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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

Form 10-K

 

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

 

Commission file number: 1-13105

 


 

 

Arch Coal, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware
(State or other jurisdiction
of incorporation or organization)

 

43-0921172
(I.R.S. Employer
Identification Number)

 

 

 

One CityPlace Drive, Ste. 300, St. Louis, Missouri
(Address of principal executive offices)

 

63141
(Zip code)

 

Registrant’s telephone number, including area code: (314) 994-2700

 

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

 

Title of Each Class

 

Name of Each Exchange on Which Registered

Common Stock, $.01 par value

 

OTC Pink

 

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 x  No o

 

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

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) 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.

 

Large accelerated filer o

 

Accelerated filer x

 

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

 

Smaller reporting company o

 

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

 

The aggregate market value of the voting stock held by non-affiliates of the registrant (excluding outstanding shares beneficially owned by directors, officers, other affiliates and treasury shares) as of June 30, 2015 was approximately $72.4 million.

 

At February 12, 2016 there were 21,446,233 shares of the registrant’s common stock outstanding.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

 

 

Page

PART I

 

 

ITEM 1.

BUSINESS

5

ITEM 1A.

RISK FACTORS

37

ITEM 1B.

UNRESOLVED STAFF COMMENTS

51

ITEM 2.

PROPERTIES

52

ITEM 3.

LEGAL PROCEEDINGS

57

ITEM 4.

MINE SAFETY DISCLOSURES

59

 

 

 

PART II

 

 

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

60

ITEM 6.

SELECTED FINANCIAL DATA

61

ITEM 7.

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

62

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

80

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

81

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUTING AND FINANCIAL DISCLOSURE

81

ITEM 9A.

CONTROLS AND PROCEDURES

81

ITEM 9B.

OTHER INFORMATION

81

 

 

 

PART III

 

 

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

82

ITEM 11.

EXECUTIVE COMPENSATION

82

ITEM 12.

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

82

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

82

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

82

 

 

 

PART IV

 

 

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

84

 

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If you are not familiar with any of the mining terms used in this report, we have provided explanations of many of them under the caption “Glossary of Selected Mining Terms” on page 36 of this report. Unless the context otherwise requires, all references in this report to “Arch,” “we,” “us,” or “our” are to Arch Coal, Inc. and its subsidiaries.

 

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

 

This report contains forward-looking statements, within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, such as our expected future business and financial performance, and are intended to come within the safe harbor protections provided by those sections. The words “anticipates,” “believes,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “predicts,” “projects,” “seeks,” “should,” “will” or other comparable words and phrases identify forward-looking statements, which speak only as of the date of this report. Forward-looking statements by their nature address matters that are, to different degrees, uncertain. Actual results may vary significantly from those anticipated due to many factors, including:

 

·                  our ability to continue as a going concern;

 

·                  our ability to successfully complete a reorganization under Chapter 11 and emerge from bankruptcy;

 

·                  potential adverse effects of the Chapter 11 Cases (as defined below) on our liquidity and results of operations;

 

·                  our ability to obtain timely Bankruptcy Court approval with respect to motions filed in the Chapter 11 Cases;

 

·                  objections to the Company’s plan of reorganization that could protract the Chapter 11 Cases;

 

·                  employee attrition and our ability to retain senior management and key personnel due to the distractions and uncertainties, including our ability to provide adequate compensation and benefits during the Chapter 11 Cases;

 

·                  market demand for coal and electricity;

 

·                  geologic conditions, weather and other inherent risks of coal mining that are beyond our control;

 

·                  competition, both within our industry and with producers of competing energy sources;

 

·                  excess production and production capacity;

 

·                  our ability to acquire or develop coal reserves in an economically feasible manner;

 

·                  inaccuracies in our estimates of our coal reserves;

 

·                  availability and price of mining and other industrial supplies;

 

·                  availability of skilled employees and other workforce factors;

 

·                  disruptions in the quantities of coal produced by our contract mine operators;

 

·                  our ability to collect payments from our customers;

 

·                  defects in title or the loss of a leasehold interest;

 

·                  railroad, barge, truck and other transportation performance and costs;

 

·                  our ability to successfully integrate the operations that we acquire;

 

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·                  our ability to secure new coal supply arrangements or to renew existing coal supply arrangements;

 

·                  our relationships with, and other conditions affecting our customers;

 

·                  the deferral of contracted shipments of coal by our customers;

 

·                  our ability to service our outstanding indebtedness;

 

·                  our ability to comply with the restrictions imposed by our DIP Credit Agreement, our Securitization Facility and other financing arrangements;

 

·                  the availability and cost of surety bonds;

 

·                  our ability to manage the market and other risks associated with certain trading and other asset optimization strategies;

 

·                  terrorist attacks, military action or war;

 

·                  our ability to obtain and renew various permits, including permits authorizing the disposition of certain mining waste;

 

·                  existing and future legislation and regulations affecting both our coal mining operations and our customers’ coal usage, governmental policies and taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases;

 

·                  the accuracy of our estimates of reclamation and other mine closure obligations;

 

·                  the existence of hazardous substances or other environmental contamination on property owned or used by us; and

 

·                  other factors, including those discussed in “Legal Proceedings”, set forth in Item 3 of this report and “Risk Factors,” set forth in Item 1A of this report.

 

All forward-looking statements in this report, as well as all other written and oral forward-looking statements attributable to us or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements contained in this section and elsewhere in this report. These factors are not necessarily all of the important factors that could affect us. These risks and uncertainties, as well as other risks of which we are not aware or which we currently do not believe to be material, may cause our actual future results to be materially different than those expressed in our forward-looking statements. These forward-looking statements speak only as of the date on which such statements were made, and we do not undertake to update our forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by the federal securities laws.

 

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PART I

 

ITEM 1. BUSINESS

 

Introduction

 

We are one of the world’s largest coal producers. For the year ended December 31, 2015,  we sold approximately 128 million tons of coal, including approximately 1.4 million tons of coal we purchased from third parties. We sell substantially all of our coal to power plants, steel mills and industrial facilities. At December 31, 2015, we operated, or contracted out the operation of, 16 active mines located in each of the major coal-producing regions of the United States. The locations of our mines and access to export facilities enable us to ship coal worldwide.

 

Our History

 

We were organized in Delaware in 1969 as Arch Mineral Corporation. In July 1997, we merged with Ashland Coal, Inc., a subsidiary of Ashland Inc. that was formed in 1975. As a result of the merger, we became one of the largest producers of low-sulfur coal in the eastern United States.

 

In June 1998, we expanded into the western United States when we acquired the coal assets of Atlantic Richfield Company. This acquisition included the Black Thunder and Coal Creek mines in the Powder River Basin of Wyoming, the West Elk mine in Colorado and a 65% interest in Canyon Fuel Company, which operated three mines in Utah. In October 1998, we acquired a leasehold interest in the Thundercloud reserve, a 412-million-ton federal reserve tract adjacent to the Black Thunder mine.

 

In July 2004, we acquired the remaining 35% interest in Canyon Fuel Company. In August 2004, we acquired Triton Coal Company’s North Rochelle mine adjacent to our Black Thunder operation. In September 2004, we acquired a leasehold interest in the Little Thunder reserve, a 719-million-ton federal reserve tract adjacent to the Black Thunder mine.

 

In December 2005, we sold the stock of Hobet Mining, Inc., Apogee Coal Company and Catenary Coal Company and their four associated mining complexes (Hobet 21, Arch of West Virginia, Samples and Campbells Creek) and approximately 455 million tons of coal reserves in Central Appalachia to Magnum Coal Company, which was subsequently acquired by Patriot Coal Corporation.

 

In October 2009, we acquired Rio Tinto’s Jacobs Ranch mine complex in the Powder River Basin of Wyoming, which included 345 million tons of low-cost, low-sulfur coal reserves, and integrated it into the Black Thunder mine.

 

In June 2011, we acquired International Coal Group, Inc., which owned and operated mines primarily in the Appalachian Region of the United States.

 

In August 2013, we sold the equity interests of Canyon Fuel Company, LLC (“Canyon Fuel”), which owned and operated our Utah operations.

 

Filing Under Chapter 11 of the United States Bankruptcy Code

 

On January 11, 2016 (the “Petition Date”), Arch and substantially all of Arch’s wholly owned domestic subsidiaries (the “Filing Subsidiaries” and, together with Arch, the “Debtors”) filed voluntary petitions for reorganization (collectively, the “Bankruptcy Petitions”) under Chapter 11 of Title 11 of the U.S. Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Eastern District of Missouri (the “Court”). The Debtor’s Chapter 11 Cases (collectively, the “Chapter 11 Cases”) are being jointly administered under the caption In re Arch Coal, Inc., et al. Case No. 16-40120 (lead case). Each Debtor will continue to operate its business as a “debtor in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Court.

 

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The filing of the Bankruptcy Petitions constituted an event of default that accelerated Arch’s obligations under the documents governing each of Arch’s 7.00% senior notes due 2019, 9.875% senior notes due 2019, 8.00% senior secured second lien notes due 2019, 7.25% senior notes due 2020, 7.25% senior notes due 2021 (together, the “senior notes”) and senior secured first lien term loan due 2018 (the “Existing Credit Agreement”) (collectively with the senior notes, the “Debt Instruments”), all as further described in Note 14, “Debt and Financing Arrangements” to the Consolidated Financial Statements included in the Form 10-K. Immediately after filing the Bankruptcy Petitions, Arch began notifying all known current or potential creditors of the Debtors of the bankruptcy filings.

 

Additionally, on the Petition Date, the New York Stock Exchange (the “NYSE”) determined that Arch was no longer suitable for listing pursuant to Section 8.02.01D of the NYSE continued listing standards, and trading in the Company’s common stock was suspended on January 11, 2016.  We expect that the existing common stock of the Company will be extinguished upon the Company’s emergence from Chapter 11 and existing equity holders will not receive consideration in respect of their equity interests.

 

On the Petition Date, the Debtors filed a number of motions with the Court generally designed to stabilize their operations and facilitate the Debtors’ transition into Chapter 11. Certain of these motions sought authority from the Court for the Debtors to make payments upon, or otherwise honor, certain pre-petition obligations (e.g., obligations related to certain employee wages, salaries and benefits and certain vendors and other providers essential to the Debtors’ businesses). The Court has entered orders approving the relief sought in these motions.

 

Pursuant to Section 362 of the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically stayed most actions against the Debtors, including actions to collect indebtedness incurred prior to the Petition Date or to exercise control over the Debtors’ property. Subject to certain exceptions under the Bankruptcy Code, the filing of the Debtors’ Chapter 11 Cases also automatically stayed the continuation of most legal proceedings, including certain of the third party litigation matters described under “Legal Proceedings,” or the filing of other actions against or on behalf of the Debtors or their property to recover on, collect or secure a claim arising prior to the Petition Date or to exercise control over property of the Debtors’ bankruptcy estates, unless and until the Court modifies or lifts the automatic stay as to any such claim. Notwithstanding the general application of the automatic stay described above, governmental authorities may determine to continue actions brought under their police and regulatory powers.

 

As required by the Bankruptcy Code, the U.S. Trustee for the Eastern District of Missouri appointed an official committee of unsecured creditors (the “Creditors’ Committee”) on January 25, 2016. The Creditors’ Committee represents all unsecured creditors of the Debtors and has a right to be heard on all matters that come before the Court.

 

As a result of extremely challenging current market conditions, Arch believes it will require a significant restructuring of its balance sheet in order to continue as a going concern in the long term. The Company’s ability to continue as a going concern is dependent upon, among other things, its ability to become profitable and maintain profitability and its ability to successfully implement its Chapter 11 plan strategy. As a result of the Bankruptcy Petitions, the realization of the Debtors’ assets and the satisfaction of liabilities are subject to significant uncertainty. While operating as a debtor-in-possession pursuant to the Bankruptcy Code, the Company may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Court or as otherwise permitted in the ordinary course of business for amounts other than those reflected in the accompanying consolidated financial statements. Further, a Chapter 11 plan is likely to materially change the amounts and classifications of assets and liabilities reported in the Company’s Consolidated Financial Statements.

 

Restructuring Support Agreement

 

In connection with the filing of the Bankruptcy Petitions, Arch entered into a Restructuring Support Agreement, dated as of January 10, 2016 (the “Restructuring Support Agreement”), among the Debtors and holders of over 50% of Arch’s first lien term loans under Arch’s Existing Credit Agreement (the “Supporting First Lien Creditors”), providing that the Supporting First Lien Creditors will support a restructuring of the Debtors, subject to the following terms and conditions contemplated therein, among others:

 

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·                  existing common stock of Arch would likely be extinguished upon the Company’s emergence from Chapter 11, and existing equity holders would likely not receive consideration in respect of their equity interests;

 

·                  claims against the Debtors arising under the DIP Facility (as defined below) would be paid in full in cash or receive such other treatment as may be consented to by the holders of such claims;

 

·                  claims against the Debtors of holders of first lien term loans would be exchanged for (a) a combination of cash and $326.5 million (principal amount) of new first lien debt that would be issued by the reorganized Company and (b) 100% of the common stock of the reorganized Company outstanding on the effective date of the plan, subject to dilution on account of a proposed new management incentive plan and the distribution to unsecured creditors of any new common stock and warrants (as described below);

 

·                  first lien term loan deficiency claims (subject to certain exceptions) as well as second lien notes, unsecured notes and general unsecured claims against the Debtors would be exchanged for either (1) common stock in the reorganized Company and warrants or (2) the value of the unencumbered assets of the Company, if any, after giving effect to certain other payments and claims;

 

·                  either the Company’s existing accounts receivable securitization facility would be reinstated or a new letter of credit facility would be entered into by the Company, in either case on terms acceptable to Supporting First Lien Creditors holding more than 66 2/3% of the aggregate amount of the first lien term loans held by Supporting First Lien Creditors; and

 

·                  the board of directors of the reorganized Company would consist of seven directors, at least one of whom would be independent, including the Company’s Chief Executive Officer and six directors selected by certain of the Company’s first-lien term lenders in consultation with the Company’s Chief Executive Officer.

 

The Restructuring Support Agreement, if utilized as the basis for a plan of reorganization, is expected to reduce Arch’s long-term debt by more than $4.5 billion.

 

We entered into an amendment to the Restructuring Support Agreement on February 25, 2016 (the “RSA Amendment”), which provides for the waiver of the termination event that would have occurred on February 25, 2016 as a result of the Debtors not having obtained Court approval of the assumption of the Restructuring Support Agreement within 45 days of the Petition Date. The Debtors had previously agreed, with the consent of the Majority Consenting Lenders under the Restructuring Support Agreement, to adjourn the Court hearing on the Restructuring Support Agreement at the request of the official committee of unsecured creditors appointed in the Debtors’ Chapter 11 cases. Pursuant to the RSA Amendment, unless otherwise agreed by the Majority Consenting Lenders, the Debtors are required to obtain Court approval of the assumption of the Restructuring Support Agreement on or before the date that is 90 days from the Petition Date.

 

The RSA Amendment also provides for a waiver of any termination event that otherwise would occur as a result of the dismissal of the Chapter 11 case of one of our subsidiaries following the sale of such subsidiary and a 45-day extension of the date after which the Debtors and the Majority Consenting Lenders may modify the proposed distributions to holders of unsecured claims if holders of more than $1.6125 billion of unsecured claims against the Debtors have not executed a restructuring support agreement substantially in the form of the Restructuring Support Agreement.

 

Securitization Agreement

 

On January 13, 2016, Arch and its securitization financing providers (the “Securitization Financing Providers”) agreed that, subject to certain amendments (the “Amendments”), they will continue the $200 million trade accounts receivable securitization facility provided to Arch Receivable Company, LLC, a non-debtor special-purpose entity that is a wholly owned subsidiary of the Company (“Arch Receivable”) (the “Securitization Facility”). See Item 7, “Management’s Discussion and Analysis—Liquidity and Capital Resources—Securitization Agreement” for more information.

 

Debtor-In-Possession Financing

 

On January 21, 2016, the Superpriority Secured Debtor-in-Possession Credit Agreement, as amended by the Waiver and Consent and Amendment No. 1, dated as of March 4, 2016, (the “DIP Credit Agreement”) was entered into by and among the Company, as borrower, certain of the Debtors, as guarantors (the “Guarantors” and, together with the Company, the “Loan Parties”), the lenders from time to time party thereto (the “DIP Lenders”) and Wilmington Trust, National Association, as administrative agent and collateral agent for the DIP Lenders (in such capacities, the “DIP Agent”).

 

The DIP Credit Agreement, which has been approved by the Court on a final basis, provides for a super-priority senior secured debtor-in-possession credit facility (the “DIP Facility”) consisting of term loans (collectively, the “DIP Term Loan”) in the aggregate principal amount of up to $275 million that may be funded in not more than two draws not later than six months after the effective date of the DIP Facility (such six month period, the “Availability Period”).  Any portion of the DIP Term Loan commitment that has not been funded on or prior to the end of the Availability Period will be permanently cancelled. The

 

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DIP Facility includes a $75 million carve-out from the first priority lien granted in favor of the DIP Agent for the benefit of the DIP Lenders on all encumbered and unencumbered assets of the Loan Parties for super-priority claims relating to certain of the Debtors’ bonding obligations. See Item 7, “Management’s Discussion and Analysis—Liquidity and Capital Resources—Debtor-In-Possession Financing” for more information.

 

Coal Characteristics

 

End users generally characterize coal as steam coal or metallurgical coal. Heat value, sulfur, ash, moisture content, and volatility, in the case of metallurgical coal, are important variables in the marketing and transportation of coal. These characteristics help producers determine the best end use of a particular type of coal. The following is a description of these general coal characteristics:

 

Heat Value.  In general, the carbon content of coal supplies most of its heating value, but other factors also influence the amount of energy it contains per unit of weight. The heat value of coal is commonly measured in Btus. Coal is generally classified into four categories, lignite, subbituminous, bituminous and anthracite, reflecting the progressive response of individual deposits of coal to increasing heat and pressure. Anthracite is coal with the highest carbon content and, therefore, the highest heat value, nearing 15,000 Btus per pound. Bituminous coal, used primarily to generate electricity and to make coke for the steel industry, has a heat value ranging between 10,500 and 15,500 Btus per pound. Subbituminous coal ranges from 8,300 to 13,000 Btus per pound and is generally used for electric power generation. Lignite coal is a geologically young coal which has the lowest carbon content and a heat value ranging between 4,000 and 8,300 Btus per pound.

 

Sulfur Content.  Federal and state environmental regulations, including regulations that limit the amount of sulfur dioxide that may be emitted as a result of combustion, have affected and may continue to affect the demand for certain types of coal. The sulfur content of coal can vary from seam to seam and within a single seam. The chemical composition and concentration of sulfur in coal affects the amount of sulfur dioxide produced in combustion. Coal-fueled power plants can comply with sulfur dioxide emission 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-dioxide emission reduction technology.

 

Ash.  Ash is the inorganic residue remaining after the combustion of coal. As with sulfur, 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 composition of the ash, including the proportion of sodium oxide and fusion temperature, is also an important characteristic of coal, as it helps to determine the suitability of the coal to end users. The absence of ash is also important to the process by which metallurgical coal is transformed into coke for use in steel production.

 

Moisture.  Moisture content of coal varies by the type of coal, the region where it is mined and the location of the coal within a seam. In general, high moisture content decreases the heat value and increases the weight of the coal, thereby making it more expensive to transport. Moisture content in coal, on an as-sold basis, can range from approximately 2% to over 30% of the coal’s weight.

 

Other.  Users of metallurgical coal measure certain other characteristics, including fluidity, swelling capacity and volatility to assess the strength of coke produced from a given coal or the amount of coke that certain types of coal will yield. These characteristics may be important elements in determining the value of the metallurgical coal we produce and market.

 

The Coal Industry

 

Background.  Coal is traded globally and can be transported to demand centers by ship, rail, barge or truck. Total world coal production reached 7.7 billion tonnes in 2014, according to the International Energy Agency (IEA). Total hard coal production decreased 0.5% to an estimated 6.9 billion tonnes in 2014 from 2013 levels, while global production of lignite coal declined roughly 3% to 810 million tonnes. Also according to IEA estimates, China remained the largest producer of coal in the world, producing over 3.5 billion tonnes in 2014. The United States and India follow China with total coal production of over

 

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900 million tonnes and 600 million tonnes, respectively, in 2014.  Preliminary data for 2015 suggests further erosion in global coal demand, but the relative ranking of producer countries remained the same.

 

Cross-border trade of coal was close to 1.4 billion tonnes in 2014, according to the IEA. Despite a drop in coal imports, China remained the largest importer of globally traded coal in 2014, taking over 305 million tonnes. India and Japan followed China with total coal imports of over 239 million tonnes and 187 million tonnes, respectively. Imports in OECD Europe were slightly higher in 2014 at an estimated 280 million tonnes.

 

The primary nations that are supplying coal to the global power and steel markets are Australia and Indonesia, as well as Russia, the United States, Colombia and South Africa. The IEA estimates that these key supply regions combined made up 86% of total global cross-border coal trade in 2014.

 

Global Coal Supply and Demand.  The supply and demand fundamentals in global coal markets were further challenged in 2015. In China, a slowing economy along with new environmental restrictions and protectionist policies aiming to support the domestic coal industry resulted in a significant decline in coal imports in 2015 according to preliminary reports.  China continues to add coal-based power generation capacity at a robust pace, but slower economic growth and/or additional regulations could continue to pressure demand in the near to intermediate term. Preliminary reports indicated that imports of metallurgical and thermal coal into China decreased by 11 and 43 million tonnes in 2015, respectively.  The decline was primarily caused by weak industrial production and protectionist measures favoring domestic supply. Conversely, India is estimated to have sustained strong demand for both thermal and metallurgical coal in 2015 due to solid economic growth and associated electric power and infrastructure projects. Europe’s weak economic growth combined with increased competition from other fuels and renewables resulted in further declines in import coal demand there. Additionally, economic uncertainties as well as the low-cost external supply of steel have pressured Europe’s domestic steel producers which has translated into lower demand for metallurgical coal.

 

The IEA publishes a World Energy Outlook (“WEO”) in which it reports on multiple scenarios. For example, the “New Policies Scenario” incorporates policies and measures affecting energy markets that have already been adopted, as well as other relevant commitments and plans that have been announced by countries, including national pledges to reduce emissions and plans to phase out fossil fuel subsidies, even if the measures to implement these commitments have yet to be identified or announced. The “Current Policies Scenario” contemplates no changes in policies from the mid-point of the year of publication, assuming that governments do not implement any commitments that have yet to be finalized by legislation and will not introduce any new policies affecting coal usage. Finally, the “450 Scenario” assumes implementation of a set of government policies consistent with a goal of limiting long-term increases in the average global temperature to two degrees Celsius, a limit determined by various governments and non-governmental organizations and recognized by nations of the world in the 2010 United Nations Climate Change Conference.

 

The IEA makes projections about world coal demand based on various future scenarios for energy development. The scenarios used by the IEA as the bases for these projections vary by time and publication. Further details are available to the public directly from the IEA, including through the IEA’s website: http://www.iea.org/publications/scenariosandprojections/. Information contained on or accessible through the IEA’s website is not incorporated by reference into this Annual Report on Form 10-K.

 

The IEA estimates in its WEO 2015, Current Policies Scenario, that worldwide primary energy demand will grow 45%, whereas the New Policies Scenario projects 32% growth, between 2013 and 2040. Demand for coal during this time period is projected to rise 43% and 12% under the Current Policies Scenario and the New Policies Scenario, respectively.

 

The IEA expects coal to retain its prominent presence as a fuel for the power sector worldwide under the Current Policies Scenario. Coal’s share of the power generation mix was 41% in 2013. By 2040, the IEA’s Current Policies Scenario estimates that coal’s fuel share of global power generation will be 38% as it continues to have the largest share of worldwide electric power production. Under the New Policies and 450 scenarios, coal’s fuel share of global power generation is projected to be 30% and 12%, respectively.

 

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Most coal consumption growth is expected to occur in Asia, with China and India as the largest consumers going forward. In the metallurgical markets, we expect somewhat modest growth in near-term steel demand based on slower economic growth. Moreover, we expect continued supply rationalization for global metallurgical coal.

 

The IEA also projects that global natural gas-fueled electricity generation will grow from 22% share in 2013 to 24% under the Current Policies scenario.  IEA’s New Policies Scenario shows gas share growing only slightly to 23% share by 2040.  However, under the 450 Scenario, natural gas share declines to 16% by 2040.  The 450 Scenario assumes the generation share from renewable sources will grown more than fivefold from 6% in 2013 to 32% by 2040.  Electricity generation from nuclear power is expected to fall from 11% to 9% under the Current Policies Scenario, while growing to 11% or 18% under the New Policies and 450 scenarios, respectively.

 

As noted above, projected coal usage is highest under the Current Policies Scenario. Future energy use consistent with the 450 Scenario would likely yield results materially lower than the projections noted above under the Current Policies Scenario or the New Policies Scenario.

 

U.S. Coal Consumption.  In the United States, coal is used primarily by power plants to generate electricity, by steel companies to produce coke for use in blast furnaces, and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing or processing facilities. Although final data are not yet available, coal consumption in the United States is estimated to be approximately 809 million tons in 2015, according to the Energy Information Administration’s (EIA) Short Term Energy Outlook. Coal consumption decreased in 2015 by 12%, or around 108 million tons.

 

According to the EIA, coal accounted for approximately 33% of U.S. electricity generation in 2015.  This is 5 percentage points lower than the same period in 2014 and represents the lowest share for coal fueled power generation in at least 60 years. This decline in domestic coal consumption was caused by a convergence of factors including record high natural gas production along with the lowest natural gas prices since 1999, coal unit retirements following the implementation of the Mercury and Air Toxics Standards regulations and growing power generation from wind and solar.

 

The following chart shows the breakdown of U.S. electricity generation by energy source for 2014 and 2015 according to the EIA:

 

 

Source:       EIA Electric Power Monthly (February 2016).

 

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Historically, coal has been considerably less expensive than natural gas or oil. However, the growth of hydraulic fracturing (fracking) combined with less-than-projected electric power demand has resulted in oversupply. Natural gas inventories at the end of 2015 were 3.6 trillion cubic feet, which was 535 Bcf (17%) above the end of 2014 and 15% above the five-year average.

 

While demand for natural gas is expected to increase in the coming years from new industrial users and exports, the current oversupply has suppressed natural gas prices to levels where coal is less competitive. As drilling for new natural gas has dropped to at least a 28-year low, EIA expects natural gas prices to increase in the coming years which we expect to improve coal’s relative competitiveness.

 

While coal’s prospects with regard to natural gas should improve, the effects of new regulations on the use of coal, particularly regarding carbon dioxide emissions and climate change impacts, are evolving. EIA’s Annual Energy Outlook forecast does not reflect the impact of carbon regulations such as the Clean Power Plan on domestic coal consumption for power generation. However, EIA has published an analysis on the effects the Clean Power Plan would have on domestic coal consumption. EIA believes that even though the regulation targets coal use in power generation, coal will maintain a critical role for power generation in the U.S.

 

Although the proposed Clean Power Plan rule results in less coal-fired electricity generation, several factors contribute to projected increases in coal generation from 2024 through 2040. Demand for electricity increases, and a combination of rising natural gas prices and increased renewable capacity translates to increased utilization at existing coal plants, even after significant amounts of coal capacity are retired. Also, in the Base Policy case, the standards set by the Clean Power Plan are assumed to remain constant after 2030. - EIA “Today in Energy,” June 10, 2015

 

Even though the validity of the Clean Power Plan is being tested by the courts, we included EIA’s analysis of the originally proposed rule as a proxy for either the Clean Power Plan or other carbon regulations.  We expect EIA will incorporate their analysis of the effects of the Clean Power Plan, which has been promulgated in 2015, in their upcoming release of the Annual Energy Outlook in April 2016.  The 2020 and 2040 values are from EIA’s analysis for the proposed Clean Power Plan published on May 22, 2015:

 

 

 

Actual

 

Estimated

 

Forecast

 

Annual
Growth

 

Sector

 

2010

 

2015

 

2016

 

2020

 

2040

 

2013 - 2040

 

 

 

(Tons, in millions)

 

 

 

Electric power

 

975

 

747

 

746

 

694

 

677

 

(0.9

)%

Other industrial

 

49

 

40

 

41

 

46

 

49

 

0.5

%

Coke plants

 

21

 

19

 

17

 

21

 

18

 

(0.7

)%

Residential/commercial

 

3

 

3

 

2

 

2

 

2

 

0.5

%

*Total U.S. coal consumption

 

1,049

 

809

 

807

 

770

 

746

 

0.2

%

 


Source:       EIA “Analysis of the Impacts of the Clean Power Plan” (May 22, 2015)

EIA Short Term Energy Outlook (February 2016)

EIA Monthly Energy Review (February 2016)

 

*                                         Columns may not total due to rounding.

 

U.S. Coal Production.  The United States is the second largest coal producer in the world, exceeded only by China. According to the EIA, there are over 200 billion tons of recoverable coal in the United States. The U.S. Department of Energy estimates that current domestic recoverable coal reserves could supply enough electricity to satisfy domestic demand for over 150 years.

 

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Coal is mined from coal fields throughout the United States, with the major production centers located in the western United States, the Appalachian region and the Interior. According to the EIA and MSHA, U.S. coal production declined an estimated 109 million tons in 2015, to 891 million tons.

 

The EIA subdivides United States coal production into three major areas: Western, Appalachia and Interior.

 

The Western area includes the Powder River Basin and the Western Bituminous region. According to the EIA, coal produced in the western United States declined from an estimated 542 million tons in 2014 to 494 million tons in 2015. The Powder River Basin is located in northeastern Wyoming and southeastern Montana and is the largest producing region in the United States. Coal from this region is sub-bituminous coal with low sulfur content ranging from 0.2% to 0.9% and heating values ranging from 8,000 to 9,500 Btu. The price of Powder River Basin coal is generally less than that of coal produced in other regions because Powder River Basin coal exists in greater abundance and is easier to mine and, thus, has a lower cost of production. The Western Bituminous region includes Colorado, Utah and southern Wyoming. Coal from this region typically has low sulfur content ranging from 0.4% to 0.8% and heating values ranging from 10,000 to 12,200 Btu.

 

The Appalachia region is further divided into north, central and southern regions. According to the EIA, coal produced in the Appalachian region fell from 268 million tons in 2014 to 228 million tons in 2015. Appalachian coal is located near the prolific eastern shale-gas producing regions. Central Appalachia is further disadvantaged for power generation because of the depletion of economically attractive reserves, permitting issues and increasing costs of production. Central Appalachia includes eastern Kentucky, Tennessee, Virginia and southern West Virginia. Coal mined from this region generally has a high heat value ranging from 11,400 to 13,200 Btu and a sulfur content ranging from 0.2% to 2.0%. Northern Appalachia includes Maryland, Ohio, Pennsylvania and northern West Virginia. Coal from this region generally has a high heat value ranging from 10,300 to 13,500 Btu and a sulfur content ranging from 0.8% to 4.0%. Southern Appalachia primarily covers Alabama and generally has a heat content ranging from 11,300 to 12,300 Btu and a sulfur content ranging from 0.7% to 3.0%.

 

The Interior region includes the Illinois Basin, Gulf Lignite production in Texas and Louisiana, and a small producing area in Kansas, Oklahoma, Missouri and Arkansas. The Illinois Basin is the largest producing region in the Interior and consists of Illinois, Indiana and western Kentucky. According to the EIA, coal produced in the Interior region fell from 189 million tons in 2014 to approximately 169 million tons in 2015. Coal from the Illinois Basin generally has a heat value ranging from 10,100 to 12,600 Btu and has a sulfur content ranging from 1.0% to 4.3%. Despite its high sulfur content, coal from the Illinois Basin can generally be used by electric power generation facilities that have installed emissions control devices, such as scrubbers.

 

U.S. Coal Exports and Imports.  Coal exports declined approximately 20 million tons to 77 million tons in 2015. The decline was primarily caused by growing global coal supply along with slowing demand growth which displaced some of the volume originating in the United States. Additionally, unfavorable foreign currency exchange disadvantaged some United States coal in certain markets. The seaborne market is cyclical, but in their New Policies Scenario the IEA projects seaborne coal trade to grow to 1.1 billion tonnes by 2020, an increase of 59 million tons from 2015 levels.

 

Historically, coal imported from abroad has represented a relatively small share of total domestic coal consumption, and this remained the case in 2015. Imports reached close to 36 million tons in 2007, but have fallen since then. According to the EIA, coal imports were 11.3 million tons in 2015. The decline is mostly attributable to more competitive pricing for domestic coal. The majority of the coal imported into the United States originates from Colombia.

 

Coal Mining Methods

 

The geological characteristics of our coal reserves largely determine the coal mining method we employ. We use two primary methods of mining coal: surface mining and underground mining.

 

Surface Mining.  We use surface mining when coal is found close to the surface. We have included the identity and location of our surface mining operations below under “—Our Mining Operations-General.” The majority of the coal we produce comes from surface mining operations.

 

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Surface mining involves removing the topsoil then drilling and blasting the overburden (earth and rock covering the coal) with explosives. We then remove the overburden with heavy earth-moving equipment, such as draglines, power shovels, excavators and loaders. Once exposed, we drill, fracture and systematically remove the coal using haul trucks or conveyors to transport the coal to a preparation plant or to a loadout facility. We reclaim disturbed areas as part of our normal mining activities. After final coal removal, we use draglines, power shovels, excavators or loaders to backfill the remaining pits with the overburden removed at the beginning of the process. Once we have replaced the overburden and topsoil, we reestablish vegetation and plant life into the natural habitat and make other improvements that have local community and environmental benefits.

 

The following diagram illustrates a typical dragline surface mining operation:

 

 

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Underground Mining.  We use underground mining methods when coal is located deep beneath the surface. We have included the identity and location of our underground mining operations below under “Our Mining Operations-General.”

 

Our underground mines are typically operated using one or both of two different mining techniques: longwall mining and room-and-pillar mining.

 

Longwall Mining.  Longwall mining involves using a mechanical shearer to extract coal from long rectangular blocks of medium to thick seams. Ultimate seam recovery using longwall mining techniques can exceed 75%. In longwall mining, continuous miners are used to develop access to these long rectangular coal blocks. Hydraulically powered supports temporarily hold up the roof of the mine while a rotating drum mechanically advances across the face of the coal seam, cutting the coal from the face. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface. Once coal is extracted from an area, the roof is allowed to collapse in a controlled fashion. The following diagram illustrates a typical underground mining operation using longwall mining techniques:

 

 

Room-and-Pillar Mining.  Room-and-pillar mining is effective for small blocks of thin coal seams. In room-and-pillar mining, a network of rooms is cut into the coal seam, leaving a series of pillars of coal to support the roof of the mine. Continuous miners are used to cut the coal and shuttle cars are used to transport the coal to a conveyor belt for further transportation to the surface. The pillars generated as part of this mining method can constitute up to 40% of the total coal in a seam. Higher seam recovery rates can be achieved if retreat mining is used. In retreat mining, coal is mined from the pillars as workers retreat. As retreat mining occurs, the roof is allowed to collapse in a controlled fashion.

 

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The following diagram illustrates our typical underground mining operation using room-and-pillar mining techniques:

 

 

Coal Preparation and Blending.  We crush the coal mined from our Powder River Basin mining complexes and ship it directly from our mines to the customer. Typically, no additional preparation is required for a saleable product. Coal extracted from some of our underground mining operations contains impurities, such as rock, shale and clay occupying a wide range of particle sizes. The majority of our mining operations in the Appalachia region use a coal preparation plant located near the mine or connected to the mine by a conveyor. These coal preparation plants allow us to treat the coal we extract from those mines to ensure a consistent quality and to enhance its suitability for particular end-users. In addition, depending on coal quality and customer requirements, we may blend coal mined from different locations, including coal produced by third parties, in order to achieve a more suitable product.

 

The treatments we employ at our preparation plants depend on the size of the raw coal. For coarse material, the separation process relies on the difference in the density between coal and waste rock and, for the very fine fractions, the separation process relies on the difference in surface chemical properties between coal and the waste minerals. To remove impurities, we crush raw coal and classify it into various sizes. For the largest size fractions, we use dense media vessel separation techniques in which we float coal in a tank containing a liquid of a pre-determined specific gravity. Since coal is lighter than its impurities, it floats, and we can separate it from rock and shale. We treat intermediate sized particles with dense medium cyclones, in which a liquid is spun at high speeds to separate coal from rock. Fine coal is treated in spirals, in which the differences in density between coal and rock allow them, when suspended in water, to be separated. Ultra fine coal is recovered in column flotation cells utilizing the differences in surface chemistry between coal and rock. By injecting stable air bubbles through a suspension of ultra fine coal and rock, the coal particles adhere to the bubbles and rise to the surface of the column where they are removed. To minimize the moisture content in coal, we process most coal sizes through centrifuges. A centrifuge spins coal very quickly, causing water accompanying the coal to separate.

 

For more information about the locations of our preparation plants, you should see the section entitled “—Our Mining Operations” below.

 

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Our Mining Operations

 

General.  At December 31, 2015, we operated, or contracted out the operation of, 13 active mines in the United States. Our reportable segments are based on the major coal producing basins in which we operate. Our reportable segments are the Powder River Basin segment, with operations in Wyoming; and the Appalachia segment, with operations in West Virginia, Kentucky, Maryland and Virginia.  We also sell coal from operations in Colorado and Illinois. Geology, coal transportation routes to consumers, regulatory environments and coal quality can vary from segment to segment.  We incorporate by reference the information about the operating results of each of our segments for the years ended December 31, 2015, 2014, and 2013  contained in Note 27 beginning on page F-52.

 

In general, we have developed our mining complexes and preparation plants at strategic locations in close proximity to rail or barge shipping facilities. Coal is transported from our mining complexes to customers by means of railroads, trucks, barge lines, and ocean-going vessels from terminal facilities. We currently own or lease under long-term arrangements a substantial portion of the equipment utilized in our mining operations. We employ sophisticated preventative maintenance and rebuild programs and upgrade our equipment to ensure that it is productive, well-maintained and cost-competitive.

 

The following map shows the locations of our active mining operations:

 

 

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The following table provides a summary of information regarding our active mining complexes as of December 31, 2015, including the total sales associated with these complexes for the years ended December 31, 2013, 2014, and 2015 and the total reserves associated with these complexes at December 31, 2015. The amount disclosed below for the total cost of property, plant and equipment of each mining complex does not include the costs of the coal reserves that we have assigned to an individual complex.

 

 

 

Captive

 

Contract

 

Mining

 

 

 

Tons Sold(2)(3)

 

Total Cost of
Property,
Plant and
Equipment at
December 31,

 

Assigned

 

Mining Complex

 

Mines(1)

 

Mines(1)

 

Equipment

 

Railroad

 

2013

 

2014

 

2015

 

2015

 

Reserves

 

 

 

 

 

 

 

 

 

 

 

(Million tons)

 

($ millions)

 

(Million tons)

 

Powder River Basin:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Black Thunder

 

S

 

 

D, S

 

UP/BN

 

100.7

 

101.2

 

99.5

 

$

1,212.5

 

1,163.9

 

Coal Creek

 

S

 

 

D, S

 

UP/BN

 

8.5

 

9.4

 

7.8

 

146.6

 

153.7

 

Other:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

West Elk

 

U

 

 

LW, CM

 

UP

 

6.1

 

6.5

 

5.1

 

417.9

 

53.5

 

Viper

 

U

 

 

CM

 

 

2.2

 

2.2

 

2.1

 

99.8

 

37.2

 

Appalachia:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coal-Mac

 

S

 

 

L, E

 

NS/CSX

 

3.1

 

2.8

 

2.4

 

205.4

 

24.6

 

Lone Mountain

 

U(3)

 

 

CM

 

NS/CSX

 

2.0

 

1.9

 

1.6

 

256.2

 

10.2

 

Mountain Laurel

 

U

 

 

L, LW, CM

 

CSX

 

2.9

 

2.6

 

2.3

 

4.1

 

 

Beckley

 

U

 

 

CM

 

CSX

 

1.1

 

1.0

 

0.9

 

 

 

Vindex

 

S

 

 

L, E

 

CSX

 

0.6

 

0.5

 

0.6

 

 

 

Sycamore No. 2

 

 

U

 

CM

 

 

0.4

 

0.5

 

0.2

 

 

 

Sentinel

 

U

 

 

CM

 

CSX

 

1.0

 

1.1

 

0.9

 

 

 

Leer

 

U

 

 

CM, LW

 

CSX

 

0

 

2.7

 

2.9

 

463.2

 

40.1

 

Totals

 

 

 

 

 

 

 

 

 

128.6

 

132.4

 

126.3

 

$

2,805.7

 

1,483.2

 

 

S = Surface mine

D = Dragline

UP = Union Pacific Railroad

U = Underground mine

L = Loader/truck

CSX = CSX Transportation

 

S = Shovel/truck

BN = Burlington Northern-Santa Fe Railway

 

E = Excavator/truck

NS = Norfolk Southern Railroad

 

LW = Longwall

 

 

CM = Continuous miner

 

 

HW = Highwall miner

 

 

 

 

 


(1)                                 Amounts in parentheses indicate the number of captive and contract mines, if more than one, at the mining complex as of December 31, 2015. Captive mines are mines that we own and operate on land owned or leased by us. Contract mines are mines that other operators mine for us under contracts on land owned or leased by us.

 

(2)                                 Tons of coal we purchased from third parties that were not processed through our loadout facilities are not included in the amounts shown in the table above.

 

(3)                                 2013 tons sold numbers do not include tons of coal sold from the following mining complexes that were sold in the 2013 calendar year: Dugout Canyon, Skyline and Sufco. We sold 5.3 million tons of coal from these mining complexes in 2013. 2013 and 2014 tons sold numbers do not include tons of coal sold from the Hazard mining complex, which was sold in 2014, or tons of coal sold from the Cumberland River mining complex, which was idled

 

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in 2014. We sold 2.7 million and 0.8 million tons of coal from these two mining complexes in 2013 and 2014, respectively.

 

Powder River Basin

 

Black Thunder.  Black Thunder is a surface mining complex located on approximately 35,800 acres in Campbell County, Wyoming. The Black Thunder complex extracts steam coal from the Upper Wyodak and Main Wyodak seams.

 

We control a significant portion of the coal reserves through federal and state leases. The Black Thunder mining complex had approximately 1.2 billion tons of proven and probable reserves at December 31, 2015. The air quality permit for the Black Thunder mine allows for the mining of coal at a rate of 190 million tons per year.  Several large tracts of coal adjacent to the Black Thunder mining complex have been nominated for lease, and other potential large areas of unleased coal remain available for nomination by us or other mining operations. The U.S. Department of Interior Bureau of Land Management, which we refer to as the BLM, will determine if the tracts will be leased and, if so, the final boundaries of, and the coal tonnage for, these tracts.

 

The Black Thunder mining complex currently consists of active pit areas and three loadout facilities. We ship all of the coal raw to our customers via the Burlington Northern Santa Fe and Union Pacific railroads. We do not process the coal mined at this complex. Each of the loadout facilities can load a 15,000-ton train in less than two hours.

 

Coal Creek.  Coal Creek is a surface mining complex located on approximately 7,400 acres in Campbell County, Wyoming. The Coal Creek mining complex extracts steam coal from the Wyodak-R1 and Wyodak-R3 seams.

 

We control a significant portion of the coal reserves through federal and state leases. The Coal Creek mining complex had approximately 153.7 million tons of proven and probable reserves at December 31, 2015. The air quality permit for the Coal Creek mine allows for the mining of coal at a rate of 50 million tons per year.

 

The Coal Creek complex currently consists of active pit areas and a loadout facility. We ship all of the coal raw to our customers via the Burlington Northern Santa Fe and Union Pacific railroads. We do not process the coal mined at this complex. The loadout facility can load a 15,000-ton train in less than three hours.

 

Appalachia

 

Coal-Mac.  Coal-Mac is a surface mining complex located on approximately 46,000 acres in Logan and Mingo Counties, West Virginia. Surface mining operations at the Coal-Mac mining complex extract steam coal primarily from the Coalburg and Stockton seams.

 

We control a significant portion of the coal reserves through private leases. The Coal-Mac mining complex had approximately 24.6 million tons of proven and probable reserves at December 31, 2015.

 

The complex currently consists of one captive surface mine, a preparation plant and two loadout facilities, which we refer to as Holden 22 and Ragland. We ship coal trucked to the Ragland loadout facility directly to our customers via the Norfolk Southern railroad. The Ragland loadout facility can load a 10,000-ton train in less than four hours. We ship coal trucked to the Holden 22 loadout facility directly to our customers via the CSX railroad. We wash all of the coal transported to the Holden 22 loadout facility at an adjacent 600-ton-per-hour preparation plant. The Holden 22 loadout facility can load a 10,000-ton train in about four hours.

 

Lone Mountain.  Lone Mountain is an underground mining complex located on approximately 54,000 acres in Harlan County, Kentucky and Lee County, Virginia. The Lone Mountain mining complex extracts steam and metallurgical coal from the Kellioka, Darby and Owl seams.

 

We control a significant portion of the coal reserves through private leases. The Lone Mountain mining complex had approximately 10.2 million tons of proven and probable reserves at December 31, 2015.

 

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The complex currently consists of three underground mines operating a total of six continuous miner sections. We process coal through a 1,200-ton-per-hour preparation plant. We then ship the coal to our customers via the Norfolk Southern or CSX railroad.

 

Mountain Laurel.  Mountain Laurel is an underground and surface mining complex located on approximately 38,200 acres in Logan County and Boone County, West Virginia. Underground mining operations at the Mountain Laurel mining complex extract steam and metallurgical coal from the Cedar Grove and Alma seams. Surface mining operations at the Mountain Laurel mining complex extract coal from a number of different splits of the Five Block, Stockton and Coalburg seams.

 

The complex currently consists of one underground mine operating a longwall and one continuous miner sections, a preparation plant and a loadout facility. We process most of the coal through a 2,100-ton-per-hour preparation plant before shipping the coal to our customers via the CSX railroad. The loadout facility can load a 15,000-ton train in less than four hours.

 

Beckley.  The Beckley mining complex is located on approximately 15,400 acres in Raleigh County, West Virginia. Beckley is extracting high quality, low-volatile metallurgical coal in the Pocahontas No. 3 seam.

 

Coal is belted from the mine to a 600-ton-per-hour preparation plant before shipping the coal via the CSX railroad. The loadout facility can load a 10,000-ton train in less than four hours.

 

Vindex.  The Vindex mining complex consists of a surface mine located on approximately 40,300 acres in Maryland and West Virginia. Mining operations extract coal from the Upper Freeport, Middle Kittanning, Pittsburgh, Little Pittsburgh and Redstone seams. Coal is sold on a raw basis and trucked directly to the customer.  This operation had been idled effective March 1, 2016 and is currently in reclamation.

 

Sentinel.  The Sentinel mining complex consists of one underground mine, a preparation plant and a loadout facility located on approximately 25,600 acres in Barbour County, West Virginia. Mining operations currently extract coal from the Clarion coal seam. Coal from the Sentinel mining complex is processed through the preparation plant and shipped by CSX rail to customers.

 

Leer.  The Leer Complex, located in Taylor County, West Virginia, includes approximately 40.1 million tons of coal reserves as of December 31, 2015 and has both steam and metallurgical quality coal in the Lower Kittanning seam, and is part of approximately 79,400 acres that is considered our Tygart Valley area. Substantially all of the reserves at Leer are owned rather than leased from third parties.

 

The Leer Complex is designed to have 3.5 million tons of capacity per year of high quality coal that is well suited to both the high volatile metallurgical and utility markets. All the production is processed through a 1,400 ton-per-hour preparation plant and loaded on the CSX railroad. A 15,000-ton train can be loaded in less than four hours. Without the addition of more coal reserves, the current reserves could sustain the longwall mine at current production levels until about 2029 and support continuous miner production until 2035.

 

Other

 

West Elk.  West Elk is an underground mining complex located on approximately 17,800 acres in Gunnison County, Colorado. The West Elk mining complex extracts steam coal from the E seam.

 

We control a significant portion of the coal reserves through federal and state leases. The West Elk mining complex had approximately 53.5 million tons of proven and probable reserves at December 31, 2015.

 

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The West Elk complex currently consists of a longwall, continuous miner sections and a loadout facility. We ship most of the coal raw to our customers via the Union Pacific railroad. The loadout facility can load an 11,000-ton train in less than three hours.

 

Viper.  The Viper mining complex consists of one underground coal mine and a preparation plant located on approximately 46,500 acres in central Illinois near the city of Springfield. Mining operations extract steam coal from the Illinois No. 5 seam, also referred to as the Springfield seam. All coal is processed through an 800 ton-per-hour preparation plant and shipped to customers by on-highway trucks.

 

We control a significant portion of the coal reserves through private leases. As of December 31, 2015, we had approximately 37.2 million tons of proven and probable reserves.

 

Sales, Marketing and Trading

 

Overview.  Coal prices are influenced by a number of factors and can vary materially by region. The price of coal within a region is influenced by market conditions, coal quality, transportation costs involved in moving coal from the mine to the point of use and mine operating costs. For example, higher carbon and lower ash content generally result in higher prices, and higher sulfur and higher ash content generally result in lower prices within a given geographic region.

 

The cost of coal at the mine is also influenced by geologic characteristics such as seam thickness, overburden ratios and depth of underground reserves. It is generally less expensive to mine coal seams that are thick and located close to the surface than to mine thin underground seams. Within a particular geographic region, underground mining, which is the primary mining method we use in certain of our Appalachian mines, is generally more expensive than surface mining, which is the mining method we use in the Powder River Basin, and for certain of our Appalachian mines. This is the case because of the higher capital costs, including costs for construction of extensive ventilation systems, and higher per unit labor costs due to lower productivity associated with underground mining.

 

Our sales, marketing and trading functions are principally based in St. Louis, Missouri and consist of sales and trading, transportation and distribution, quality control and contract administration personnel as well as revenue management. We also have smaller groups of sales personnel in our Singapore and London offices. In addition to selling coal produced in our mining complexes, from time to time we purchase and sell coal mined by others, some of which we blend with coal produced from our mines. We focus on meeting the needs and specifications of our customers rather than just selling our coal production.

 

Customers.  The Company markets its steam and metallurgical coal to domestic and foreign utilities, steel producers and other industrial facilities. For the year ended December 31, 2015, we derived approximately 18% of our total coal revenues from sales to our three largest customers U.S. Steel, Southern Company and Tennessee Valley Authority - and approximately 39% of our total coal revenues from sales to our 10 largest customers.

 

In 2015, we sold coal to domestic customers located in 36 different states. The locations of our mines enable us to ship coal to most of the major coal-fueled power plants in the United States.

 

In addition, in 2015 we also exported coal to Europe, Asia, North America (outside the United States) and South America. Exports to foreign countries were $0.4 billion, $0.6 billion and $0.8 billion for the years ended December 31, 2015,  2014 and 2013, respectively. As of December 31, 2015 and 2014, trade receivables related to metallurgical-quality coal sales totaled $32.8 million and $76.0 million, respectively, or 28% of total trade receivables. We do not have foreign currency exposure for our international sales as all sales are denominated and settled in U.S. dollars.

 

The Company’s foreign revenues by coal shipment destination for the year ended December 31, 2015, were as follows:

 

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(In thousands)

 

 

 

Europe

 

$

170,314

 

Asia

 

96,523

 

Central and South America

 

55,323

 

North America

 

40,315

 

Brokered Sales

 

32,848

 

Total

 

$

395,323

 

 

Long-Term Coal Supply Arrangements

 

As is customary in the coal industry, we enter into fixed price, fixed volume long-term supply contracts, the terms of which are more than one year, with many of our customers. Multiple year contracts usually have specific and possibly different volume and pricing arrangements for each year of the contract. Long-term contracts allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. In 2015, we sold approximately 68% of our coal under long-term supply arrangements. The majority of our supply contracts include a fixed price for the term of the agreement or a pre-determined escalation in price for each year. Some of our long-term supply agreements may include a variable pricing system. While most of our sales contracts are for terms of one to five years, some are as short as one month and other contracts have terms exceeding five years. At December 31, 2015, the average volume-weighted remaining term of our long-term contracts was approximately 2.12 years, with remaining terms ranging from one to P5Y years. At December 31, 2015, remaining tons under long-term supply agreements, including those subject to price re-opener or extension provisions, were approximately 144 million tons.

 

We typically sell coal to customers under long-term arrangements through a “request-for-proposal” process. The terms of our coal sales agreements result from competitive bidding and 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, future regulatory changes, extension options, force majeure, termination, damages and assignment provisions. Our long-term supply contracts typically contain provisions to adjust the base price due to new statutes, ordinances or regulations. Additionally, some of our contracts contain provisions that allow for the recovery of costs affected by modifications or changes in the interpretations or application of any applicable statute by local, state or federal government authorities. These provisions only apply to the base price of coal contained in these supply contracts. In some circumstances, a significant adjustment in base price can lead to termination of the contract.

 

Certain of our contracts contain index provisions that change the price based on changes in market based indices or changes in economic indices or both. Certain of our contracts contain price re-opener provisions that may allow a 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 within a specified range of prices. In a limited number of agreements, if the parties do not agree on a new price, either party has an option to terminate the contract. In addition, certain of our contracts contain clauses that may allow customers to terminate the contract in the event of certain changes in environmental laws and regulations that impact their operations.

 

Coal quality and volumes are stipulated in coal sales agreements. In most cases, the annual pricing and volume obligations are fixed, although in some cases the volume specified may vary depending on the customer consumption requirements. Most of our coal sales agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content (for thermal coal contracts), volatile matter (for metallurgical coal contracts), and for both types of contracts, sulfur, ash and moisture content. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts.

 

Our coal sales agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers, during the duration of events beyond the control of the affected party, including events such as strikes, adverse mining conditions, mine closures or serious transportation problems that affect us or unanticipated plant outages that may affect the buyer. Our contracts also generally provide that in the event a force majeure circumstance exceeds a

 

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certain time period, the unaffected party may have the option to terminate the purchase or sale in whole or in part. Some contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer. Agreements between our customers and the railroads servicing our mines may also contain force majeure provisions.

 

In most of our contracts, we have a right of substitution (unilateral or subject to counterparty approval), 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 equivalent delivered cost.

 

In some of our coal supply contracts, we agree to indemnify or reimburse our customers for damage to their or their rail carrier’s equipment while on our property, which result from our or our agents’ negligence, and for damage to our customer’s equipment due to non-coal materials being included with our coal while on our property.

 

Trading.  In addition to marketing and selling coal to customers through traditional coal supply arrangements, we seek to optimize our coal production and leverage our knowledge of the coal industry through a variety of other marketing, trading and asset optimization strategies. From time to time, we may employ strategies to use coal and coal-related commodities and contracts for those commodities in order to manage and hedge volumes and/or prices associated with our coal sales or purchase commitments, reduce our exposure to the volatility of market prices or augment the value of our portfolio of traditional assets. These strategies may include physical coal contracts, as well as a variety of forward, futures or options contracts, swap agreements or other financial instruments.

 

We maintain a system of complementary processes and controls designed to monitor and manage our exposure to market and other risks that may arise as a consequence of these strategies. These processes and controls seek to preserve our ability to profit from certain marketing, trading and asset optimization strategies while mitigating our exposure to potential losses. You should see Item 7A, entitled “Quantitative and Qualitative Disclosures About Market Risk” for more information about the market risks associated with these strategies at December 31, 2015.

 

Transportation.  We ship our coal to domestic customers by means of railcars, barges, vessels or trucks, or a combination of these means of transportation. We generally sell coal used for domestic consumption free on board (f.o.b.) at the mine or nearest loading facility. Our domestic customers normally bear the costs of transporting coal by rail, barge or vessel.

 

Historically, most domestic electricity generators have arranged long-term shipping contracts with rail or barge companies to assure stable delivery costs. Transportation can be a large component of a purchaser’s total cost. Although the purchaser pays the freight, transportation costs still are important to coal mining companies because the purchaser may choose a supplier largely based on cost of transportation. Transportation costs borne by the customer vary greatly based on each customer’s proximity to the mine and our proximity to the loadout facilities. Trucks and overland conveyors haul coal over shorter distances, while barges, Great Lake carriers and ocean vessels move coal to export markets and domestic markets requiring shipment over the Great Lakes and several river systems.

 

Most coal mines are served by a single rail company, but much of the Powder River Basin is served by two rail carriers: the Burlington Northern-Santa Fe railroad and the Union Pacific railroad. We generally transport coal produced at our Appalachian mining complexes via the CSX railroad or the Norfolk Southern railroad. Besides rail deliveries, some customers in the eastern United States rely on a river barge system.

 

We generally sell coal to international customers at the export terminal, and we are usually responsible for the cost of transporting coal to the export terminals. In some cases we may enter into long-term throughput agreements with export terminals that contain minimum throughput obligations. In the event we do not meet those minimum thresholds, we may be obligated to pay liquidated damage amounts to such terminals. We transport our coal to Atlantic coast terminals or terminals along the Gulf of Mexico for transportation to international customers. Our international customers are generally responsible for paying the cost of ocean freight. We may also sell coal to international customers delivered to an unloading facility at the destination country.

 

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We own a 22% interest in Dominion Terminal Associates, a partnership that operates a ground storage-to-vessel coal transloading facility in Newport News, Virginia. The facility has a rated throughput capacity of 20 million tons of coal per year and ground storage capacity of approximately 1.7 million tons. The facility serves international customers, as well as domestic coal users located along the Atlantic coast of the United States.

 

We also own a 38% interest in Millennium Bulk Terminals-Longview, LLC (MBT), the owner of a bulk commodity terminal on the Columbia River near Longview, Washington. MBT is currently working to obtain the required approvals and necessary permits to complete upgrades to enable coal shipments through the brownfield terminal.

 

Competition

 

The coal industry is intensely competitive. The most important factors on which we compete are coal quality, delivered costs to the customer and reliability of supply. Our principal domestic competitors include Alpha Natural Resources, Inc., Cloud Peak Energy, CONSOL Energy Inc. and Peabody Energy Corp. Some of these coal producers are larger than we are and have greater financial resources and larger reserve bases than we do. We also compete directly with a number of smaller producers in each of the geographic regions in which we operate, as well as companies that produce coal from one or more foreign countries, such as Australia, Colombia, Indonesia and South Africa.

 

Additionally, coal competes with other fuels, such as natural gas, nuclear energy, hydropower, wind, solar and petroleum, for steam and electrical power generation. Costs and other factors relating to these alternative fuels, such as safety and environmental considerations, affect the overall demand for coal as a fuel.

 

Suppliers

 

Principal supplies used in our business include petroleum-based fuels, explosives, tires, steel and other raw materials as well as spare parts and other consumables used in the mining process. We use third-party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services and construction. We use sole source suppliers for certain parts of our business such as explosives and fuel, and preferred suppliers for other parts of our business such as dragline and shovel parts and related services. We believe adequate substitute suppliers are available. For more information about our suppliers, you should see Item 1A, “Risk Factors-Increases in the costs of mining and other industrial supplies, including steel-based supplies, diesel fuel and rubber tires, or the inability to obtain a sufficient quantity of those supplies, could negatively affect our operating costs or disrupt or delay our production.”

 

Environmental and Other Regulatory Matters

 

Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety and the environment, including the protection of air quality, water quality, wetlands, special status species of plants and animals, land uses, cultural and historic properties and other environmental resources identified during the permitting process. Reclamation is required during production and after mining has been completed. Materials used and generated by mining operations must also be managed according to applicable regulations and law. These laws have, and will continue to have, a significant effect on our production costs and our competitive position.

 

We endeavor to conduct our mining operations in compliance with applicable federal, state and local laws and regulations. However, due in part to the extensive, comprehensive and changing regulatory requirements, violations during mining operations occur from time to time. We cannot assure you that we have been or will be at all times in complete compliance with such laws and regulations. While it is not possible to accurately quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. Federal and state mining laws and regulations require us to obtain surety bonds to guarantee performance or payment of certain long-term obligations, including mine closure and reclamation costs, federal and state workers’ compensation benefits, coal

 

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leases and other miscellaneous obligations. Compliance with these laws has substantially increased the cost of coal mining for domestic coal producers.

 

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

 

The following is a summary of the various federal and state environmental and similar regulations that have a material impact on our business:

 

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 to federal, state or local authorities data pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment. For example, in order to obtain a federal coal lease, an environmental impact statement must be prepared to assist the BLM in determining the potential environmental impact of lease issuance, including any collateral effects from the mining, transportation and burning of coal, which may in some cases include a review of impacts on climate change. The authorization, permitting and implementation requirements imposed by federal, state and local authorities may be costly and time consuming and may delay commencement or continuation of mining operations. In the states where we operate, the applicable laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if officers, directors, shareholders with specified interests or certain other affiliated entities with specified interests in the applicant or permittee have, or are affiliated with another entity that has, outstanding permit violations. Thus, past or ongoing violations of applicable laws and regulations could provide a basis to revoke existing permits and to deny the issuance of additional permits.

 

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

 

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

 

Surface Mining Control and Reclamation Act.  The Surface Mining Control and Reclamation Act, which we refer to as SMCRA, establishes mining, environmental protection, reclamation and closure standards for all aspects of surface mining as well as many aspects of underground mining. Mining operators must obtain SMCRA permits and permit renewals from the Office of Surface Mining, which we refer to as OSM, or from the applicable state agency if the state agency has obtained regulatory primacy. A state agency may achieve primacy if the state regulatory agency develops a mining regulatory program that is no less stringent than the federal mining regulatory program under SMCRA. All states in which we conduct mining operations have achieved primacy and issue permits in lieu of OSM.

 

In 1999, a federal court in West Virginia ruled that the stream buffer zone rule issued under SMCRA prohibited most excess spoil fills. While the decision was later reversed on jurisdictional grounds, the extent to which the rule applied to fills was left unaddressed. On December 12, 2008, OSM finalized a rulemaking regarding the interpretation of the stream buffer zone provisions of SMCRA which confirmed that excess spoil from mining and refuse from coal preparation could be placed in permitted areas of a mine site that constitute waters of the United States. That rule, however, was subject to a challenge in federal court. In addition, on November 30, 2009, OSM announced that it would re-examine and reinterpret the regulations finalized eleven months earlier. On February 20, 2014, the federal court vacated the 2008 rule. On December 22, 2014, OSM

 

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published the final revisions to the stream buffer zone rule in the Federal Register. The revisions reinstate the previous version of the rule, but do not announce a new interpretation of the rule regarding the ability to construct excess spoil fills. We cannot predict how the regulations will be applied or how they may affect coal production, though there are reports that any reinterpretation of the prior version of the rule would be to restrict the ability to construct mining related structures in streams. Such an interpretation could curtail surface mining operations in and near streams-especially in central Appalachia.

 

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; subsidence control for underground mines; surface runoff and drainage control; establishment of suitable post mining land uses; and revegetation. 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 includes surveys and/or assessments of the following: cultural and historical resources; geology; soils; vegetation; aquatic organisms; wildlife; potential for threatened, endangered or other special status species; surface and ground water hydrology; climatology; riverine and riparian habitat; and wetlands. The geologic data and information derived from the other surveys and/or assessments are used to develop the mining and reclamation plans presented in the permit application. The mining and reclamation plans address the provisions and performance standards of the state’s equivalent SMCRA regulatory program, and are also used to support applications for other authorizations and/or permits required to conduct coal mining activities. Also included in the permit application is information used for documenting surface and mineral ownership, variance requests, access roads, bonding information, mining methods, mining phases, other agreements that may relate to coal, other minerals, oil and gas rights, water rights, permitted areas, and ownership and control information required to determine compliance with OSM’s Applicant Violator System, including the mining and compliance history of officers, directors and principal owners of the entity.

 

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

 

In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund, which was created by SMCRA, requires 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 and $0.12 per ton of coal produced from underground mines. In 2015, we recorded $32.7 million of expense related to these reclamation fees.

 

Surety Bonds.  Mine operators are often required by federal and/or state laws, including SMCRA, to assure, usually through the use of surety bonds, payment of certain long-term obligations including mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other miscellaneous obligations. Although surety bonds are usually noncancelable during their term, many of these bonds are renewable on an annual basis.  Please see “Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal, and a loss or reduction in our ability to self-bond could have a material adverse effect on our business and results of operations,” contained under the heading Risk Factors—Risks related to Our Operations for a discussion of certain risks associated with our surety bonds.

 

The costs of these bonds have fluctuated in recent years while the market terms of surety bonds have generally become more unfavorable to mine operators. These changes in the terms of the bonds have been accompanied at times by a

 

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decrease in the number of companies willing to issue surety bonds. In order to address some of these uncertainties, we use self-bonding to secure performance of certain obligations in Wyoming. As of December 31, 2015, we have self-bonded an aggregate of approximately $485.5 million, posted an aggregate of approximately $188.0 million in surety bonds for reclamation purposes and secured $49.2 million in letters of credit and cash for reclamation bonding obligations. In addition, we had approximately $212.0 million of surety bonds, cash and letters of credit outstanding at December 31, 2015 to secure workers’ compensation, coal lease and other obligations.

 

For additional information, please see “Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations, and, therefore, our ability to mine or lease coal, and a loss or reduction in our ability to self-bond could have a material, adverse effect on our business and results of operations,” contained in Item 1A, “Risk Factors—Risk Related to Our Operations,” for a discussion of certain risks associated with our surety bonds.

 

Mine Safety and Health.  Stringent safety and health standards have been imposed by federal legislation since Congress adopted the Mine Safety and Health Act of 1969. The Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed comprehensive 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 programs aimed at improving mine safety and health. Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive and pervasive systems for the protection of employee health and safety affecting any segment of U.S. industry. In reaction to recent mine accidents, federal and state legislatures and regulatory authorities have increased scrutiny of mine safety matters and passed more stringent laws governing mining. For example, in 2006, Congress enacted the MINER Act. The MINER Act imposes additional obligations on coal operators including, among other things, the following:

 

·                  development of new emergency response plans that address post-accident communications, tracking of miners, breathable air, lifelines, training and communication with local emergency response personnel;

·                  establishment of additional requirements for mine rescue teams;

·                  notification of federal authorities in the event of certain events;

·                  increased penalties for violations of the applicable federal laws and regulations; and

·                  requirement that standards be implemented regarding the manner in which closed areas of underground mines are sealed.

 

In 2008, the U.S. House of Representatives approved additional federal legislation which would have required new regulations on a variety of mine safety issues such as underground refuges, mine ventilation and communication systems. Although the U.S. Senate failed to pass that legislation, it is possible that similar legislation may be proposed in the future. Various states, including West Virginia, have also enacted laws to address many of the same subjects. The costs of implementing these safety and health regulations at the federal and state level have been, and will continue to be, substantial. In addition to the cost of implementation, there are increased penalties for violations which may also be substantial. Expanded enforcement has resulted in a proliferation of litigation regarding citations and orders issued as a result of the regulations.

 

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on production of up to $1.10 per ton for coal mined in underground operations and up to $0.55 per ton for coal mined in surface operations. These amounts may not exceed 4.4% of the gross sales price. This excise tax does not apply to coal shipped outside the United States. In 2015, we recorded $66.1 million of expense related to this excise tax.

 

Clean Air Act.  The federal Clean Air Act and similar state and local laws that regulate air emissions affect coal mining directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emissions control requirements relating to particulate matter which may include controlling fugitive dust. The Clean Air Act also indirectly affects coal mining operations, for example, by extensively regulating the emissions of fine particulate matter measuring 2.5 micrometers in diameter or smaller, sulfur dioxide, nitrogen oxides, mercury and other compounds

 

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emitted by coal-fueled power plants and industrial boilers, which are the largest end-users of our coal. Continued tightening of the already stringent regulation of emissions is likely, such as the Mercury and Air Toxics Standard (MATS), finalized in 2011 and discussed in more detail below. In addition, the U.S. Environmental Protection Agency, which we refer to as EPA, has issued regulations on additional emissions, such as greenhouse gases (GHG), from new, modified, reconstructed and existing electric generating units, including coal-fired plants.  Other GHG regulations apply to industrial boilers (see discussion of Climate Change, below).  These regulations could eventually reduce the demand for coal.

 

Clean Air Act requirements that may directly or indirectly affect our operations include the following:

 

·                  Acid Rain.  Title IV of the Clean Air Act, promulgated in 1990, imposed a two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and applies to all coal-fueled power plants with a capacity of more than 25-megawatts. Generally, the affected power plants have sought to comply with these requirements by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading sulfur dioxide emissions allowances. Although we cannot accurately predict the future effect of this Clean Air Act provision on our operations, we believe that implementation of Phase II has been factored into the pricing of the coal market.

 

·                  Particulate Matter.  The Clean Air Act requires the EPA to set national ambient air quality standards, which we refer to as NAAQS, for certain pollutants associated with the combustion of coal, including sulfur dioxide, particulate matter, nitrogen oxides and ozone. Areas that are not in compliance with these standards, referred to as non-attainment areas, must take steps to reduce emissions levels. For example, NAAQS currently exist for particulate matter measuring 10 micrometers in diameter or smaller (PM10) and for fine particulate matter measuring 2.5 micrometers in diameter or smaller (PM2.5), and the EPA revised the PM2.5 NAAQS on December 14, 2012, making it more stringent. The states were required to make recommendations on nonattainment designations for the new NAAQS in late 2013. EPA issued final designations for most areas of the country in 2012 and made some revisions in 2015.  Individual states must now identify the sources of emissions and develop emission reduction plans. These plans may be state-specific or regional in scope. Under the Clean Air Act, individual states have up to 12 years from the date of designation to secure emissions reductions from sources contributing to the problem. Future regulation and enforcement of the new PM2.5 standard, as well as future revisions of PM standards, will affect many power plants, especially coal-fueled power plants, and all plants in non-attainment areas.

 

·                  Ozone.  On October 26, 2015, the EPA published a final rule revising the existing primary and secondary NAAQS for ozone, reducing them to 70ppb on an 8-hour average.  EPA has yet to make attainment designations for states on this new standard, but significant additional emission control expenditures will likely be required at certain coal-fueled power plants to meet the new stricter NAAQS. Nitrogen oxides, which are a byproduct of coal combustion, are classified as an ozone precursor. As a result, emissions control requirements for new and expanded coal-fueled power plants and industrial boilers will continue to become more demanding in the years ahead.  The new standard is subject to pending judicial challenge.

 

·                  NOx SIP Call.  The Nitrogen Oxides State Implementation Plan (NOx SIP) Call program was established by the EPA in October 1998 to reduce the transport of ozone on prevailing winds from the Midwest and South to states in the Northeast, which said that they could not meet federal air quality standards because of migrating pollution. The program was designed to reduce nitrous oxide emissions by one million tons per year in 22 eastern states and the District of Columbia. Phase II reductions were required by May 2007. As a result of the program, many power plants were required to install additional emission control measures, such as selective catalytic reduction devices. Installation of additional emission control measures has made it more costly to operate coal-fueled power plants, which could make coal a less attractive fuel.

 

·                  Interstate Transport.  The EPA finalized the Clean Air Interstate Rule, which we refer to as CAIR, in March 2005. CAIR called for power plants in 28 Eastern states and the District of Columbia to reduce emission levels of sulfur

 

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dioxide and nitrous oxide, which could lead to non-attainment of PM2.5 and ozone NAAQS in downwind states (interstate transport), pursuant to a cap and trade program similar to the system now in effect for acid deposition control.  In July 2008, in State of North Carolina v. EPA and consolidated cases, the U.S. Court of Appeals for the District of Columbia Circuit disagreed with the EPA’s reading of the Clean Air Act and vacated CAIR in its entirety. In December 2008, the U.S. Court of Appeals for the District of Columbia Circuit revised its remedy and remanded the rule to the EPA. The EPA proposed a revised transport rule on August 2, 2010 (75 Fed. Reg. 45209) to address attainment of the 1997 ozone NAAQS and the 2006 PM2.5 NAAQS.  The rule was finalized as the Cross State Air Pollution Rule (CSAPR) on July 6, 2011, with compliance required for SO2 reductions beginning January 1, 2012 and compliance with NOx reductions required by May 1, 2012. Numerous appeals of the rule were filed and, on August 21, 2012, the Federal Court of Appeals for the District of Columbia Circuit vacated the rule, leaving the EPA to continue implementation of the CAIR. Controls required under the CAIR, especially in conjunction with other rules may have affected the market for coal inasmuch as multiple existing coal fired units were being retired rather than having required controls installed. The U.S. Supreme Court agreed to hear the EPA’s appeal of the decision vacating CSAPR and on April 29, 2014, issued an opinion reversing the August 21, 2012 District of Columbia Circuit decision, remanding the case back to the District of Columbia Circuit. The EPA then requested that the court lift the CSAPR stay and toll the CSAPR compliance deadlines by three years. On October 23, 2014, the District of Columbia Circuit granted the EPA’s request, and that court later dismissed all pending challenges to the rule on July 28, 2015 but it remanded some state budgets to EPA for further consideration.  CSAPR Phase 1 implementation began in 2015, with Phase 2 beginning in 2017.  CSAPR generally requires greater reductions that under CAIR.  As a result, some coal-fired power plants will be required to install costly pollution controls or shut down which may adversely affect the demand for coal.  Finally, in November 2015, EPA proposed an update to the CSAPR to address interstate transport of air pollution under the more recent 2008 ozone NAAQS and the state budgets remanded by the D.C. Circuit.  EPA received public comment on the rule in January 2016 and will issue a final rule in the near future.  It is likely the final rule will increase the pressure to install controls or shut down units, which may further adversely affect the demand for coal.

 

·                  Mercury.  In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the EPA’s Clean Air Mercury Rule (CAMR) and remanded it to the EPA for reconsideration. In response, the EPA announced an Electric Generating Unit (EGU) Mercury and Air Toxics Standard (MATS) on December 16, 2011. The MATS was finalized April 16, 2012, and required compliance for most plants by 2015.  In addition, before the court decision vacating the CAMR, some states had either adopted the CAMR or adopted state-specific rules to regulate mercury emissions from power plants that are more stringent than the CAMR.  MATS compliance, coupled with state mercury and air toxics laws and other factors have required many plants to install costly controls, re-fire with natural gas or to retire, which may adversely affect the demand for coal.  MATS was challenged in the D.C. Circuit, which upheld the rule on April 15, 2013.  Petitioners successfully obtained Supreme Court review, and on June 29, 2015, the Supreme Court issued a 5-4 decision striking down the final rule based on EPA’s failure to consider economic costs in determining whether to regulate.  The case was remanded to the D.C. Circuit.  EPA began reconsideration of costs, proposing to re-issue the final rule in April 2016 based on a finding that those costs still justified regulation, and successfully secured an order from the D.C. Circuit to keep the rule in effect while it completed its rulemaking.  Petitioners unsuccessfully sought a stay of the rule in the Supreme Court in February 2016.  Therefore, the rule remains in effect until further order of the D.C. Circuit, which will likely hear challenges to EPA’s re-issuance of the rule based on its new cost considerations. Hence, MATS will likely continue to impact coal-fueled generation as discussed above for at least the near term, and possibly well into the future.

 

·                  Regional Haze.  The EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks, particularly those located in the southwest and southeast United States. Under the Regional Haze Rule, affected states were required to submit regional haze SIPs by December 17, 2007, that, among other things, were to identify facilities that would have to reduce emissions and comply with stricter emission limitations. The vast majority of states failed to submit their

 

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plans by December 17, 2007, and the EPA issued a Finding of Failure to Submit plans on January 15, 2009 (74 Fed. Reg. 2392). The EPA had taken no enforcement action against states to finalize implementation plans and was slowly dealing with the state Regional Haze SIPs that were submitted, which resulted in the National Parks Conservation Association commencing litigation in the D.C. Circuit Court of Appeals on August 3, 2012, against the EPA for failure to enforce the rule (National Parks Conservation Act v. EPA, D.C. Cir). Industry groups, including the Utility Air Regulatory Group have intervened (Utility Air Regulatory Group v. EPA. D.C. Cir 12-1342, 8/6/2012).  EPA ultimately agreed in a consent decree with environmental groups to impose regional haze federal implementation plans (FIPs) or to take action on regional haze SIPs before the agency for 42 states and the District of Columbia.  EPA has completed those actions for all but several states in its first planning period (2008-2010).  In many eastern states, EPA has allowed states to meet “best available control technology” (BART) requirements for power plants through compliance with CAIR and CSAPR (a policy under pending litigation).  Other states have had BART imposed on a case-by-case basis, and where EPA found SIPs deficient, it disapproved them and issued FIPs.  It is possible that EPA may continue to increase the stringency of control requirements imposed under the Regina Haze Program as it moves toward the next planning period.  This program may result in additional emissions restrictions from new coal-fueled power plants whose operations may impair visibility at and around federally protected areas. This program may also require certain existing coal-fueled power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could affect the future market for coal.

 

·                  New Source Review.  A number of pending regulatory changes and court actions are affecting the scope of the EPA’s new source review program, which under certain circumstances requires existing coal-fueled power plants to install the more stringent air emissions control equipment required of new plants. The new source review program is continually revised and such revisions may impact demand for coal nationally, but we are unable to predict the magnitude of the impact.

 

Climate Change.  Carbon dioxide, which is considered to be a greenhouse gas, is a by-product of burning coal. Global climate issues, including with respect to greenhouse gases such as carbon dioxide and the relationship that greenhouse gases may have with perceived global warning, continue to attract significant public and scientific attention. For example, the Fourth and Fifth Assessment Reports of the Intergovernmental Panel on Climate Change have expressed concern about the impacts of human activity, especially from fossil fuel combustion, on global climate issues. As a result of the public and scientific attention, several governmental bodies increasingly are focusing on global climate issues and, more specifically, levels of emissions of carbon dioxide from coal combustion by power plants. Future regulation of greenhouse gas emissions in the United States could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes and the federal, state or local level or otherwise.

 

Demand for coal also may be impacted by international efforts to reduce emissions from greenhouse gases. For example, in December 2015, representatives of 195 nations reached a landmark climate accord that will, for the first time, commit participating countries to lowering greenhouse gas emissions. Further, the United States and a number of international development banks, such as the World Bank, the European Investment Bank and European Bank for Reconstruction and Development, have announced that they will no longer provide financing for the development of new coal-fueled power plants, subject to very narrow exceptions.

 

Although the U.S. Congress has considered various legislative proposals that would address global climate issues and greenhouse gas emissions, no such federal proposals have been adopted into law to date. In the absence of U.S. federal legislation on these topics, the U.S. Environmental Protection Agency (the “EPA”) has been the primary source of federal oversight, although future regulation of greenhouse gases and global climate matters in the United States could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act, federal adoption of a greenhouse gas regulatory scheme or otherwise.

 

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In 2007, the U.S. Supreme Court held that the EPA has authority under the Clean Air Act to regulate carbon dioxide emissions from automobiles and can decide against regulation only if the EPA determines that carbon dioxide does not significantly contribute to climate change and does not endanger public health or the environment. Although the Supreme Court’s holding did not expressly involve the EPA’s authority to regulate greenhouse gas emissions from stationary sources, such as coal-fueled power plants, the EPA since has determined on its own that it has the authority to regulate greenhouse gas emissions from power plants, and the EPA has published a formal determination that six greenhouse gases, including carbon dioxide, endanger both the public health and welfare of current and future generations.

 

In 2014, the EPA proposed a sweeping rule, known as the “Clean Power Plan,” to cut carbon emissions from existing electric generating units, including coal-fired power plants. A final version of the Clean Power Plan was adopted in August 2015. The final version of the Clean Power Plan aims to reduce carbon dioxide emissions from electrical power generation by 32% within 15 years relative to 2005 levels through reduction of emissions from coal-burning power plants and increased use of renewable energy and energy conservation methods. Under the Clean Power Plan, states are free to reduce emissions by various means and must submit emissions reduction plans to the EPA by September 2016 or, with an approved extension, September 2018. If a state has not submitted a plan by then, the Clean Power Plan authorizes the EPA to impose its own plan on that state. In order to determine a state’s goal, the EPA has divided the country into three regions based on connected regional electricity grids. States are to implement their plans by focusing on (i) increasing the generation efficiency of existing fossil fuel plants, (ii) substituting lower carbon dioxide emitting natural gas generation for coal-powered generation and (iii) substituting generation from new zero carbon dioxide emitting renewable sources for fossil fuel powered generation. States are permitted to use regionally available low carbon generation sources when substituting for in-state coal generation and coordinate with other states to develop multi-state plans. Following the adoption, 27 states sued the EPA, claiming that the EPA overstepped its legal authority in adopting the Clean Power Plan. In February 2016, the U.S. Supreme Court ordered the EPA to halt enforcement of the Clean Power Plan until a lower court rules on the lawsuit and until the Supreme Court determines whether or not to hear the case.  If the Supreme Court does decide to hear the case, then the stay would remain in effect until the Supreme Court rules.  If the Clean Power Plan ultimately is upheld in its current form, it is projected to significantly curtail the construction of new coal-fired power plants and have a materially adverse impact on the demand for coal nationally.

 

Several U.S. states have enacted legislation establishing greenhouse gas emissions reduction goals or requirements or joined regional greenhouse gas reduction initiatives. Some states also have enacted legislation or regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources. For example, nine northeastern states currently are members of the Regional Greenhouse Gas Initiative, which is a mandatory cap-and-trade program established in 2005 to cap regional carbon dioxide emissions from power plants. Six midwestern states and one Canadian province entered into the Midwestern Regional Greenhouse Gas Reduction Accord to establish voluntary regional greenhouse gas reduction targets and develop a voluntary multi-sector cap-and-trade system to help meet the targets, although it has been reported that the members no longer are actively pursuing the group’s activities. Lastly, California and Quebec remain members of the Western Climate Initiative, which was formed in 2008 to establish a voluntary regional greenhouse gas reduction goal and develop market-based strategies to achieve emissions reductions, and those two jurisdictions have adopted their own greenhouse gas cap-and-trade regulations. Several states and provinces that originally were members of these organizations, as well as some current members, have joined the new North America 2050 initiative, which seeks to reduce greenhouse gas emissions and create economic opportunities aside from cap-and-trade programs. Any particular state, or any of these or other regional group, may have or adopt in the future rules or policies that cause some users of coal to switch from coal to a lower carbon fuel. There can be no assurance at this time that a carbon dioxide cap-and-trade-program, a carbon tax or other regulatory or policy regime, if implemented by any one or more states or regions in which our customers operate or at the federal level, will not affect the future market for coal in those states or regions and lower the overall demand for coal.

 

Clean Water Act.  The federal Clean Water Act (sometimes shortened to CWA) and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including dredged and fill materials, into waters of the United States. The Clean Water Act provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. Recent court decisions and regulatory actions have

 

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created uncertainty over Clean Water Act jurisdiction and permitting requirements that could variously increase or decrease the cost and time we expend on Clean Water Act compliance.

 

Clean Water Act requirements that may directly or indirectly affect our operations include the following:

 

·                  Water Discharge.  Section 402 of the Clean Water Act 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, which we refer to as the NPDES, or an equally stringent program delegated to a state regulatory agency. 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 United States, especially on selenium, sulfate and specific conductance. Discharges that exceed the limits specified under NPDES permits can lead to the imposition of penalties, and persistent non-compliance could lead to significant penalties, compliance costs and delays in coal production. In addition, the imposition of future restrictions on the discharge of certain pollutants into waters of the United States could increase the difficulty of obtaining and complying with NPDES permits, which could impose additional time and cost burdens on our operations. You should see Item 3, “Legal Proceedings,” for more information about certain regulatory actions pertaining to our operations. Discharges of pollutants into waters that states have designated as impaired (i.e., as not meeting present water quality standards) are subject to Total Maximum Daily Load, which we refer to as TMDL, regulations. The TMDL regulations establish a process for calculating the maximum amount of a pollutant that a water body can receive while maintaining state water quality standards. Pollutant loads are allocated among the various sources that discharge pollutants into that water body. Mine operations that discharge into water bodies designated as impaired will be required to meet new TMDL allocations. The adoption of more stringent TMDL-related allocations for our coal mines could require more costly water treatment and could adversely affect our coal production.

 

The Clean Water Act also requires states to develop anti-degradation policies to ensure that non-impaired water bodies continue to meet water quality standards. The issuance and renewal of permits for the discharge of pollutants to waters that have been designated as “high quality” are subject to anti-degradation review that may increase the costs, time and difficulty associated with obtaining and complying with NPDES permits.

 

Under the Clean Water Act, citizens may sue to enforce NPDES permit requirements. Beginning in 2012, multiple citizens’ suits were filed in West Virginia against mine operators for alleged violations of NPDES permit conditions requiring compliance with West Virginia’s water quality standards. Some of the lawsuits alleged violations of water quality standards for selenium, whereas others alleged that discharges of conductivity and sulfate were causing violations of West Virginia water quality standards that prohibit adverse effects to aquatic life. The suits sought penalties as well as injunctive relief that would limit future discharges of selenium, conductivity or sulfate through the implementation of expensive treatment technologies. In 2012, the federal district court for the Southern District of West Virginia granted summary judgment to citizens in one such suit alleging violations of the water quality standard for selenium. In 2014, the same court found in another such suit that discharges of conductivity from two West Virginia mines were causing violations of West Virginia’s narrative water quality standards. Both cases were resolved prior to any appeal and it is difficult to predict whether such suits will continue to be successful.

 

Citizens may also sue under the Clean Water Act when pollutants are being discharged without NPDES permits. Beginning in 2013, multiple citizens’ suits were filed in West Virginia against landowners alleging ongoing discharges of pollutants, including selenium and conductivity, from valley fills at reclaimed mining sites. In each case, the reclamation bond had been released and the mining and NPDES permits had been terminated following the completion of reclamation. While it is difficult to predict the outcome of such suits, any determination that discharges from valley fills require NPDES permits could result in increased compliance costs following the completion of mining at our operations.

 

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·                  Dredge and Fill Permits.  Many mining activities, such as the development of refuse impoundments, fresh water impoundments, refuse fills, valley fills, and other similar structures, may result in impacts to waters of the United States, including wetlands, streams and, in certain instances, man-made conveyances that have a hydrologic connection to such streams or wetlands. Under the Clean Water Act, coal companies are required to obtain a Section 404 permit from the Army Corps of Engineers, which we refer to as the Corps, prior to conducting such mining activities. The Corps is authorized to issue 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, which we refer to as NWP 21, generally authorize the disposal of dredged and fill material from surface coal mining activities into waters of the United States, subject to certain restrictions. Since March 2007, permits under NWP 21 were reissued for a five-year period with new provisions intended to strengthen environmental protections. There must be appropriate mitigation in accordance with nationwide general permit conditions rather than less restricted state-required mitigation requirements, and permit holders must receive explicit authorization from the Corps before proceeding with proposed mining activities. Notwithstanding the additional environmental protections designed in the NWP 21, on July 15, 2009, the Corps proposed to immediately suspend the use of NWP 21 in six Appalachian states, including West Virginia, Kentucky and Virginia where the Company conducts operations. On June 17, 2010, the Corps announced that it had suspended the use of NWP 21 in the same six states although it remained for use elsewhere. In February 2012, the Corps proposed to reissue NWP 21, albeit with significant restrictions on the acreage and length of stream channel that can be filled in the course of mining operations. The Corps’ decisions regarding the use of NWP 21 does not prevent the Company’s operations from seeking an individual permit under § 404 of the CWA, nor does it restrict an operation from utilizing another version of the nationwide permit, NWP 50, authorized for small underground coal mines that must construct fills as part of their mining operations.

 

The use of nationwide permits to authorize stream impacts from mining activities has been the subject of significant litigation. Refer to Item 3, “Legal Proceedings,” for more information about certain litigation pertaining to our permits.

 

Resource Conservation and Recovery Act.  The Resource Conservation and Recovery Act, which we refer to as RCRA, may affect coal mining operations through its requirements for the management, handling, transportation and disposal of hazardous wastes. Currently, certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management. In addition, Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In its 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion products generated at electric utility and independent power producing facilities, such as coal ash, and left the exemption in place. In May 2000, the EPA concluded that coal combustion products do not warrant regulation as hazardous waste under RCRA and again retained the hazardous waste exemption for these wastes. The EPA also determined that national non-hazardous waste regulations under RCRA Subtitle D are needed for coal combustion products disposed in surface impoundments and landfills and used as mine-fill. In March of 2007 the Office of Surface Mining and the EPA proposed regulations regarding the management of coal combustion products. The EPA concluded that beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. As long as this exemption remains in effect, it is not anticipated that regulation of coal combustion waste will have any material effect on the amount of coal used by electricity generators. A final rule has not been promulgated. Most state hazardous waste laws also exempt coal combustion products, and instead treat it as either a solid waste or a special waste. Any costs associated with handling or disposal of hazardous wastes would increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of ash can lead to material liability. In another development regarding coal combustion wastes, the EPA conducted an assessment of impoundments and other units that manage residuals from coal combustion and that contain free liquids following a massive coal ash spill in Tennessee in 2008, the EPA contractors conducted site assessments at many impoundments and is requiring appropriate remedial action at any facility that is found to have a unit posing a risk for potential failure. The EPA is posting utility responses to the assessment on its web site as the responses are received. Future regulations resulting from the EPA coal combustion refuse assessments may impact the ability of the Company’s utility customers to continue to use coal in their power plants.

 

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

 

Endangered Species.  The Endangered Species Act and other related federal and state statutes protect species threatened or endangered with possible extinction. Protection of threatened, endangered and other special status species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species. A number of species indigenous to our properties are protected under the Endangered Species Act or other related laws or regulations. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans. We have been able to continue our operations within the existing spatial, temporal and other restrictions associated with special status species. Should more stringent protective measures be applied to threatened, endangered or other special status species or to their critical habitat, then we could experience increased operating costs or difficulty in obtaining future mining permits.

 

Use of Explosives.  Our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to strict regulatory requirements established by four different federal regulatory agencies. 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, must complete a screening review in order to help determine whether there is a high level of security risk such that a security vulnerability assessment and site security plan will be required.

 

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

 

Employees

 

At December 31, 2015, we employed approximately 4,655 full and part-time employees. We believe that our relations with all employees are good.

 

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Executive Officers

 

The following is a list of our executive officers, their ages as of February 29, 2016 and their positions and offices during the last five years:

 

Name

 

Age

 

Position

Kenneth D. Cochran

 

55

 

Mr. Cochran has served as our Senior Vice President-Operations since August 2012. From May 2011 to August 2012, Mr. Cochran served as Group President of our western operations, which included Thunder Basin Coal Company, the Arch Western Bituminous Group, Arch of Wyoming and the Otter Creek development, and served as President and General Manager of Thunder Basin Coal Company from 2005 to April 2011. Prior to joining Arch Coal in 2005, Mr. Cochran spent 20 years with TXU Corporation. Mr. Cochran currently serves on the boards of Millennium Bulk Terminals-Longview, LLC, Knight Hawk Holdings, LLC, and Tongue River Holding Company.

John T. Drexler

 

46

 

Mr. Drexler has served as our Senior Vice President and Chief Financial Officer since 2008 and as our principal accounting officer since January 2016. Mr. Drexler served as our Vice President-Finance and Accounting from 2006 to 2008. From 2005 to 2006, Mr. Drexler served as our Director of Planning and Forecasting. Prior to 2005, Mr. Drexler held several other positions within our finance and accounting department.

John W. Eaves

 

58

 

Mr. Eaves was elected Chairman of the Board in April 2015 and currently serves as our Chairman and Chief Executive Officer. Mr. Eaves served as our President and Chief Operating Officer from 2006 until he was elected as our Chief Executive Officer in April 2012. From 2002 to 2006, Mr. Eaves served as our Executive Vice President and Chief Operating Officer. Mr. Eaves currently serves on the boards of COALOGIX, National Mining Association, the Business Roundtable, the American Coalition for Clean Coal Electricity and the Business Council. Mr. Eaves was previously a director of Advanced Emissions Solutions, Inc. and former chairman of the National Coal Council.

Robert G. Jones

 

59

 

Mr. Jones has served as our Senior Vice President-Law, General Counsel and Secretary since 2008. Mr. Jones served as Vice President-Law, General Counsel and Secretary from 2000 to 2008.

Allen R. Kelley

 

55

 

Mr. Kelley was appointed Vice President-Human Resources in March 2014. From 2008 to March 2014, Mr. Kelley served as our Vice President-Enterprise Risk Management. From 2005 to 2008, Mr. Kelley served as our Director of Internal Audit. Prior to 2005, Mr. Kelley held various finance and accounting positions within the corporate and operations functions of Arch Coal, Inc.

Paul A. Lang

 

55

 

Mr. Lang was elected our President and Chief Operating Officer in April 2015. He has served as our Executive Vice President and Chief Operating Officer since April 2012 and as our Executive Vice President-Operations from August 2011 to April 2012. Mr. Lang served as Senior Vice President-Operations from 2006 through August 2011, as President of Western Operations from 2005 through 2006 and President and General Manager of Thunder Basin Coal Company from 1998 to 2005. Mr. Lang is a director of Arch Coal, Inc., Advanced Emissions Solutions, Inc. and Knight Hawk Holdings, LLC. Mr. Lang also serves on the development board of the Mining Department of the Missouri University of Science & Technology, and is chairman of the University of Wyoming’s School of Energy Resources Council.

Deck S. Slone

 

52

 

Mr. Slone has served as our Senior Vice President-Strategy and Public Policy since June 2012. Mr. Slone served as our Vice President-Government, Investor and Public Affairs from 2008 to June 2012. Mr. Slone served as our Vice President-Investor Relations and Public Affairs from 2001 to 2008. Mr. Slone is a director of Millennium Bulk Terminals-Longview and DKRW Advanced Fuels. In addition, Mr. Slone serves as co-chair of the Coal Utilization Research Council, as National Coal Council Policy Committee chair and as a member of the steering committee of the Consortium for Clean Coal Utilization at Washington University in St. Louis.

John A. Ziegler, Jr.

 

49

 

Mr. Ziegler was appointed Chief Commercial Officer in March 2014. Mr. Ziegler served as our Vice President-Human Resources from April 2012 to March 2014. From October 2011 to April 2012, Mr. Ziegler served as our Senior Director-Compensation and Benefits. From 2005 to October 2011 Mr. Ziegler served as Vice President-Contract Administration, President of Sales, then finally Senior Vice President, Sales and Marketing and Marketing Administration. Mr. Ziegler joined Arch Coal in 2002 as Director-Internal Audit. Prior to joining Arch Coal, Mr. Ziegler held various finance and accounting positions with bioMerieux and Ernst & Young.

 

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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. You may access and read our filings without charge through the SEC’s website, at 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, archcoal.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 (314) 994-2700 or by mail at Arch Coal, Inc., One CityPlace Drive, Suite 300, St. Louis, Missouri, 63141 Attention: Senior Vice President-Strategy and Public Policy. The information on our website is not part of this Annual Report on Form 10-K.

 

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GLOSSARY OF SELECTED MINING TERMS

 

Certain terms that we use in this document are specific to the coal mining industry and may be technical in nature. The following is a list of selected mining terms and the definitions we attribute to them.

 

Assigned reserves

 

Recoverable reserves designated for mining by a specific operation.

Brown coal

 

Coal of gross calorific value of less than 5700 kilocalories per kilogramme (kcal/kg), which includes lignite and sub-bituminous coal where lignite has a gross calorific value of less than 4165 kcal/kg and sub-bituminous coal has a gross calorific value between 4165 kcal/kg and 5700 kcal/kg.

Btu

 

A measure of the energy required to raise the temperature of one pound of water one degree of Fahrenheit.

Compliance coal

 

Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus, requiring no blending or other sulfur dioxide reduction technologies in order to comply with the requirements of the Clean Air Act.

Continuous miner

 

A machine used in underground mining to cut coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation.

Dragline

 

A large machine used in surface mining to remove the overburden, or layers of earth and rock, covering a coal seam. The dragline has a large bucket, suspended by cables from the end of a long boom, which is able to scoop up large amounts of overburden as it is dragged across the excavation area and redeposit the overburden in another area.

Hard coal

 

Coal of gross calorific value greater than 5700 kcal/kg on an ashfree but moist basis and further disaggregated into anthracite, coking coal and other bituminous coal.

Longwall mining

 

One of two major underground coal mining methods, generally employing two rotating drums pulled mechanically back and forth across a long face of coal.

Low-sulfur coal

 

Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btus.

Preparation plant

 

A facility used for crushing, sizing and washing coal to remove impurities and to prepare it for use by a particular customer.

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.

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 restoration of land and environmental values to a mining site after the coal is extracted. The process commonly includes “recontouring” or shaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers.

Recoverable reserves

 

The amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods and under current law.

Reserves

 

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

Room-and-pillar mining

 

One of two major underground coal mining methods, utilizing continuous miners creating a network of “rooms” within a coal seam, leaving behind “pillars” of coal used to support the roof of a mine.

Unassigned reserves

 

Recoverable reserves that have not yet been designated for mining by a specific operation.

 

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ITEM 1A.  RISK FACTORS.

 

Our business involves certain risks and uncertainties. In addition to the risks and uncertainties described below, we may face other risks and uncertainties, some of which may be unknown to us and some of which we may deem immaterial and the following review of important risk factors should not be construed as exhaustive and should be read in conjunction with other cautionary statements that are included herein or elsewhere. If one or more of these risks or uncertainties occur, our business, financial condition or results of operations may be materially and adversely affected.

 

Risks Related to Our Chapter 11 Cases

 

As a result of the filing of the Bankruptcy Petitions, we are subject to the risks and uncertainties associated with bankruptcy proceedings, and operating under Chapter 11 may restrict our ability to pursue strategic and operational initiatives.

 

For the duration of the Chapter 11 Cases (In re Arch Coal, Inc., et al.), our operations and our ability to execute our business strategy will be subject to the risks and uncertainties associated with bankruptcy. These risks include:

 

·                  our ability to obtain Court approval with respect to motions filed in the Chapter 11 Cases from time to time;

·                  our ability to comply with and operate under any cash management orders entered by the Court from time to time;

·                  our ability to comply with our Restructuring Support Agreement and DIP Credit Agreement terms and conditions;

·                  our ability to confirm and consummate a Chapter 11 plan of reorganization;

·                  our ability to fund and execute our business plan; and

·                  our ability to continue as a going concern.

 

These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with the Chapter 11 Cases could adversely affect our relationships with our suppliers, customers and employees.   In particular, critical vendors may determine not to do business with us due to our Chapter 11 filing and we may not be successful in securing alternative sources.  Also, transactions outside the ordinary course of business are subject to the prior approval of the Court, which may limit our ability to respond timely to certain events or take advantage of opportunities. Because of the risks and uncertainties associated with the Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 reorganization process may have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.

 

Under Chapter 11, transactions outside the ordinary course of business are subject to the prior approval of the Court, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities. Additionally, the terms of the DIP Credit Agreement require us to comply with certain financial maintenance covenants, including (i) maximum capital expenditures and (ii) minimum unrestricted cash and cash equivalents. The DIP Credit Agreement also contains customary affirmative and negative covenants for debtor-in-possession financings, which include restrictions on (i) indebtedness, (ii) liens and guaranties, (iii) liquidations, mergers, consolidations, acquisitions, (iv) disposition of assets or subsidiaries, (v) affiliate transactions, (vi) creation or ownership of certain subsidiaries, partnerships and joint ventures, (vii) continuation of or change in business, (viii) restricted payments, (ix) sanctions and anti-corruption matters, (x) no restriction in agreements on dividends or certain loans, (xi) loans and investments, (xii) transactions with respect to Bonding Subsidiaries and (xiii) hedging transactions. In addition, the DIP Credit Agreement contains milestones relating to the Chapter 11 Cases. Our ability to comply with these provisions may be affected by events beyond our control and our failure to comply could result in an event of default under the DIP Credit Agreement.

 

Trading in our securities during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks.  We expect that the existing common stock of the Company will be extinguished and existing equity holders will not receive consideration in respect of their equity interests.

 

On the Petition Date, the NYSE determined that the Company’s stock (NYSE: ACI) was no longer suitable for listing pursuant to Section 8.02.01D of the NYSE continued listing standards and trading in the Company’s common stock was suspended on January 11, 2016.  We expect that the existing common stock of the Company will be extinguished upon the

 

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Company’s emergence from Chapter 11 and existing equity holders will not receive consideration in respect of their equity interests.  Following delisting from the NYSE, Arch common stock has been traded over the counter in the Pink Sheets, but this may not always be the case. The delisting by the NYSE could result in significantly lower trading volumes and reduced liquidity for investors seeking to buy or sell shares of our common stock.

 

Arch’s Restructuring Support Agreement provides that, upon the Company’s emergence from Chapter 11, Arch’s existing stock will be cancelled and the senior lenders will receive the substantial majority of the new stock in the reorganized Arch. If a plan of reorganization is approved in the Chapter 11 Cases, it is likely that our existing common stock will be extinguished, and existing equity holders will likely not receive consideration in respect of their existing equity interests.

 

The pursuit of the Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.

 

While the Chapter 11 Cases continue, our management will be required to spend a significant amount of time and effort focusing on the cases. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, on our financial condition and results of operations, particularly if the Chapter 11 Cases are protracted.

 

During the pendency of the Chapter 11 Cases, our employees will face considerable distraction and uncertainty and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a materially adverse effect on our ability to meet customer expectations, thereby adversely affecting our business and results of operations. The failure to retain or attract members of our management team and other key personnel could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.

 

If we are not able to obtain confirmation of a Chapter 11 plan of reorganization, or if current financing is insufficient or exit financing is not available, we could be required to seek a sale of the Company or certain of its material assets pursuant to Section 363 of the Bankruptcy Code or liquidate under Chapter 7 of the Bankruptcy Code.

 

In order to successfully emerge from Chapter 11 bankruptcy protection, we must obtain confirmation of a Chapter 11 plan of reorganization by the Court. If confirmation by the Court does not occur, we could be forced to sell the Company or certain of its material assets pursuant to Section 363 of the Bankruptcy Code or liquidate under Chapter 7 of the Bankruptcy Code.

 

There can be no assurance that our current cash position and amounts of cash from future operations will be sufficient to fund operations. In the event that we do not have sufficient cash to meet our liquidity requirements, and our current financing is insufficient or exit financing is not available, we may be required to seek additional financing. There can be no assurance that such additional financing would be available, or, if available, would be available on acceptable terms. Failure to secure any necessary exit financing or additional financing would have a material adverse effect on our operations and ability to continue as a going concern.

 

Our post-bankruptcy capital structure has yet to be determined, and any changes to our capital structure may have a material adverse effect on existing debt and security holders.

 

Our capital structure will be set pursuant to a plan of reorganization that requires Court approval. Any reorganization of our capital structure may include exchanges of new debt or equity securities for our existing debt and equity securities, and such new debt or equity securities may be issued at different interest rates, payment schedules and maturities than our existing creditors. The success of a reorganization through any such exchanges or modifications will depend on approval by the Court and the willingness of existing debt and security holders to agree to the exchange or modification, and there can be no guarantee of success. If such exchanges or modifications are successful, holders of our debt may find their holdings no longer have any value or are materially reduced in value, or they may be converted to equity and be diluted or may be modified or

 

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replaced by debt with a principal amount that is less than the outstanding principal amount, longer maturities and reduced interest rates. There can be no assurance that any new debt or equity securities will maintain their value at the time of issuance.

 

Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, or adverse market conditions persist or worsen, our plan may be unsuccessful in its execution.

 

Any plan of reorganization that we may implement will affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to substantially change our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and coal industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

 

In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, EBITDA, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

 

As a result of the Chapter 11 Cases, realization of assets and liquidation of liabilities are subject to uncertainty, and our historical financial information will not be indicative of our future financial performance.

 

Our capital structure will likely be significantly altered under any plan of reorganization ultimately confirmed by the Court. Under fresh-start reporting rules that may apply to us upon the effective date of a plan of reorganization, our assets and liabilities would be adjusted to fair values and our accumulated deficit would be restated to zero. Accordingly, if fresh-start reporting rules apply, our financial condition and results of operations following our emergence from Chapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

 

While operating under the protection of the Bankruptcy Code, and subject to Court approval or otherwise as permitted in the normal course of business, we may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in our consolidated financial statements. In connection with the Chapter 11 Cases and the development of a plan of reorganization, it is also possible that additional restructuring and related charges may be identified and recorded in future periods. Such sales, disposals, liquidations, settlements or charges could be material to our consolidated financial position and results of operations in any given period.

 

We may be unable to comply with restrictions imposed by our DIP Credit Agreement, our Securitization Facility and other financing arrangements.

 

The agreements governing our outstanding financing arrangements impose a number of restrictions on us. For example, the terms of our credit facilities, leases and other financing arrangements contain financial and other covenants that create limitations on our ability to borrow the full amount under our credit facilities, effect acquisitions or dispositions and

 

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incur additional debt and require us to maintain minimum levels of liquidity and various financial ratios and comply with various other financial covenants.  Specifically, the terms of the DIP Credit Agreement require us to comply with certain financial maintenance covenants, including (i) maximum capital expenditures and (ii) minimum unrestricted cash and cash equivalents. The DIP Credit Agreement also contains customary affirmative and negative covenants for debtor-in-possession financings, which include restrictions on (i) indebtedness, (ii) liens and guaranties, (iii) liquidations, mergers, consolidations, acquisitions, (iv) disposition of assets or subsidiaries, (v) affiliate transactions, (vi) creation or ownership of certain subsidiaries, partnerships and joint ventures, (vii) continuation of or change in business, (viii) restricted payments, (ix) sanctions and anti-corruption matters, (x) no restriction in agreements on dividends or certain loans, (xi) loans and investments, (xii) transactions with respect to Bonding Subsidiaries and (xiii) hedging transactions. In addition, the DIP Credit Agreement contains milestones relating to the Chapter 11 Cases. Our ability to comply with these provisions may be affected by events beyond our control and our failure to comply could result in an event of default under the DIP Credit Agreement, the Securitization Facility or our other financing arrangements.

 

Risks Related to Our Operations

 

Coal prices are subject to change based on a number of factors and coal prices are currently experiencing an historic level of depression. If coal prices remain depressed, or if there is a further decline in prices, it could materially and adversely affect our profitability and the value of our coal reserves.

 

Our profitability and the value of our coal reserves depend upon the prices we receive for our coal. The contract prices we may receive in the future for coal depend upon factors beyond our control, including the following:

 

·                  the domestic and foreign supply of and demand for coal;

·                  the domestic and foreign demand for electricity and steel;

·                  the quantity and quality of coal available from competitors;

·                  competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;

·                  domestic and foreign air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards;

·                  adverse weather, climatic or other natural conditions, including unseasonable weather patterns;

·                  domestic and foreign economic conditions, including economic slowdowns and the exchange rate of U.S. dollars for foreign currency;

·                  domestic and foreign legislative, regulatory and judicial developments, environmental regulatory changes or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions or providing for increased funding and incentives for alternative energy sources;

·                  the proximity to, capacity of and cost of transportation and port facilities; and

·                  market price fluctuations for sulfur dioxide or nitric oxide emission allowances.

 

Due to a number of factors outside our control, including decelerating demand for coal used in electricity (due to low natural gas prices and regulations), an oversupplied market and increased competition particularly from non-U.S. suppliers taking advantage of a strong dollar, we have experienced a sustained and significant downturn in coal pricing over the last several years. The global metallurgical coal market remains challenged and has shown no meaningful improvement over the

 

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last several years. We are also experiencing higher than normal uncommitted volumes due to prolonged, depressed market conditions.  Pricing may be adversely affected or we may need to reduce production as a result of our uncommitted volume levels.  If coal prices remain depressed, or if there is a further decline in the prices we receive for our future coal sales contracts, it could materially and adversely affect us by decreasing our profitability and the value of our coal reserves.

 

Unfavorable economic and market conditions have adversely affected and may continue to affect our revenues and profitability.

 

Our profitability depends, in large part, on conditions in the markets that we serve, which fluctuate in response to various factors beyond our control. The prices at which we sell our coal are largely dependent on prevailing market prices. We have experienced significant price pressure over the past several years, and we expect that the price for our coal will continue to be depressed, as the demand for, and price of, coal remains subject to pressure for a variety of reasons, including reductions in domestic and international demand for metallurgical and thermal coal. These conditions, among other factors, have led to our filing of the Bankruptcy Petitions.

 

Global economic downturns have also had and in the future could have a negative impact on us. These conditions have, in the past, led to extreme volatility of security prices, severely limited liquidity and credit availability, and resulted in declining valuations of assets. If there are downturns in economic conditions, our customers’ and our businesses, financial conditions or results of operations could be adversely affected. During unfavorable economic conditions we are focused on cost control and capital discipline, but there can be no assurance that these actions, or any other actions that we may take, will be sufficient to offset any adverse effect these conditions may have on our business, financial condition or results of operations.

 

Competition could put downward pressure on coal prices and, as a result, materially and adversely affect our revenues and profitability.

 

We compete with numerous other domestic and foreign coal producers for domestic and international sales. Overcapacity and increased production within the coal industry, both domestically and internationally, and decelerating steel demand in China have, and could further, materially reduce coal prices and therefore materially reduce our revenues and profitability. In addition, our ability to ship our coal to international customers depends on port capacity, which is limited. Increased competition within the coal industry for international sales could result in us not being able to obtain throughput capacity at port facilities, or the rates for such throughput capacity to increase to a point where it is not economically feasible to export our coal.

 

In addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas. Natural gas pricing has declined significantly in recent years. The decline in the price of natural gas has caused demand for coal to decrease and adversely affect the price of our coal. Sustained periods of low natural gas prices have also contributed to utilities phasing out or closing existing coal-fired power plants and continued low prices could reduce construction of any new coal-fired power plants. This trend has, and could continue to have, a material adverse effect on demand and prices for our coal.

 

Any change in the coal consumption of electric power generators could result in less demand and lower prices for coal, which could materially and adversely affect our revenues and results of operations.

 

Thermal coal accounted for 95% of our coal sales by volume during 2015. The majority of these sales were to electric power generators. The amount of coal consumed for electric power generation is affected primarily by the overall demand for electricity, the availability, quality and price of competing fuels for power generation and governmental regulations. Gas-fueled generation has the potential to displace coal-fueled generation, particularly from older, less efficient coal-powered generators and this has occurred to date. We expect that many of the new power plants needed in the United States to meet increasing demand for electricity generation will be fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain as natural gas is seen as having a lower environmental impact than coal-fueled generation. In addition, state and federal mandates for increased use of electricity from renewable energy sources also have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use

 

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renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

 

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

 

We mine coal at underground and surface mining operations. Certain factors beyond our control, including those listed below, could disrupt our coal mining operations, adversely affect production and shipments and increase our operating costs:

 

·                  poor mining conditions resulting from geological, hydrologic or other conditions that may cause instability of highwalls or spoil piles or cause damage to nearby infrastructure or mine personnel;

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

·                  mining, processing and plant equipment failures and unexpected maintenance problems;

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

·                  unexpected or accidental surface subsidence from underground mining;

·                  accidental mine water discharges, fires, explosions or similar mining accidents;

·                  delays or closures by third-party transportation on coal shipments; and

·                  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.

 

If any of these conditions or events occurs, particularly at our Black Thunder mining complex, which accounted for approximately 78% of the coal volume we sold in 2015, our coal mining operations may be disrupted and we could experience a delay or halt of production or shipments or our operating costs could increase significantly. In addition, if our insurance coverage is limited or excludes certain of these conditions or events, then we may not be able to recover any of the losses we may incur as a result of such conditions or events, some of which may be substantial.

 

A decline in demand for metallurgical coal would limit our ability to sell our coal into higher-priced metallurgical markets and could substantially affect our business.

 

Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on the prevailing conditions in the metallurgical and steam coal markets. We decide whether to mine, process and market these coals as metallurgical or steam coal based on management’s assessment as to which market is likely to provide us with a higher margin. We consider a number of factors when making this assessment, including the difference between the current and anticipated future market prices of steam coal and metallurgical coal and the increased costs incurred in producing coal for sale in the metallurgical market instead of the steam market. The global metallurgical coal market remains challenged and has shown no meaningful improvement over the last several quarters, due to, among other things, reduced steel production. A further decline in, or prices remaining depressed in, the metallurgical market relative to the steam market could cause us, as well as our competitors, to shift coal from the metallurgical market to the steam market, thereby reducing our revenues and profitability and increasing the availability of coal to customers in the steam market.

 

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Our inability to acquire additional coal reserves or our inability to develop coal reserves in an economically feasible manner may adversely affect our business.

 

Our profitability depends substantially on our ability to mine and process, in a cost-effective manner, coal reserves that possess the quality characteristics desired by our customers. As we mine, our coal reserves decline. As a result, our future success depends upon our ability to acquire additional coal that is economically recoverable. If we fail to acquire or develop additional coal reserves, our existing reserves will eventually be depleted. We may not be able to obtain replacement reserves when we require them. If available, replacement reserves may not be available at favorable prices, or we may not be capable of mining those reserves at costs that are comparable with our existing coal reserves. Our ability to obtain coal reserves in the future could also be limited by the availability of cash we generate from our operations or available financing, restrictions under our existing or future financing arrangements (including under our DIP Credit Agreement), competition from other coal producers, the lack of suitable acquisition or lease-by-application, or LBA, opportunities or the inability to acquire coal properties or LBAs on commercially reasonable terms, and restrictions on making acquisitions as a result of our Chapter 11 Cases. If we are unable to acquire replacement reserves, our future production may decrease significantly and our operating results may be negatively affected. In addition, we may not be able to mine future reserves as profitably as we do at our current operations.

 

On January 15, 2016, the federal government ordered a moratorium on new leases for coal mined from federal lands as part of a review of the government’s management of federally-owned coal.  The delay in the LBA process caused by the moratorium could prevent us from obtaining replacement reserves when we require them.  Also, the outcome of the government’s review is uncertain and could have a material and adverse impact on our business in any number of ways including by limiting our ability to mine reserves under ongoing or future applications, by increasing the costs or timeframe associated with obtaining leases under the LBA program, by making it uneconomical for us to participate in the programs or by preventing us from obtaining replacement reserves if the LBA program were to be terminated.

 

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

 

Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. We base our estimates of reserves on engineering, economic and geological data assembled, analyzed and reviewed by internal and third-party engineers and consultants. We update our estimates of the quantity and quality of proven and probable coal reserves 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, including many factors beyond our control, including the following:

 

·                  quality of the coal;

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

·                  the percentage of coal ultimately recoverable;

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

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

·                  assumptions concerning physical access to the reserves; and

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

 

As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary materially due to changes in the above factors and assumptions. Actual production recovered from identified reserve

 

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areas and properties, and revenues and expenditures associated with our mining operations, may vary materially from estimates. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues and/or higher than expected costs.

 

Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal, and a loss or reduction in our ability to self-bond could have a material adverse effect on our business and results of operations.

 

Federal and state laws require us to obtain surety bonds or post letters of credit to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations. The costs of surety bonds have fluctuated in recent years while the market terms of such bonds have generally become more unfavorable to mine operators. These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, our failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. We use self-bonding to secure performance of certain obligations in Wyoming. Self-bonding allows us to mine without posting any other third party financial assurance such as a surety bond or letter of credit.  As of December 31, 2015, we have self-bonded an aggregate of approximately $485.5 million. The Land Quality Division of the Wyoming Department of Environmental Quality periodically re-evaluates the amount of the bond, so this amount is subject to change.

 

On February 29, 2016, the Bankruptcy Court approved a stipulation between certain of our operating subsidiaries and the State of Wyoming, pursuant to which those subsidiaries granted Wyoming a $75 million superpriority claim to support the self-bonded obligations and agreed to substitute approximately $17 million of the self-bonds with financial assurance in the form of third-party collateral support.  In exchange, Wyoming agreed to a stay of any proceedings related to the subsidiaries’ self-bonded status and that, so long as the stipulation is effective, Wyoming will not seek additional collateral in respect of the self-bonds, take certain other adverse actions with respect to the subsidiaries’ mining permits or licenses in Wyoming or seek to enforce the subsidiaries’ obligations to make payments in respect of the self-bonds.  The stipulation is effective until the earlier of May 1, 2017 and the date upon which a plan of reorganization in the Chapter 11 Cases is approved and becomes effective, subject to certain early termination events.

 

Our self-bonding obligations may increase as our bankruptcy process continues, and, upon our emergence from bankruptcy or otherwise, we may not continue to qualify to self-bond or self-bonding programs may be terminated.  Alternative forms of financial assurance such as surety bonds and letters of credit may not be available to us. To the extent we are unable to maintain our current level of self-bonding, due to legislative or regulatory changes or changes in our financial condition, our costs would increase and it could have a material adverse effect on our financial condition and results of operations, as well as cast substantial doubt on our ability to continue as a going concern.

 

Increases in the costs of mining and other industrial supplies, including steel-based supplies, diesel fuel and rubber tires, or the inability to obtain a sufficient quantity of those supplies, could negatively affect our operating costs or disrupt or delay our production.

 

Our coal mining operations use significant amounts of steel, diesel fuel, explosives, rubber tires and other mining and industrial supplies. The cost of roof bolts we use in our underground mining operations depends on the price of scrap steel. We also use significant amounts of diesel fuel and tires for trucks and other heavy machinery, particularly at our Black Thunder mining complex. If the prices of mining and other industrial supplies, particularly steel based supplies, diesel fuel and rubber tires, increase, our operating costs could be negatively affected. In addition, if we are unable to procure these supplies, our coal mining operations may be disrupted or we could experience a delay or halt in our production.

 

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Disruptions in the quantities of coal produced by our contract mine operators or purchased from other third parties could temporarily impair our ability to fill customer orders or increase our operating costs.

 

We use independent contractors to mine coal at certain of our mining complexes, including select operations in our Appalachian segment. In addition, we purchase coal from third parties that we sell to our customers. Operational difficulties at contractor-operated mines or mines operated by third parties from whom we purchase coal, changes in demand for contract miners from other coal producers and other factors beyond our control could affect the availability, pricing, and quality of coal produced for or purchased by us. Disruptions in the quantities of coal produced for or purchased by us could impair our ability to fill our customer orders or require us to purchase coal from other sources in order to satisfy those orders. If we are unable to fill a customer order or if we are required to purchase coal from other sources in order to satisfy a customer order, we could lose existing customers and our operating costs could increase.

 

Our profitability depends upon the long-term coal supply agreements we have with our customers. Changes in purchasing patterns in the coal industry could make it difficult for us to extend our existing long-term coal supply agreements or to enter into new agreements in the future.

 

The success of our businesses depends on our ability to retain our current customers, renew our existing customer contracts and solicit new customers. Our ability to do so generally depends on a variety of factors, including the quality and price of our products, our ability to market these products effectively, our ability to deliver on a timely basis and the level of competition that we face. If current customers do not honor current contract commitments, or if they terminate agreements or exercise force majeure provisions allowing for the temporary suspension of performance, our revenues will be adversely affected. Changes in the coal industry may cause some of our customers not to renew, extend or enter into new long-term coal supply agreements or enter into agreements to purchase fewer tons of coal or on different terms or prices than in the past. In addition, uncertainty caused by federal and state regulations, including the Clean Air Act, could deter our customers from entering into long-term coal supply agreements.  Also, the availability and price of competing fuels, such as natural gas, could influence the volume of coal a customer is willing to purchase under contract.

 

Our long-term coal supply agreements typically contain force majeure provisions allowing the parties to temporarily suspend performance during specified events beyond their control. Most of our long-term coal supply agreements also contain provisions requiring us to deliver coal that satisfies certain quality specifications, such as heat value, sulfur content, ash content, hardness and ash fusion temperature. These provisions in our long-term coal supply agreements could result in negative economic consequences to us, including price adjustments, purchasing replacement coal in a higher-priced open market, the rejection of deliveries or, in the extreme, contract termination. Our profitability may be negatively affected if we are unable to seek protection during adverse economic conditions or if we incur financial or other economic penalties as a result of these provisions of our long-term supply agreements. For more information about our long-term coal supply agreements, you should see the section entitled “Long-Term Coal Supply Arrangements” under Item 1.

 

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates and our financial position could be materially and adversely effected by the bankruptcy of any of our significant customers.

 

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If we determine that a customer is not creditworthy, we may be able to withhold delivery under the customer’s coal sales contract. If this occurs, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contracted price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our significant customers could materially and adversely affect our financial position.

 

In addition, our customer base may change with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear for customer payment default. Some power plant owners may have credit ratings that are below investment grade, or may become below investment grade after we enter into contracts with them. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk of payment default. Customers in other countries may also be subject to other

 

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pressures and uncertainties that may affect their ability to pay, including trade barriers, exchange controls and local economic and political conditions.

 

A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine our coal reserves or result in significant unanticipated costs.

 

We conduct a significant part of our coal mining operations on properties that we lease. A title defect or the loss of a lease could adversely affect our ability to mine the associated coal reserves. We may not verify title to our leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or coal reserves that we intend to mine may contain defects prohibiting our ability to conduct mining operations. Similarly, our leasehold interests may be subject to superior property rights of other third parties. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and require us to pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.

 

The availability, reliability and cost-effectiveness of transportation facilities and fluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.

 

We depend upon barge, ship, rail, truck and belt transportation systems, as well as seaborne vessels and port facilities, to deliver coal to our customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, route closures and other events beyond our control could impair our ability to supply coal to our customers. Since we do not have long-term contracts with all transportation providers we utilize, decreased performance levels over longer periods of time could cause our customers to look to other sources for their coal needs. In addition, increases in transportation costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of the United States or abroad. If we experience disruptions in our transportation services or if transportation costs increase significantly and we are unable to find alternative transportation providers, our coal mining operations may be disrupted, we could experience a delay or halt of production or our profitability could decrease significantly.

 

In addition, a growing portion of our coal sales in recent years has been into export markets, and we are actively seeking additional international customers. Our ability to maintain and grow our export sales revenue and margins depends on a number of factors, including the existence of sufficient and cost-effective export terminal capacity for the shipment of coal to foreign markets. At present, there is limited terminal capacity for the export of coal into foreign markets. Our access to existing and future terminal capacity may be adversely affected by regulatory and permit requirements, environmental and other legal challenges, public perceptions and resulting political pressures, operational issues at terminals and competition among domestic coal producers for access to limited terminal capacity, among other factors. If we are unable to maintain terminal capacity, or are unable to access additional future terminal capacity for the export of our coal on commercially reasonable terms, or at all, our results could be materially and adversely affected.

 

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

 

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

 

For the year ended December 31, 2015, we derived approximately 18% of our total coal revenues from sales to our three largest customers and approximately 39% of our total coal revenues from sales to our ten largest customers. We are currently discussing the extension of coal sales agreements with some of these customers. However, we may be unsuccessful in obtaining coal supply agreements with those customers, and some or all of these customers could discontinue purchasing coal

 

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from us. If any of those 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 those customers on terms as favorable to us, it may have an adverse impact on the results of our business.

 

We may incur losses as a result of certain marketing, trading and asset optimization strategies.

 

We seek to optimize our coal production and leverage our knowledge of the coal industry through a variety of marketing, trading and other asset optimization strategies. We maintain a system of complementary processes and controls designed to monitor and control our exposure to market and other risks as a consequence of these strategies. These processes and controls seek to balance our ability to profit from certain marketing, trading and asset optimization strategies with our exposure to potential losses. While we employ a variety of risk monitoring and mitigation techniques, those techniques and accompanying judgments cannot anticipate every potential outcome or the timing of such outcomes. In addition, the processes and controls that we use to manage our exposure to market and other risks resulting from these strategies involve assumptions about the degrees of correlation or lack thereof among prices of various assets or other market indicators. These correlations may change significantly in times of market turbulence or other unforeseen circumstances. As a result, we may experience volatility in our earnings as a result of our marketing, trading and asset optimization strategies.

 

International growth in our operations adds new and unique risks to our business.

 

We have recently opened offices in China, Singapore and the United Kingdom. The international expansion of our operations increases our exposure to country and currency risks. In addition, our international offices are selling our coal to new customers and customers in new countries, whose business practices and reputations are not as well known to us. We are also challenged by political risks by expanding internationally, including the potential for expropriation of assets and limits on the repatriation of earnings. In the event that we are unable to effectively manage these new risks, our results of operations, financial position or cash flow could be adversely affected by these activities.

 

If we sustain cyber attacks or other security breaches that disrupt our operations, or that result in the unauthorized release of proprietary or confidential information, we could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks.

 

We may be subject to security breaches which could result in unauthorized access to our facilities or to information we are trying to protect. Unauthorized physical access to one or more of our facilities or locations, or electronic access to our proprietary or confidential information could result in, among other things, unfavorable publicity, litigation by parties affected by such breach, disruptions to our operations, loss of customers, and financial obligations for damages related to the theft or misuse of such information, any of which could have a substantial impact on our results of operations, financial condition or cash flows.

 

Risks Related to Environmental, Other Regulations and Legislation

 

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

 

Coal contains impurities, including but not limited to sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. The operations of our customers are subject to extensive environmental regulation particularly with respect to air emissions. For example, the federal Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. A series of more stringent requirements relating to particulate matter, ozone, haze, mercury, sulfur dioxide, nitrogen oxide and other air pollutants are expected to be proposed or become effective in coming years. The Clean Power Plan, under review by U.S. courts, would severely limit emissions of carbon dioxide which would adversely affect our ability to sell coal.  In addition, concerted conservation efforts that result in reduced electricity consumption could cause coal prices and sales of our coal to materially decline.

 

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Considerable uncertainty is associated with these air emissions initiatives. The content of regulatory requirements in the United States is in the process of being developed, and many new regulatory initiatives remain 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-fueled power plants. As a result, these power plants may switch to other fuels that generate fewer of these emissions or may install more effective pollution control equipment that reduces the need for low sulfur coal, possibly reducing future demand for coal and a reduced need to construct new coal-fueled power plants. Any switching of fuel sources away from coal, closure of existing coal-fired plants, or reduced construction of new 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.

 

You should see Item 1, “Environmental and Other Regulatory Matters” for more information about the various governmental regulations affecting us.

 

The demand for our products or our securities, as well as the number and quantity of viable financing alternatives, may be significantly impacted by increased regulation or other scrutiny of topics related to coal combustion.

 

Global climate issues and topics related to greenhouse gas emissions, such as the impact of fossil fuel combustion, continue to attract increasing public scrutiny. Legislative or regulatory efforts at the international, federal, state or local level to control emissions from the combustion of coal may result in electricity generators increasingly using fuel sources other than coal or closures of coal-fueled power plants. In addition, certain banks and other financing sources have taken actions to limit available financing for the development of new coal-fueled power plants, which also may adversely impact the future global demand for coal. Further, there have been recent efforts by members of the general financial and investment communities, such as investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to divest themselves and to promote the divestment of securities issued by companies involved in the fossil fuel extraction market, such as coal producers. Those entities also have been pressuring lenders to limit financing available to such companies. These efforts may adversely affect the market for our securities and our ability to access capital and financial markets in the future.

 

Any future laws, regulations or other policies of the nature described above may adversely impact our business in material ways. The degree to which any particular law, regulation or policy impacts us will depend on several factors, including the substantive terms involved, the relevant time periods for enactment and any related transition periods. We routinely attempt to evaluate the potential impact on us of any proposed laws, regulations or policies, which requires that we make several material assumptions. From time to time, we determine that the impact of one or more such laws, regulations or policies, if adopted and ultimately implemented as proposed, may result in materially adverse impacts on our operations, financial condition or cash flow; however, we often are not able to reasonably quantify such impacts. In general, however, it is likely that any future laws, regulations or other policies aimed at reducing greenhouse gas emissions will negatively impact demand for our coal.

 

Our failure to obtain and renew permits necessary for our mining operations could negatively affect our business.

 

Mining companies must obtain numerous permits that impose strict regulations on various environmental and operational matters in connection with coal mining. These include permits issued by various federal, state and local agencies and regulatory bodies. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by the regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing operations or the development of future mining operations. The public, including non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and submit objections to requested permits and environmental impact statements prepared in connection with applicable regulatory processes, and otherwise engage in the permitting process, including bringing citizens’ lawsuits to challenge the issuance of permits, the validity of environmental impact statements or performance of mining activities. Accordingly, required permits may not be issued or renewed in a timely fashion or at all, or permits issued or renewed may be conditioned in a

 

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manner that may restrict our ability to efficiently and economically conduct our mining activities, any of which would materially reduce our production, cash flow and profitability.

 

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

 

Federal or state regulatory agencies have the authority under certain circumstances following significant health and safety incidents, such as fatalities, to order a mine to be temporarily or permanently closed. If this occurred, we may be required to incur capital expenditures to re-open the mine. In the event that these agencies order the closing of our mines, our coal sales contracts generally 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.

 

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

 

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

 

·                  limitations on land use;

·                  mine permitting and licensing requirements;

·                  reclamation and restoration of mining properties after mining is completed;

·                  management of materials generated by mining operations;

·                  the storage, treatment and disposal of wastes;

·                  remediation of contaminated soil and groundwater;

·                  air quality standards;

·                  water pollution;

·                  protection of human health, plant-life and wildlife, including endangered or threatened species;

·                  protection of wetlands;

·                  the discharge of materials into the environment;

·                  the effects of mining on surface water and groundwater quality and availability; and

·                  the management of electrical equipment containing polychlorinated biphenyls.

 

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

 

New legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us to change operations significantly or incur increased costs. Such changes could have a material adverse effect on our financial condition and results of operations. You should see the section entitled “Environmental and Other Regulatory Matters” in Item 1 for more information about the various governmental regulations affecting us.

 

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

 

SMCRA and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of underground mining. We base our estimates of reclamation and mine closure liabilities on permit requirements, engineering studies and our engineering expertise related to these requirements. Our management and engineers periodically review these estimates. The estimates can change significantly if actual costs vary from our original assumptions or if governmental regulations change significantly. We are required to record new obligations as liabilities at fair value under generally accepted accounting principles. In estimating fair value, we considered the estimated current costs of reclamation and mine closure and applied inflation rates and a third-party profit, as required. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf. The resulting estimated reclamation and mine closure obligations could change significantly if actual amounts change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial condition.

 

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

 

Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. We could become subject to claims 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. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or at sites that we may acquire. Our liability for such claims may be joint and several with other owners or operators, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share.

 

We maintain extensive coal refuse areas and slurry impoundments at a number of our mining complexes. Such areas and impoundments are subject to extensive regulation. Slurry impoundments can fail, which could release large volumes of coal slurry into the surrounding environment. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined-out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.

 

Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage,” which we refer to as AMD. The treating of AMD can be costly. Although we do not currently face material costs associated with AMD, it is possible that we could incur significant costs in the future.

 

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

 

Judicial rulings that restrict how we may dispose of mining wastes could significantly increase our operating costs, discourage customers from purchasing our coal and materially harm our financial condition and operating results.

 

To dispose of mining overburden generated by our Appalachian surface mining operations, we often need to obtain permits to construct and operate valley fills and surface impoundments. Some of these permits are Clean Water Act § 404 permits issued by the Army Corps of Engineers (the Corps). Two of our operating subsidiaries were identified in an existing lawsuit, which challenged the issuance of such permits and asked that the Corps be ordered to rescind them. Two of our operating subsidiaries intervened in the suit to protect their interests in being allowed to operate under the issued permits, and the claims against one of the subsidiaries was thereafter dismissed. On February 13, 2009, the U.S. Court of Appeals for the Fourth Circuit ruled on appeals from decisions rendered prior to our intervention, which may have a favorable impact on our permits. The matter is pending before the U.S. District Court for the Southern District of West Virginia on Mingo Logan’s motion for summary judgment. If the matter is resolved ultimately in a manner that is adverse to the interests of our operating

 

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subsidiaries, such subsidiaries’ operating results may be adversely impacted.  For more information regarding this litigation matter you should see the section entitled “Legal Proceedings—Permit Litigation Matters” under Item 3.

 

Changes in the legal and regulatory environment could complicate or limit our business activities, increase our operating costs or result in litigation.

 

The conduct of our businesses is subject to various laws and regulations administered by federal, state and local governmental agencies in the United States. These laws and regulations may change, sometimes dramatically, as a result of political, economic or social events or in response to significant events.  Environmental and other non-governmental organizations and activists, many of which are well funded, continue to exert pressure on regulators and other government bodies to enact more stringent laws and regulations.  Changes in the legal and regulatory environment in which we operate may impact our results, increase our costs or liabilities, complicate or limit our business activities or result in litigation.  Such legal and regulatory environment changes may include changes in such items as: the processes for obtaining or renewing permits; self-bonding programs; federal lease by application programs; costs associated with providing healthcare benefits to employees; health and safety standards; accounting standards; taxation requirements; and competition laws.

 

For example, in April 2010, the EPA issued comprehensive guidance regarding the water quality standards that EPA believes should apply to certain new and renewed Clean Water Act permit applications for Appalachian surface coal mining operations. Under the EPA’s guidance, applicants seeking to obtain state and federal Clean Water Act permits for surface coal mining in Appalachia must perform an evaluation to determine if a reasonable potential exists that the proposed mining would cause a violation of water quality standards. According to the EPA Administrator, the water quality standards set forth in the EPA’s guidance may be difficult for most surface mining operations to meet. Additionally, the EPA’s guidance contains requirements for the avoidance and minimization of environmental and mining impacts, consideration of the full range of potential impacts on the environment, human health and local communities, including low-income or minority populations, and provision of meaningful opportunities for public participation in the permit process. The EPA’s guidance is subject to several pending legal challenges related to its legal effect and sufficiency including consolidated challenges pending in the United States Court of Appeals for the District of Columbia led by the National Mining Association. We may be required to meet these requirements in the future in order to obtain and maintain permits that are important to our Appalachian operations. We cannot give any assurance that we will be able to meet these or any other new standards.

 

In response to the April 2010 explosion at Massey Energy Company’s Upper Big Branch Mine and the ensuing tragedy, we expect that safety matters pertaining to underground coal mining operations will continue to be the topic of new legislation and regulation, as well as the subject of heightened enforcement efforts. For example, federal and West Virginia state authorities have announced special inspections of coal mines to evaluate several safety concerns, including the accumulation of coal dust and the proper ventilation of gases such as methane. In addition, both federal and West Virginia state authorities have announced that they are considering changes to mine safety rules and regulations which could potentially result in additional or enhanced required safety equipment, more frequent mine inspections, stricter and more thorough enforcement practices and enhanced reporting requirements. Any new environmental, health and safety requirements may increase the costs associated with obtaining or maintaining permits necessary to perform our mining operations or otherwise may prevent, delay or reduce our planned production, any of which could adversely affect our financial condition, results of operations and cash flows.

 

Further, mining companies are entitled a tax deduction for percentage depletion, which may allow for depletion deductions in excess of the basis in the mineral reserves. The deduction is currently being reviewed by the federal government for repeal. If repealed, the inability to take a tax deduction for percentage depletion could have a material impact on our financial condition, results of operations, cash flows and future tax payments.

 

ITEM 1B.  UNRESOLVED STAFF COMMENTS.

 

None.

 

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ITEM 2.  PROPERTIES.

 

Our Properties

 

General

 

At December 31, 2015, we owned or controlled, primarily through long-term leases, approximately 28,541 acres of coal land in Ohio, 21,832 acres of coal land in Maryland, 46,556 acres of coal land in Virginia, 380,471 acres of coal land in West Virginia, 106,059 acres of coal land in Wyoming, 273,299 acres of coal land in Illinois, 129,043 acres of coal land in Kentucky, 10,000 acres of coal land in Montana, 21,802 acres of coal land in New Mexico, 426 acres of coal land in Pennsylvania, and 18,443 acres of coal land in Colorado. In addition, we also owned or controlled through long-term leases smaller parcels of property in Alabama, Indiana, Washington, Arkansas, California, Utah and Texas. We lease approximately 86,321 acres of our coal land from the federal government and approximately 23,349 acres of our coal land from various state governments. Certain of our preparation plants or loadout facilities are located on properties held under leases which expire at varying dates over the next 30 years. Most of the leases contain options to renew. Our remaining preparation plants and loadout facilities are located on property owned by us or for which we have a special use permit.

 

Our executive headquarters occupies leased office space at One CityPlace Drive, in St. Louis, Missouri. Our subsidiaries currently own or lease the equipment utilized in their mining operations. You should see “Our Mining Operations” for more information about our mining operations, mining complexes and transportation facilities.

 

Our Coal Reserves

 

We estimate that we owned or controlled approximately 2.5 billion tons of proven and probable recoverable reserves at December 31, 2015. Our coal reserve estimates at December 31, 2015 were prepared by our engineers and geologists and reviewed by Weir International, Inc., a mining and geological consultant. Our coal reserve estimates are based on data obtained from our drilling activities and other available geologic data. Our coal reserve estimates are periodically updated to reflect past coal production and other geologic and 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.

 

Our coal reserve estimates include reserves that can be economically and legally extracted or produced at the time of their determination. In determining whether our reserves meet this standard, we take into account, among other things, our potential inability to obtain a mining permit, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in costs required to be incurred to meet regulatory requirements and obtaining mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. We use various assumptions in preparing our estimates of our coal reserves. You should see “Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs” contained in Item 1A, “Risk Factors.”

 

The following tables present our estimated assigned and unassigned recoverable coal reserves at December 31, 2015:

 

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Total Assigned Reserves

(Tons in millions)

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

As

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assigned

 

 

 

 

 

Sulfur Content (lbs.

 

Received

 

 

 

 

 

Mining Method

 

Past Reserve

 

 

 

Recoverable

 

 

 

 

 

per million Btus)

 

Btus per

 

Reserve Control

 

 

 

Under-

 

Estimates

 

 

 

Reserves

 

Proven

 

Probable

 

<1.2

 

1.2-2.5

 

>2.5

 

lb. (1)

 

Leased

 

Owned

 

Surface

 

ground

 

2013

 

2014

 

Wyoming

 

1,318

 

1,304

 

14

 

1,257

 

61

 

 

8,852

 

1,318

 

 

 

1,318

 

 

1,526

 

1,423

 

Montana

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Colorado

 

53

 

50

 

3

 

53

 

 

 

11,533

 

53

 

 

 

53

 

84

 

65

 

Central App.

 

35

 

34

 

1

 

23

 

12

 

 

12,479

 

35

 

 

25

 

10

 

169

 

139

 

Northern App.

 

40

 

35

 

5

 

 

40

 

 

13,074

 

2

 

38

 

 

40

 

58

 

74

 

Illinois

 

37

 

22

 

15

 

 

 

37

 

10,728

 

30

 

7

 

 

37

 

21

 

33

 

Total

 

1,483

 

1,445

 

38

 

1,333

 

113

 

37

 

9,195

 

1,438

 

45

 

1,343

 

140

 

1,858

 

1,734

 

 


(1)                                 As received Btus per lb. includes the weight of moisture in the coal on an as sold basis.

 

Total Unassigned Reserves

(Tons in millions)

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unassigned

 

 

 

 

 

Sulfur Content

 

 

 

 

 

 

 

Mining Method

 

 

 

Recoverable

 

 

 

 

 

(lbs. per million Btus)

 

As Received

 

Reserve Control

 

 

 

Under-

 

 

 

Reserves

 

Proven

 

Probable

 

<1.2

 

1.2-2.5

 

>2.5

 

Btus per lb.(1)

 

Leased

 

Owned

 

Surface

 

ground

 

Wyoming

 

480

 

397

 

83

 

428

 

52

 

 

9,653

 

370

 

110

 

305

 

175

 

Montana

 

 

 

 

 

 

 

 

 

 

 

 

Colorado

 

33

 

25

 

8

 

33

 

 

 

11,220

 

33

 

 

 

33

 

Central App.

 

59

 

50

 

9

 

20

 

26

 

13

 

12,522

 

11

 

48

 

41

 

18

 

Northern App.

 

144

 

70

 

74

 

 

142

 

2

 

12,961

 

1

 

143

 

 

144

 

Illinois

 

298

 

197

 

101

 

 

 

298

 

11,137

 

65

 

233

 

4

 

294

 

Total

 

1,014

 

739

 

275

 

481

 

220

 

313

 

10,777

 

480

 

534

 

350

 

664

 

 


(1)                                 As received Btus per lb. includes the weight of moisture in the coal on an as sold basis.

 

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The following table reconciles 2015 and 2014 coal proven and probable reserves:

 

 

 

Tons

 

 

 

(in millions)

 

December 31, 2014

 

5,064

 

Depletion (1)

 

(127

)

Revisions and additions, net (2)

 

(1,709

)

Mining rights relinquished

 

(731

)

December 31, 2015

 

2,497

 

 


(1)                                 Reserves mined and sold in 2015.

(2)                                 Revisions and additions, net are due to reclassification of reserves that no longer meet the definition of compliant “reserves” per SEC Industry Guide 7 which defines a “reserve” as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.  The tonnage reclassified from reserves continues to be controlled by the company, is mineable with existing technologies, and could factor into the Company’s mining plans in the future.

 

Federal and state legislation controlling air pollution affects the demand for certain types of coal by limiting the amount of sulfur dioxide which may be emitted as a result of fuel combustion and encourages a greater demand for low-sulfur coal. All of our identified coal reserves have been subject to preliminary coal seam analysis to test sulfur content. Of these reserves, approximately 73% consist of compliance coal, or coal which emits 1.2 pounds or less of sulfur dioxide per million Btus upon combustion, while an additional approximately 5% could be sold as low-sulfur coal. The balance is classified as high-sulfur coal. Most of our reserves are suitable for the domestic steam coal markets. A substantial portion of the low-sulfur and compliance coal reserves at a number of our Appalachian mining complexes may also be used as metallurgical coal.

 

The carrying cost of our coal reserves at December 31, 2015 was $2.5 billion, consisting of $33.7 million of prepaid royalties and a net book value of coal lands and mineral rights of $2.4 billion.

 

Reserve Acquisition Process

 

We acquire a significant portion of the coal we control in the western United States through the lease-by-application (LBA) process. Under this process, before a mining company can obtain new coal reserves, the coal tract must be nominated for lease, and the company must win the lease through a competitive bidding process. The LBA process can last anywhere from five to ten years from the time the coal tract is nominated to the time a final bid is accepted by the BLM. After the LBA is awarded, the company then conducts the necessary testing to determine what amount can be classified as reserves.

 

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 that 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.

 

If the BLM determines to continue the application, the company that submitted the application will pay for a BLM-directed environmental analysis or an environmental impact statement to be completed. This analysis or impact statement

 

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

 

After the environmental analysis or environmental impact statement has been issued and a recommendation has been published that supports the lease sale of the LBA tract, the BLM schedules a public competitive lease sale. The BLM prepares an internal estimate of the fair market value of the coal that is based on its economic analysis and comparable sales analysis. Prior to the lease sale, companies interested in acquiring the lease must send sealed bids to the BLM. The bid amounts for the lease are payable in five annual installments, with the first 20% installment due when the mining operator submits its initial bid for an LBA. Before the lease is approved by the BLM, the company must first furnish to the BLM an initial rental payment for the first year of rent along with either a bond for the next 20% annual installment payment for the bid amount, or an application for history of timely payment, in which case the BLM may waive the bond requirement if the company successfully meets all the qualifications of a timely payor. The bids are opened at the lease sale. If the BLM decides to grant a lease, the lease is awarded to the company that submitted the highest total bid meeting or exceeding the BLM’s fair market value estimate, which is not published. The BLM, however, is not required to grant a lease even if it determines that a bid meeting or exceeding the fair market value of the coal has been submitted. The winning bidder must also submit a report setting forth the nature and extent of its coal holdings to the U.S. Department of Justice for a 30-day antitrust review of the lease. If the successful bidder was not the initial applicant, the BLM will refund the initial applicant certain fees it paid in connection with the application process, for example the fees associated with the environmental analysis or environmental impact statement, and the winning bidder will bear those costs. Coal won through the LBA process and subject to federal leases are administered by the U.S. Department of Interior under the Federal Coal Leasing Amendment Act of 1976. In addition, we occasionally add small coal tracts adjacent to our existing LBAs through an agreed upon lease modification with the BLM. Once the BLM has issued a lease, the company must also complete the permitting process before it can mine the coal. You should see the section entitled “Environmental and Other Regulatory Matters” under Item 1.

 

Most of our federal coal leases have an initial term of 20 years and are renewable for subsequent 10-year periods and for so long thereafter as coal is produced in commercial quantities. These leases require diligent development within the first ten years of the lease award with a required coal extraction of 1.0% of the total coal under the lease by the end of that 10-year period. At the end of the 10-year development period, the lessee is required to maintain continuous operations, as defined in the applicable leasing regulations. In certain cases a lessee may combine contiguous leases into a logical mining unit, which we refer to as 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. Some of our mines are also subject to coal leases with applicable state regulatory agencies 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.

 

On January 15, 2016, the federal government ordered a moratorium on new leases for coal mined from federal lands as part of a review of the government’s management of federally-owned coal.  The review could take the form of a programmatic environmental impact statement, which allows a broader look at all aspects of federal coal leasing across regions and can incorporate environmental and health impacts as well as financial ones.  The last review on this scale occurred in the 1980’s.  Please see “Our inability to acquire additional coal reserves or our inability to develop coal reserves in an economically feasible manner may adversely affect our business,” under Risks Related to Our Operations.

 

Title to Coal Property

 

Title to coal properties held by lessors or grantors to us and our subsidiaries and the boundaries of properties are normally verified at the time of leasing or acquisition. However, in cases involving less significant properties and consistent with industry practices, title and boundaries are not completely verified until such time as our independent operating

 

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subsidiaries prepare to mine such reserves. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to mine such reserves could be adversely affected. You should see “A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine our coal reserves or result in significant unanticipated costs” contained in Item 1A, “Risk Factors” for more information.

 

At December 31, 2015, approximately 23% of our coal reserves were held in fee, with the balance controlled by leases, most of which do not expire until the exhaustion of mineable and merchantable coal. Under current mining plans, substantially all reported leased reserves will be mined out within the period of existing leases or within the time period of assured lease renewals. Royalties are paid to lessors either as a fixed price per ton or as a percentage of the gross sales price of the mined coal. The majority of the significant leases are on a percentage royalty basis. In some cases, a payment is required, payable either at the time of execution of the lease or in annual installments. In most cases, the prepaid royalty amount is applied to reduce future production royalties.

 

From time to time, lessors or sublessors of land leased by our subsidiaries have sought to terminate such leases on the basis that such subsidiaries have failed to comply with the financial terms of the leases or that the mining and related operations conducted by such subsidiaries are not authorized by the leases. Some of these allegations relate to leases upon which we conduct operations material to our consolidated financial position, results of operations and liquidity, but we do not believe any pending claims by such lessors or sublessors have merit or will result in the termination of any material lease or sublease.

 

We leased approximately 65,886 acres of property to other coal operators in 2015. We received royalty income of $6.3 million in 2015 from the mining of approximately 2.1 million tons, $9.6 million in 2014 from the mining of approximately 2.6 million tons and $9.5 million in 2013 from the mining of approximately 2.8 million tons on those properties. We have included reserves at properties leased by us to other coal operators in the reserve figures set forth in this report.

 

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ITEM 3.   LEGAL PROCEEDINGS.

 

In addition to the following matters, we are involved in various claims and legal actions arising in the ordinary course of business, including employee injury claims. After conferring with counsel, it is the opinion of management that the ultimate resolution of these claims, to the extent not previously provided for, will not have a material adverse effect on our consolidated financial condition, results of operations or liquidity.

 

Permit Litigation Matters

 

Surface mines at our Mingo Logan and Coal-Mac mining operations were identified in an existing lawsuit brought by the Ohio Valley Environmental Coalition (OVEC) in the U.S. District Court for the Southern District of West Virginia as having been granted Clean Water Act § 404 permits by the Army Corps of Engineers (Corps), allegedly in violation of the Clean Water Act and the National Environmental Policy Act. The lawsuit, brought by OVEC in September 2005, originally was filed against the Corps for permits it had issued to four subsidiaries of a company unrelated to us or our operating subsidiaries. The suit claimed that the Corps had issued permits to the subsidiaries of the unrelated company that did not comply with the National Environmental Policy Act and violated the Clean Water Act.

 

The court ruled on the claims associated with those four permits in orders of March 23 and June 13, 2007. In the first of those orders, the court rescinded the four permits, finding that the Corps had inadequately assessed the likely impact of valley fills on headwater streams and had relied on inadequate or unproven mitigation to offset those impacts. In the second order, the court entered a declaratory judgment that discharges of sediment from the valley fills into sediment control ponds constructed in-stream to control that sediment must themselves be permitted under a different provision of the Clean Water Act, § 402, and meet the effluent limits imposed on discharges from these ponds. Both of the district court rulings were appealed to the U.S. Court of Appeals for the Fourth Circuit.

 

Before the court entered its first order, the plaintiffs were permitted to amend their complaint to challenge the Coal-Mac and Mingo Logan permits. Plaintiffs sought preliminary injunctions against both operations, but later reached agreements with our operating subsidiaries that have allowed mining to progress in limited areas while the district court’s rulings were on appeal. The claims against Coal-Mac were thereafter dismissed.

 

In February 2009, the Fourth Circuit reversed the district court. The Fourth Circuit held that the Corps’ jurisdiction under Section 404 of the Clean Water Act is limited to the narrow issue of the filling of jurisdictional waters. The court also held that the Corps’ findings of no significant impact under the National Environmental Policy Act and no significant degradation under the Clean Water Act are entitled to deference. Such findings entitle the Corps to avoid preparing an environmental impact statement, the absence of which was one issue on appeal. These holdings also validated the type of mitigation projects proposed by our operations to minimize impacts and comply with the relevant statutes. Finally, the Fourth Circuit found that stream segments, together with the sediment ponds to which they connect, are unitary “waste treatment systems,” not “waters of the United States,” and that the Corps had not exceeded its authority in permitting them.

 

OVEC sought rehearing before the entire appellate court, which was denied in May 2009, and the decision was given legal effect in June 2009. An appeal to the U.S. Supreme Court was then filed in August 2009. On August 3, 2010 OVEC withdrew its appeal.

 

Mingo Logan filed a motion for summary judgment with the district court in July 2009, asking that judgment be entered in its favor because no outstanding legal issues remained for decision as a result of the Fourth Circuit’s February 2009 decision. By a series of motions, the United States obtained extensions and stays of the obligation to respond to the motion in the wake of its letters to the Corps dated September 3 and October 16, 2009 (discussed below). By order dated April 22, 2010, the district court stayed the case as to Mingo Logan for the shorter of either six months or the completion of the U.S. Environmental Protection Agency’s (EPA) proposed action to deny Mingo Logan the right to use its Corps’ permit (as discussed below).

 

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On October 15, 2010, the United States moved to extend the existing stay for an additional 120 days (until February 22, 2011) while the EPA Administrator reviewed the “Recommended Determination” issued by the EPA Region 3. By Memorandum Opinion and Order dated November 2, 2010, the court granted the United States’ motion. On January 13, 2011, the EPA issued its “Final Determination” to withdraw the specification of two of the three watersheds as a disposal site for dredged or fill material approved under the current Section 404 permit. The court was notified of the Final Determination and by order dated March 21, 2011 stayed further proceedings in the case until further order of the court, in light of the challenge to the EPA’s “Final Determination” then pending in federal court in Washington, D.C. In a Memorandum and Opinion and separate Order, each dated March 23, 2012, the federal court granted Mingo Logan’s motion for summary judgment, vacated EPA’s Final Determination and found valid and in full force Mingo Logan’s Section 404 permit. As described more fully below, the EPA appealed that order to the United States Court of Appeals for the D.C. Circuit and by Opinion of the Court dated April 23, 2013, the court reversed the lower court’s order and remanded the matter to the district court for further proceedings.

 

On April 5, 2012, Mingo Logan moved to lift the stay referenced above. On June 5, 2012, the court entered an order lifting the stay and allowing the case to proceed on Mingo Logan’s Motion for Summary Judgment. Shortly thereafter, OVEC filed a motion for leave to file a seventh amended and supplemental complaint seeking to update existing counts and raising two new claims (one, to enforce EPA’s “Final Determination” and, the other, that the Corps’ refusal to prepare a Supplemental Environmental Impact Statement violates the APA and NEPA). By Memorandum, Opinion and Order dated July 25, 2012, the court granted OVEC’s motion and directed the Clerk to file OVEC’s Seventh Amended and Supplemental Complaint. Mingo Logan filed its Motion for Summary Judgment on August 31, 2012, along with its Answer to the Seventh Amended and Supplemental Complaint and the matter remains pending before the court.

 

As a result of the Bankruptcy Petitions, much of the pending litigation against the Debtors is stayed.  Subject to certain exceptions and approval by the Court, during the Chapter 11 process, no party can take further actions to recover pre-petition claims against the Debtors.

 

EPA Actions Related to Water Discharges from the Spruce Permit

 

By letter of September 3, 2009, the EPA asked the Corps of Engineers to suspend, revoke or modify the existing permit it issued in January 2007 to Mingo Logan under Section 404 of the Clean Water Act, claiming that “new information and circumstances have arisen which justify reconsideration of the permit.” By letter of September 30, 2009, the Corps of Engineers advised the EPA that it would not reconsider its decision to issue the permit. By letter of October 16, 2009, the EPA advised the Corps that it has “reason to believe” that the Mingo Logan mine will have “unacceptable adverse impacts to fish and wildlife resources” and that it intends to issue a public notice of a proposed determination to restrict or prohibit discharges of fill material that already are approved by the Corps’ permit. By federal register publication dated April 2, 2010, the EPA issued its “Proposed Determination to Prohibit, Restrict or Deny the Specification, or the Use for Specification of an Area as a Disposal Site: Spruce No. 1 Surface Mine, Logan County, WV” pursuant to Section 404(c) of the Clean Water Act, the EPA accepted written comments on its proposed action (sometimes known as a “veto proceeding”), through June 4, 2010 and conducted a public hearing, as well, on May 18, 2010. We submitted comments on the action during this period. On September 24, 2010, the EPA Region 3 issued a “Recommended Determination” to the EPA Administrator recommending that the EPA prohibit the placement of fill material in two of the three watersheds for which filling is approved under the current Section 404 permit. Mingo Logan, along with the Corps, West Virginia DEP and the mineral owner, engaged in a consultation with the EPA as required by the regulations, to discuss “corrective action” to address the “unacceptable adverse effects” identified. On January 13, 2011, the EPA issued its “Final Determination” pursuant to Section 404(c) of the Clean Water Act to withdraw the specification of two of the three watersheds approved in the current Section 404 permit as a disposal site for dredged or fill material. By separate action, Mingo Logan sued the EPA on April 2, 2010 in federal court in Washington, D.C. seeking a ruling that the EPA has no authority under the Clean Water Act to veto a previously issued permit (Mingo Logan Coal Company, Inc. v. USEPA, No. 1:10-cv-00541(D.D.C.)). The EPA moved to dismiss that action, and we responded to that motion.

 

Pursuant to a scheduling order for summary disposition of the case, motions and cross-motions for summary judgment by both parties were filed. On November 30, 2011, the court heard arguments from the parties limited only to the threshold

 

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issue of whether the EPA had the authority under Section 404(c) of the Clean Water Act to withdraw the specification of the disposal site after the Corps had already issued a permit under Section 404(a). The court deferred consideration of the remaining issue (i.e. whether the EPA’s “Final Determination” is otherwise lawful) until after consideration of the threshold issue. On March 23, 2012, the court entered an Order and a Memorandum Opinion granting Mingo Logan’s motion for summary judgment, denying the EPA’s cross-motion for summary judgment, vacating the Final Determination and ordering that Mingo Logan’s Section 404 permit remains valid and in full force.

 

On May 11, 2012, the EPA filed a notice of appeal to the United States Court of Appeals for the District of Columbia Circuit. The court heard oral arguments on March 14, 2013. By opinion of the court filed on April 23, 2013, the court reversed the district court on the threshold issue and remanded the matter to the district court to address the merits of our APA challenge to the Final Determination. On June 6, 2013, Mingo Logan filed a Petition for Rehearing En Banc and by Order filed July 25, 2013, the court denied the petition.

 

On November 13, 2013, Mingo Logan filed a Petition for Writ of Certiorari with the Supreme Court of the United States seeking review of the D.C. Circuit’s decision. On March 24, 2014, the Supreme Court denied Mingo Logan’s Petition for Writ of Certiorari and remanded the matter to the federal district court for the District of Columbia for further consideration on the merits of the Final Determination. On September 30, 2014, the court entered an opinion and order denying Mingo Logan’s motion for summary judgment and granting the government’s motion for summary judgment. The court upheld the Final Determination finding that EPA’s decision to withdraw the specifications for filling in Oldhouse Branch and Pigeonroost Branch under Mingo Logan’s Section 404 permit was not arbitrary and capricious. On November 11, 2014, Mingo Logan filed a notice of appeal to the United States Court of Appeals for the District of Columbia Circuit.  The matter is fully briefed and oral argument is scheduled for April 11, 2016.

 

UMWA 1974 Pension Plan et al. v Peabody Energy and Arch

 

On July 16, 2015, the UMWA 1974 Pension Trust (“Plan”) and its Trustees filed a Complaint for Declaratory Judgment against Peabody Energy Corporation, Peabody Holding Company, LLC and Arch, in the U.S. District Court in Washington D.C., seeking an order from the court requiring the defendants to submit to arbitration to determine their responsibility for pension withdrawal liability (triggered by Patriot Coal Corporation’s (“Patriot”) recent bankruptcy filing) for Plan participants of Patriot who formerly worked for Peabody and Arch subsidiaries.  In the alternative, the complaint asks the court to declare that Peabody and Arch are liable for Patriot’s withdrawal liability. With respect to Arch, plaintiffs allege that Arch engaged in actions to avoid and evade pension fund withdrawal liability when it sold subsidiaries that were signatory to UMWA agreements, to Magnum Coal Company (“Magnum”) in 2005, allegedly in violation of ERISA law.  Patriot subsequently purchased Magnum in 2008.  On October 29, 2015, plaintiffs filed an amended complaint to reflect that Patriot formally rejected its obligations to contribute to the Plan, triggering a withdrawal.  The amended complaint further alleged that Arch owes $299.8 million in withdrawal liability.  On October 29, 2015, the UMWA Funds issued a letter to Arch demanding payment of this withdrawal liability amount.  We believe there is no basis in the law to support any claim that Arch is responsible for Patriot’s withdrawal liability and we plan to vigorously defend this complaint.  Arch notified the District Court and the parties to the litigation of its bankruptcy filing and the automatic stay and, on January 21, 2016, the plaintiffs agreed that the automatic stay in the Chapter 11 Case applies to Arch and its affiliates that have filed bankruptcy petitions.

 

ITEM 4.           MINE SAFETY DISCLOSURES.

 

The statement 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 to this Annual Report on Form 10-K for the period ended December 31, 2015.

 

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PART II

 

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

 

Market for Registrant’s Common Equity and Related Stockholder Matters

 

On January 11, 2016, the New York Stock Exchange (NYSE) determined that Arch was no longer suitable for listing pursuant to Section 8.02.01D of the NYSE continued listing standards, and trading of the Company’s common stock was suspended.  Our stock is now traded under the ticker symbol “ACIIQ” on the OTC Pink marketplace, operated by OTC Markets Group Inc.  Prior to January 11, 2016, our common stock was traded on the NYSE under the symbol “ACI.”  On February 12, 2016, our common stock closed at $0.47 on the OTC Pink.  On that date, there were approximately 5,400 holders of record of our common stock.

 

On August 4, 2015, the Company effected a 1-for-10 reverse stock split of its common stock.  Each stockholder’s percentage ownership and proportional voting power remain unchanged as a result of the reverse stock split.  All applicable share data, per share amounts and related information enclosed have been adjusted retroactively to give effect to the 1-for-10 reverse stock split.

 

In 2014, we paid an annual dividend on our common stock totaling $2.1 million, or $0.10 per share.  In 2015 we did not pay an annual dividend.  We are prohibited from paying dividends on our common stock during Chapter 11.

 

We expect that the existing common stock of the Company will be extinguished upon the Company’s emergence from Chapter 11, and existing equity holders will likely not receive consideration in respect of their equity interests.

 

The following table sets forth for each period indicated the dividends paid per common share, the high and low sale prices of our common stock for each of the quarterly periods indicated.

 

 

 

2015

 

 

 

March 31

 

June 30

 

September 30

 

December 31

 

Dividends per common share

 

$

 

$

 

$

 

$

 

High

 

16.80

 

11.10

 

9.31

 

4.66

 

Low

 

8.20

 

3.40

 

1.05

 

0.84

 

 

 

 

2014

 

 

 

March 31

 

June 30

 

September 30

 

December 31

 

Dividends per common share

 

$

0.10

 

$

 

$

 

$

 

High

 

48.20

 

51.80

 

36.70

 

28.60

 

Low

 

38.81

 

32.30

 

20.80

 

15.00

 

 

Issuer Purchases of Equity Securities

 

In September 2006, our board of directors authorized a share repurchase program for the purchase of up to 1,400,000 shares of our common stock.  We did not purchase any shares of our common stock under this program during the fiscal year ended December 31, 2015.  As of December 31, 2015, we have purchased 307,420 shares of our common stock under this program since the board of directors authorized the program.  We are prohibited from purchasing shares under this program during Chapter 11.

 

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ITEM 6.  SELECTED FINANCIAL DATA.

 

 

 

 

 

Year Ended December 31

 

(In thousands, except per share data)

 

2015

 

2014

 

2013

 

2012

 

2011

 

 

 

(1)

 

 

 

(3)

 

(4)

 

(5)

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

2,573,260

 

$

2,937,119

 

$

3,014,357

 

$

3,768,126

 

$

3,883,039

 

Mine closure and asset impairment costs

 

2,628,303

 

24,113

 

220,879

 

539,182

 

7,316

 

Goodwill impairment

 

 

 

265,423

 

330,680

 

 

Acquisition and transition costs

 

 

 

 

 

47,360

 

Income (loss) from operations

 

(2,865,063

)

(149,531

)

(663,141

)

(757,012

)

343,061

 

Interest expense

 

(397,979

)

(390,946

)

(381,267

)

(317,615

)

(230,186

)

Non-operating expenses

 

(27,910

)

 

(42,921

)

(23,668

)

(51,448

)

Income (loss) from continuing operations

 

(2,913,142

)

(558,353

)

(745,228

)

(738,915

)

89,015

 

Diluted earnings (loss) from continuing operations per common share

 

$

(136.86

)

$

(26.31

)

$

(35.15

)

$

(34.97

)

$

4.60

 

Net income (loss) attributable to Arch Coal

 

(2,913,142

)

(558,353

)

(641,832

)

(683,955

)

141,683

 

Basic earnings (loss) per common share

 

$

(136.86

)

$

(26.31

)

$

(30.26

)

$

(32.36

)

$

7.45

 

Diluted earnings (loss) per common share

 

$

(136.86

)

$

(26.31

)

$

(30.26

)

$

(32.36

)

$

7.42

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

5,106,738

 

$

8,429,723

 

$

8,990,193

 

$

10,006,777

 

$

10,213,959

 

Working capital

 

(4,361,009

)

1,023,357

 

1,293,849

 

1,337,035

 

162,106

 

Current maturities of debt (2)

 

5,107,210

 

36,885

 

33,493

 

32,896

 

280,851

 

Long-term debt, less current maturities

 

30,953

 

5,123,485

 

5,118,002

 

5,085,879

 

3,762,297

 

Other long-term obligations

 

755,283

 

695,881

 

717,174

 

825,080

 

864,667

 

Noncurrent deferred income tax liability

 

 

422,809

 

413,546

 

664,182

 

976,753

 

Arch Coal stockholders’ equity

 

(1,244,289

)

1,668,154

 

2,253,249

 

2,854,567

 

3,578,040

 

Common Stock Data:

 

 

 

 

 

 

 

 

 

 

 

Dividends per share

 

$

 

$

0.10

 

$

1.20

 

$

2.00

 

$

4.30

 

Shares outstanding at year-end

 

21,446

 

21,227

 

21,228

 

21,225

 

21,167

 

Cash Flow Data:

 

 

 

 

 

 

 

 

 

 

 

Cash provided by operating activities

 

(44,367

)

(33,582

)

55,742

 

332,804

 

642,242

 

Depreciation, depletion and amortization, including amortization of acquired sales contracts, net

 

370,534

 

405,561

 

438,247

 

500,319

 

444,518

 

Capital expenditures

 

119,024

 

147,286

 

296,984

 

395,225

 

540,936

 

Acquisitions of businesses, net of cash acquired

 

 

 

 

 

2,894,339

 

Net proceeds from the issuance of long term debt

 

 

(4,519

)

623,511

 

1,942,685

 

1,906,306

 

Net proceeds from the sale of common stock

 

 

 

 

 

1,267,933

 

Payments to retire debt, including redemption premium

 

 

 

628,660

 

452,934

 

605,178

 

Net increase (decrease) in borrowings under lines of credit and commercial paper program

 

 

 

 

(481,300

)

424,396

 

Dividend payments

 

 

2,123

 

25,475

 

42,440

 

80,748

 

Operating Data:

 

 

 

 

 

 

 

 

 

 

 

Tons sold

 

127,632

 

134,360

 

139,607

 

140,820

 

156,897

 

Tons produced

 

126,820

 

132,614

 

136,613

 

135,934

 

151,829

 

Tons purchased from third parties

 

1,287

 

1,182

 

2,925

 

4,327

 

5,557

 

 

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(1)         Our results in 2015 were impacted by further weakening of both the thermal and metallurgical coal markets.  We incurred $2.6 billion of mine closure and asset impairment charges during the year; for additional information see Note 5 to the Consolidated Financial Statements, “Impairment Charges and Mine Closure Costs.”

(2)         The filing of the Bankruptcy Petitions constituted an event of default that accelerated our obligations under the documents governing each of our 7.00% senior notes due 2019, 9.875% senior notes due 2019, 8.00% senior secured second lien notes due 2019, 7.25% senior notes due 2020, 7.25% senior notes due 2021 and senior secured first lien term loan due 2018.

(3)         As part of a strategy to divest non-core thermal coal assets, on August 16, 2013, we sold Canyon Fuel Company, LLC (“Canyon Fuel”) to Bowie Resources, LLC for $423 million.  Canyon Fuel operated the Sufco and Skyline longwall mining complexes and the Dugout Canyon continuous miner operation in Utah.  We recognized a gain on the sale of Canyon Fuel, net of tax, of $77.0 million during the third quarter of 2013.  See Note 3 to the Consolidated Financial Statements, “Divestitures,” for further information.

(4)         Our results in 2012 were impacted by challenging market conditions.  In response to these conditions, we idled 10 mines in Appalachia and curtailed production at other thermal mines. We incurred $523.6 million of closure and impairment costs relating to the closures, and recognized goodwill impairment charges $330.7 million.  In addition, we refinanced our debt, increasing our average borrowing level to build cash and highly liquid investments on the balance sheet as well as to decrease near-term maturities of debt.

(5)         On June 15, 2011, we completed our acquisition of ICG, a leading coal producer, adding 12 mining complexes in Appalachia, one complex in the Illinois Basin and one mine under development in Appalachia, along with other coal reserves not currently in development. To finance the acquisition, we sold 48.7 million shares of our common stock and issued $2.0 billion in aggregate principal amount of senior unsecured notes. We directly expensed costs related to the financing and acquisition of $104.2 million.

 

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

 

Overview

 

Our results in 2015 were impacted by further weakening of both the thermal and metallurgical coal markets.  The domestic thermal market was depressed by low natural gas prices and the implementation of new environmental regulations.  Abundant supply depressed natural gas pricing to levels that made it increasingly economical to dispatch for electric generation relative to thermal coal.  Implementation of the MATS regulation resulted in the closure of some older coal-based generating facilities, further depressing domestic thermal coal demand.  Pricing in international thermal coal markets was uneconomic for our operations throughout 2015.

 

Metallurgical coal markets continued to weaken due to oversupply.  International metallurgical markets have been impacted by the economic slowdown in China and elsewhere.  Furthermore, producers in the U.S. have been pressured by the strengthening of the United States dollar compared to other producing countries’ currencies.  Many foreign producers benefited significantly from this strengthening as much of their cost structure is tied to their local currencies, but their revenue is largely generated in United States dollars.  Additionally, domestic demand for metallurgical coal softened in 2015 as blast furnace utilization has dropped, largely due to declining demand for steel in the oil and gas industry.

 

Despite lower volumes, we reduced cash costs per ton in our Powder River Basin and Appalachian regions compared to 2014.  In Appalachia we shifted production to lower cost operations, particularly the Leer Mine, and in the Powder River Basin we benefited from lower diesel fuel pricing.  Both regions benefited from a strong focus on cost control.  We continue cost control efforts throughout the business, and further reduced our capital outlays from 2014 levels.

 

On January 11, 2016 (the “Petition Date”), Arch and substantially all of its wholly owned domestic subsidiaries (the “Filing Subsidiaries” and, together with Arch, the “Debtors”) filed voluntary petitions for reorganization (collectively, the

 

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“Bankruptcy Petitions”) under Chapter 11 of Title 11 of the U.S. Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Eastern District of Missouri (the “Court”). The Debtor’s Chapter 11 Cases (collectively, the “Chapter 11 Cases”) are being jointly administered under the caption In re Arch Coal, Inc., et al. Case No. 16-40120 (lead case). Each Debtor will continue to operate its business as a “debtor in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Court.

 

The filing of the Bankruptcy Petitions constituted an event of default that accelerated Arch’s obligations under the Debt Instruments, all as further described in Note 26, “Subsequent Events”, to the Consolidated Financial Statements included in the Form 10-K. Pursuant to the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically stayed most actions against the Debtors, including most actions to collect indebtedness incurred prior to the Petition Date or to exercise control over the Debtors’ property.

 

Additionally, on the Petition Date, the New York Stock Exchange (the “NYSE”) determined that our common stock was no longer suitable for listing pursuant to Section 8.02.01D of the NYSE continued listing standards and trading in our common stock was suspended on  January 11, 2016.  We expect that the existing common stock of the Company will be extinguished upon the Company’s emergence from Chapter 11 and existing equity holders will not receive consideration in respect of their equity interests.

 

We expect that our financial results will be significantly impacted by the filing of the Bankruptcy Petitions.  For example, the Debtors’ pre-petition unsecured obligations are subject to compromise and may be settled under a plan of reorganization for lesser amounts than the original claims. These liabilities remain subject to future adjustments arising from negotiated settlements, actions of  the Court, rejection of executory contracts and unexpired leases, the determination as to the value of collateral securing the claims, proofs of claim, or other events. Additionally, under Section 502(b)(2) of the Bankruptcy Code, we are no longer required to pay interest on our senior unsecured notes and our senior secured notes accruing on or after the Petition Date. Subject to certain exceptions under the Bankruptcy Code, the filing of the Debtors’ Chapter 11 Cases pursuant to Section 362(a) of the Bankruptcy Code also automatically stayed the continuation of most legal proceedings, including the third party litigation matters described under Item 3, “Legal Proceedings—Permit Litigation Matters,” or the filing of other actions against or on behalf of the Debtors or their property to recover on, collect or secure a claim arising prior to the Petition Date or to exercise control over property of the Debtors’ bankruptcy estates, unless and until the Court modifies or lifts the automatic stay as to any such claim. The determination of how liabilities will ultimately be treated cannot be made until the Court approves a plan of reorganization. Accordingly, the ultimate amount or treatment of such liabilities is not determinable at this time.

 

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Operational Performance

 

The following table shows operating results of continuing coal operations for the years ended December 31, 2015, 2014 and 2013. The “other” category includes the results of our other bituminous thermal operations, our West Elk mining complex in Colorado and our Viper mining complex in Illinois.

 

 

 

Year Ended December 31,

 

 

 

2015

 

2014

 

2013

 

Powder River Basin

 

 

 

 

 

 

 

Tons sold (in thousands)

 

108,481

 

111,156

 

111,653

 

Coal sales per ton sold

 

$

13.15

 

$

12.86

 

$

12.44

 

Cost per ton sold

 

$

12.36

 

$

12.58

 

$

12.18

 

Operating margin per ton sold

 

$

0.79

 

$

0.28

 

$

0.26

 

Adjusted EBITDA (in thousands)

 

$

258,300

 

$

197,920

 

$

206,910

 

Appalachia

 

 

 

 

 

 

 

Tons sold (in thousands)

 

11,926

 

14,484

 

14,224

 

Coal sales per ton sold

 

$

62.47

 

$

68.77

 

$

73.07

 

Cost per ton sold

 

$

69.19

 

$

77.59

 

$

81.27

 

Operating loss per ton sold

 

$

(6.72

)

$

(8.82

)

$

(8.20

)

Adjusted EBITDA (in thousands)

 

$

82,837

 

$

109,053

 

$

88,883

 

Other

 

 

 

 

 

 

 

Tons sold (in thousands)

 

7,225

 

8,720

 

8,422

 

Coal sales per ton sold

 

$

30.99

 

$

30.78

 

$

32.63

 

Cost per ton sold

 

$

27.83

 

$

25.44

 

$

26.95

 

Operating margin per ton sold

 

$

3.16

 

$

5.34

 

$

5.68

 

Adjusted EBITDA (in thousands)

 

$

17,044

 

$

58,325

 

$

91,642

 

 

This table reflects numbers reported under a basis that differs from U.S. GAAP.  See the “Reconciliation of Non-GAAP measures” below for explanation and reconciliation of these amounts to the nearest GAAP figures.  Other companies may calculate these per ton amounts differently, and our calculation may not be comparable to other similarly titled measures.

 

Powder River Basin — Adjusted EBITDA increased 31% in 2015 when compared to 2014 due to increased coal sales per ton sold and decreased cost per ton sold, partially offset by lower shipment volume.  Pricing improved as a significant portion of 2015 shipments were priced following the harsh 2013-2014 winter season when the market was stronger.  Cost benefited from lower diesel fuel pricing and ongoing cost control efforts.  Shipment volume was favorable year over year through the first three quarters of 2015, but fell off significantly in the fourth quarter of 2015, reducing full year shipment volume below 2014 levels.  Natural gas pricing fell to historically low levels as the 2015 winter season began mildly, and the competing fuel began to dispatch for electrical generation ahead of Power River Basin coal in some areas. This decrease in coal burn has led to increasing generator stockpiles, further depressing demand.

 

Adjusted EBITDA decreased in 2014 when compared to 2013 due to a slight decrease in shipment volume and higher cost per ton sold, partially offset by increased coal sales per ton sold.  Pricing improved as low-priced export volume decreased and domestic markets firmed in 2014.  Maintenance costs increased in anticipation of increased shipment volume; however, railroad performance issues negatively impacted Powder River Basin shipment volumes for much of 2014.

 

Appalachia —Adjusted EBITDA decreased 24% in 2015 when compared to 2014 due primarily to the gain on sale of operating and idled thermal coal mines in Kentucky in 2014 ($20.6 million).  See Note 3, “Divestitures,” to the Consolidated Financial Statements for further discussion.  2015 adjusted EBITDA was also negatively impacted by reduced volume and reduced coal sales per ton sold, partially offset by decreased cost per ton sold.  Volume was negatively impacted by the asset sales previously mentioned and further deterioration in both the thermal and metallurgical markets.  We were able to partially offset the effects of the negative volume and pricing through productivity gains and continuing to shift volume to lower cost operations.  Longwall operations accounted for 41% of our shipment volume in 2015 versus 31% in 2014.

 

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Adjusted EBITDA increased in 2014 when compared to 2013 due to the gain on sale of operating and idled thermal coal mines in Kentucky ($20.6 million).  See Note 3, “Divestitures,” to the Consolidated Financial Statements for further discussion.  The gains were partially offset by the impact of an increase in per ton operating losses, caused by lower pricing for both metallurgical and thermal coal.  The startup of the longwall at the Leer mining complex, the idling and divesting of higher-cost production, and lower sales-sensitive costs contributed to lower per-ton costs, which largely offset the impact of lower sales pricing.

 

Other — Adjusted EBITDA decreased in 2015 and 2014 when compared with the respective prior year due to reduced benefit from coal risk management settlements, and increased liquidated damages on logistics contracts.  2015 was also negatively impacted by reduced volume related to low-priced natural gas, and further deterioration of overseas markets.

 

Results of Operations

 

Items impacting comparability of results

 

We recorded tangible asset impairment and mine closure charges of approximately $2,628.3 million, $24.1 million, and $220.9 million during 2015, 2014 and 2013, respectively.

 

We recorded goodwill impairment charges of $265.4 million during 2013.

 

As part of a strategy to divest non-core thermal coal assets, on August 16, 2013, we sold Canyon Fuel Company, LLC (“Canyon Fuel”) to Bowie Resources, LLC for $422.7 million.  Canyon Fuel operated the Sufco and Skyline longwall mining complexes and the Dugout Canyon continuous miner operation in Utah.  We recognized a gain on the sale of Canyon Fuel, net of tax, of $77.0 million.  The results of Canyon Fuel, including the gain on sale, are presented as discontinued operations.  See Note 3 to the Consolidated Financial Statements, “Divestitures,” for further information.

 

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

 

Revenues.  Our revenues consist of coal sales and revenues from our ADDCAR subsidiary prior to its disposition in the first quarter of 2014.

 

Coal sales.  The following table summarizes information about our coal sales during the year ended December 31, 2015 and compares it with the information for the year ended December 31, 2014:

 

 

 

Year Ended December 31,

 

 

 

 

 

2015

 

2014

 

Increase (Decrease)

 

 

 

(In thousands)

 

Coal sales

 

$

2,573,260

 

$

2,935,181

 

$

(361,921

)

Tons sold

 

127,632

 

134,360

 

(6,728

)

 

Coal sales decreased in the year ended December 31, 2015 from the year ended December 31, 2014 on a consolidated basis, primarily due to lower tons sold and pricing in our Appalachian segment, resulting in approximately a $274 million reduction in coal sales revenue.  Volume reductions accounted for approximately 64% of the decrease and lower prices approximately 36% of the decrease.  Lower Powder River Basin and Other tons sold reduced coal sales approximately $34 million and $42 million, respectively.  See discussion in “Operational Performance” above for further information about regional results.

 

Costs, expenses and other.  The following table summarizes costs, expenses and other components of operating income for the year ended December 31, 2015 and compares it with the information for the year ended December 31, 2014:

 

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Year Ended December 31,

 

(Increase) Decrease

 

 

 

2015

 

2014

 

in Net Loss

 

 

 

(In thousands)

 

Cost of sales (exclusive of items shown separately below)

 

$

2,206,433

 

$

2,566,193

 

$

359,760

 

Depreciation, depletion and amortization

 

379,345

 

418,748

 

39,403

 

Amortization of acquired sales contracts, net

 

(8,811

)

(13,187

)

(4,376

)

Change in fair value of coal derivatives and coal trading activities, net

 

(1,583

)

(3,686

)

(2,103

)

Asset impairment and mine closure costs

 

2,628,303

 

24,113

 

(2,604,190

)

Losses from disposed operations resulting from Patriot Coal bankruptcy

 

116,343

 

 

(116,343

)

Selling, general and administrative expenses

 

98,783

 

114,223

 

15,440

 

Other operating expense (income), net

 

19,510

 

(19,754

)

(39,264

)

Total costs, expenses and other

 

$

5,438,323

 

$

3,086,650

 

$

(2,351,673

)

 

Cost of sales.  Our cost of sales decreased in the year ended December 31, 2015 from the year ended December 31, 2014, due to lower transportation costs on lower export sales volumes (a decrease of approximately $66 million), lower diesel fuel costs (approximately $88 million), improved productivity at our Leer longwall operation (approximately $28 million), savings associated with one sold and two idled Appalachian complexes (approximately $77 million), lower sales sensitive costs (approximately $30 million), and other savings associated with cost-control efforts across all regions. See discussion in “Operational Performance” above for information about regional cost results.

 

Depreciation, depletion and amortization.  When compared with the year ended December 31, 2014, depreciation, depletion and amortization costs decreased in the year ended December 31, 2015 due to the effect of lower production and sales volume, continued low capital spending levels, and the effect of the significant asset impairments at the end of the third quarter of 2015.

 

Asset impairment and mine closure costs. Continued market deterioration, particularly for Appalachian products, was an indicator of impairment of certain assets.  Our testing indicated impairment of several active and undeveloped properties.  Impairment costs in the year ended December 31, 2015 include a significant portion of our assets at three current operating complexes, and a significant portion of our undeveloped coal reserves value.  In the third quarter of 2014, we idled a metallurgical coal mining complex in Appalachia, where we had previously idled two contract mining operations. See Note 5, “Impairment Charges and Mine Closure Costs,” to the Consolidated Financial Statements for further discussion.

 

Losses from disposed operations relating to Patriot Coal bankruptcy.  In the year ended December 31, 2015 we recorded liabilities related to reclamation and employee obligations that we inherited as a result of the Patriot Coal bankruptcy.  See further information regarding the losses related to the Patriot Coal bankruptcy in Note 7, “Losses from disposed operations resulting from Patriot Coal bankruptcy” to the Consolidated Financial Statements.

 

Selling, general and administrative expenses.  Total selling, general and administrative expenses decreased when compared with the year ended December 31, 2014, primarily due to decreased compensation costs of $13.8 million.

 

Other operating expense (income), net.  When compared with the year ended December 31, 2014, other operating expense (income), net decreased during the year ended December 31, 2015, as a result of increased costs of $16.4 million related to shortfalls under throughput arrangements, and lower net gains from sales of assets of $37.1 million.  These were partially offset by a $24 million gain on a contract settlement in 2015.

 

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Non-operating expense. The following table summarizes non-operating expense for the year ended December 31, 2015 and compares it with the information for the year ended December 31, 2014:

 

 

 

 

 

 

 

(Increase) Decrease

 

 

 

Year Ended December 31,

 

in Net Loss

 

 

 

2015

 

2014

 

$

 

 

 

(In thousands)