antelope LBM has been made by BLM and appealed by certain environmental groups.  The appeal is under review by the Interior Board of Land Appeals.  The Spring Creek application was being processed 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.

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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 payer.  The bids are opened at the lease sale.  If the BLM decides to grant a lease, the lease is awarded to the company that submitted the highest total bid meeting or exceeding the BLM’s fair market value estimate, which is not published.  The BLM, however, is not required to grant a lease even if it determines that a bid meeting or exceeding the fair market value of the coal has been submitted.  The winning bidder must also submit a report setting forth the nature and extent of its coal holdings to the U.S. Department of Justice for a 30-day antitrust review of the lease.  If the successful bidder was not the initial applicant, the BLM will refund the initial applicant certain fees it paid in connection with the application process, for example the fees associated with the environmental analysis or EIS, and the winning bidder will bear those costs.  Coal awarded through the LBA process and subject to federal leases is administered by the U.S. Department of Interior under the Federal Coal Leasing Amendment Act of 1976.  Once the BLM has issued a lease, the company must next complete the permitting process before it can mine the coal.  See Item 1 “Business—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 NGOs, can challenge the BLM’s actions, which may delay the leasing process.  If these challenges prove successful or are litigated for a prolonged period of time, a coal company’s ability to bid on or acquire a new coal lease could be significantly delayed, or could cause the BLM to not offer a lease for bid at all.  For example, environmental organizations filed legal challenges against the BLM’s findings on the final EIS and other matters associated with the West Antelope II LBA, which was nominated by our Antelope Mine.  Though these challenges were unsuccessful and the plaintiffs abandoned their efforts for appeal, these types of challenges create some uncertainty with respect to the timing of future LBA bids and lease acquisitions and may ultimately delay the leasing process or prevent mining operations.  Even after a lease has been issued and a successful bidder has paid installment money to the BLM, legal challenges may still seek to delay or prevent mining operations.  It is possible that subsequent EISs for other mines in the PRB currently underway but not yet final could be similarly challenged.  There also exists the possibility of similar challenges to the permitting and licensing process, which is also a public process designed to allow public comments.  Refer to Note 20 of Notes to Consolidated Financial Statements in Item 8 for a discussion regarding current challenges by environmental activist groups against existing regulatory permits and approvals for our mines and against a pending lease modification for our Antelope Mine.

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

Most of the coal we lease from the U.S. comes from “split estate” lands in which one party, such as the federal government, owns the coal and a private party owns the surface.  In order to mine the coal we acquire, we must acquire rights to mine from certain owners of the surface lands overlying the coal.  Certain federal regulations provide a specific class of surface owners, QSOs, with the ability to prohibit the BLM from leasing its coal.  For example, in connection with an LBA tract that we previously nominated for our Cordero Rojo Mine, the BLM indicated that certain surface owners satisfied the regulatory definition of QSO.  If the land overlying a coal tract is owned by a QSO, federal laws prohibit us from leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO, which would allow us to conduct our mining operations.  Furthermore, the state permitting process requires us to demonstrate surface owner consent for split estate lands before the state will issue a permit to mine coal.  This consent is separate from the QSO consent

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required before leasing federal coal.  This right of QSOs and certain other surface owners allows them to exercise significant influence over negotiations and prices to acquire surface rights and can delay the federal coal lease or permitting processes or ultimately prevent the acquisition of the federal coal lease or permit over that land entirely.  There are QSOs that own land adjacent to or near our existing mines that may be attractive acquisition candidates for us.  Typically, we seek to purchase the land overlying our coal or enter into option agreements granting us an option to purchase the land upon acquiring a federal coal lease.  We own substantially all of the land over our reserves.  We may not own or control the land over our non-reserve coal deposits, which would be required before these non-reserve coal deposits could be classified as reserves and mined.

Most of the coal we have acquired from private third parties is in the form of coal leases obtained through private negotiations with one or more third parties.  These leases generally include, among other terms and conditions, a set term of years with the right to renew the lease for a stated period and royalties to be paid to the lessor as a percentage of the sales price. These leases may require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments, and a minimum production of coal from the leased areas in order to hold the leases by active production.  We believe that the term of years will allow the recoverable reserve to be fully extracted in accordance with our projected mine plan.  Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing.  Title to properties leased from private third parties is not usually fully verified until we make a commitment to develop a property, which may not occur until we have obtained the necessary permits and completed exploration of the property.

On August 24, 2015, we entered into a surface rights agreement that provided our Cordero Rojo Mine with access to approximately 95 million tons of additional coal contained within a federal coal lease controlled by the mine.  These additional tons were evaluated as part of the year-end reserve reporting process and were determined to be proven and probable reserves as of December 31, 2015.  The additional coal consists of tons directly under the acquired land and other adjacent tonnage that is anticipated to become available for future mining as a result of acquiring the surface access. The agreement primarily involves a land exchange and production payments from any future sales of the underlying coal, including certain recoupable advance production payments.

We acquired significant coal deposits when we completed the acquisition of the Youngs Creek project, a non-operating mine in Northeast Wyoming in the Northern PRB, whereby we acquired 287 million tons of non-reserve coal deposits along with significant related surface assets.  We also announced in 2013 that we signed an option agreement and a corresponding exploration agreement with the Crow Tribe of Indians for the exploration and potential development of significant coal resources on the Crow Indian Reservation in southeast Montana in the Northern PRB region.  Subject to market conditions, we intend to continue to seek opportunities to acquire additional coal through the federal leasing process upon expiration of the leasing moratorium as well as through private transactions with third parties or sovereign nations such as the Crow Tribe of Indians.

Office Space

Our corporate headquarters is located in Gillette, Wyoming, where we own approximately 32,000 square feet of office space.  In addition, we lease approximately 5,600 square feet of additional office space in Gillette, Wyoming,  under an annual lease expiring in April 2016, and we lease approximately 28,000 square feet of office space in Broomfield, Colorado under a lease that expires in February 2021.  As of December 31, 2015, all of our long-lived assets were located in the U.S.  See Note 24 of Notes to Consolidated Financial Statements in Item 8.

Item 3.  Legal Proceedings.

For a discussion of legal proceedings, please see Note 20 of Notes to the Consolidated Financial Statements in Item 8.

Item 4.  Mine Safety Disclosures

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

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PART II

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

Our common stock, $0.01 par value, is traded on the New York Stock Exchange (“NYSE”) under the symbol “CLD”.  The following table sets forth the intraday high and low sales prices of our common stock, as reported by the NYSE, for each of the periods listed.

The last reported sale price of our common stock on the NYSE on December 31, 2015 was $2.08 per share. As of the close of business on February 11, 2016, there were 76 holders of record of our common stock.

Dividend Policy

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

Stock Performance Graph

The following performance graph compares the cumulative total return on CPE Inc.’s common stock with the cumulative total return of the following indices: (i) the Standard & Poor’s (“S&P”) MidCap 400 stock index and (ii) the Custom Composite Index.  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.  As of December 31, 2015, this group was comprised of Alliance Resource Partners LP, Alpha Natural Resources, Inc., Arch Coal, Inc., Cabot Oil & Gas Corporation, CONSOL Energy Inc., EQT Corporation, Foresight Energy LP, Newfield Exploration Co., Noble Energy, Inc., Peabody Energy Corp., Penn Virginia Corporation, Rhino Resource Partners LP, Sabine Oil & Gas Corporation, SandRidge Energy, Inc., SM Energy Company, SunCoke Energy Inc., Walter Energy, Inc., Westmoreland Coal Co., and Whiting Petroleum Corp.  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.  In 2015, James River Coal was removed from the Custom Composite Index as a result of its previous bankruptcy filing and Oxford Resource Partners LP was removed as a result of Westmoreland’s acquisition of Oxford’s general partner.  To replace these companies, Foresight Energy LP, a coal company, was added and Sabine Oil & Gas Corporation replaced Forest Oil, which Sabine had acquired.

The graph assumes that you invested $100 in CPE Inc.’s common stock and in each index at the closing price on December 31, 2010, that all dividends were reinvested and that you continued to hold your investment through December 31, 2015.

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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.

(1)                                 Reflects the Custom Composite Index as of December 31, 2015.

(2)                                 Reflects the Custom Composite Index as of December 31, 2014.

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

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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, 2015:

(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, 2015 and 2014 and for each of the three years in the period ended December 31, 2015 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, 2013, 2012 and 2011 and the historical consolidated statements of operations data for the years ended December 31, 2012 and 2011 from our audited consolidated financial statements not included in this report.

Selected Consolidated Financial and Other Data

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(1)                                 No cash dividends were declared or paid on our common stock during the periods presented.

(2)                                 Inclusive of intersegment sales.

(3)                                 EBITDA, Adjusted EBITDA and Adjusted EPS are intended to provide additional information only and do not have any standard meaning prescribed by generally accepted accounting principles in the U.S. (“U.S. GAAP”)  A quantitative reconciliation of historical net income (loss) to Adjusted EBITDA and EPS (as defined below) to Adjusted EPS is found in the tables below.

EBITDA represents net income (loss) before: (1) interest income (expense) net, (2) income tax provision, (3) depreciation and depletion, and (4) amortization.  Adjusted EBITDA represents EBITDA as further adjusted for accretion, which represents non-cash increases in asset retirement obligation liabilities resulting from the passage of time, and specifically identified items that management believes do not directly reflect our core operations.  For the periods presented herein, the specifically identified items are:  (1) adjustments to exclude the changes in the Tax Receivable Agreement, (2) adjustments for derivative financial instruments, excluding fair value mark-to-market gains or losses and including cash amounts received or paid, (3) adjustments to exclude non-cash impairment charges, and (4) adjustments to exclude the gain from the sale of our 50% non-operating interest in the Decker Mine in September 2014.  We enter into certain derivative financial instruments such as put options that require the payment of premiums at contract inception.  The reduction in the premium value over time is reflected in the mark-to-market gains or losses.  Our calculation of Adjusted EBITDA does not include premiums paid for derivative financial instruments; either at contract inception, as these payments pertain to future settlement periods, or in the period of contract settlement, as the payment occurred in a preceding period.  Because of the inherent uncertainty related to the items identified above, management does not believe it is able to provide a meaningful forecast of the comparable GAAP measures or reconciliation to any forecasted GAAP measure.

Adjusted EPS represents diluted earnings (loss) per common share (“EPS”) adjusted to exclude (i) the estimated per share impact of the same specifically identified non-core items used to calculate Adjusted EBITDA as described above, (ii) the change in tax valuation allowance, and (iii) the cash and non-cash interest expense associated with the early retirement of debt and refinancing transactions.  All items are adjusted at the statutory tax rate of approximately 37%.

Adjusted EBITDA is an additional tool intended to assist our management in comparing our performance on a consistent basis for purposes of business decision making by removing the impact of certain items that management believes do not directly reflect our core operations.  Adjusted EBITDA is a metric intended to assist management in evaluating operating performance, comparing performance across periods, planning and forecasting future business operations and helping determine levels of operating and capital investments.  Period-to-period comparisons of Adjusted EBITDA are intended to help our management identify and assess additional trends potentially impacting

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our company that may not be shown solely by period-to-period comparisons of net income (loss).  Consolidated Adjusted EBITDA is also used as part of our incentive compensation program for our executive officers and others.