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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, 2016 
or
( )
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-13105

https://cdn.kscope.io/68d9427cafb55572c10771a6ab4e536d-image0a09.jpg
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
NYSE
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 ¨

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 ¨ 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 ¨

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¨

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. x


 

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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
Accelerated filer ¨
Non-accelerated filer x
(Do not check if a smaller reporting company)
Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ 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, 2016 was approximately $6.4 million.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes x No ¨

At February 16, 2017 there were 25,001,819 shares of the registrant’s common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement to be filed with the Securities and Exchange Commission in connection with the 2017 annual stockholders’ meeting to be held on May 4, 2017 are incorporated by reference into Part III of this Form 10-K.


























 

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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 31 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 recent emergence from Chapter 11 bankruptcy protection;
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;
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 Term Loan Agreement, our Securitization Facility, other financing arrangements or any subsequent financing or credit facilities;
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;

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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;
our ability to continue as a going concern; 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, 2016, we sold approximately 94 million tons of coal, including approximately 0.7 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, 2016, we operated 12 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. We incorporate by reference the information about the geographical breakdown of our coal sales for the respective periods covered within this Form 10-K contained in Note 23 to the Consolidated Financial Statements.
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.
Restructuring Under Chapter 11 of the United States Bankruptcy Code
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 “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”) were jointly administered under the caption In re Arch Coal, Inc., et al. Case No. 16-40120 (lead case). During the bankruptcy proceedings, each Debtor operated 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.

On September 13, 2016, the Bankruptcy Court entered an order, Docket No. 1324, confirming the Debtors’ Fourth Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code dated as of September 11, 2016 (the “Plan”), which order was amended on September 15, 2016, Docket No. 1334.


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On October 5, 2016, Arch Coal emerged from Chapter 11 and the Plan became effective on such date (the “Effective Date”).

On the Plan Effective Date, we applied fresh start accounting which requires us to allocate our reorganization value to the fair value of assets and liabilities in conformity with the guidance for the acquisition method of accounting for business combinations. In addition to fresh start accounting, our consolidated financial statements reflect all impacts of the transactions contemplated by the Plan. Under the provisions of fresh start accounting, a new entity has been created for financial reporting purposes. We selected an accounting convenience date of October 1, 2016 for purposes of applying fresh start accounting as the activity between the convenience date and the Effective Date does not result in a material difference in the results. References to “Successor” in the financial statements and accompanying footnotes are in reference to reporting dates on or after October 2, 2016; references to “Predecessor” in the financial statements and accompanying footnotes are in reference to reporting dates through October 1, 2016 which includes the impact of the Plan provisions and the application of fresh start accounting. As such, our financial statements for the Successor will not be comparable in many respects to its financial statements for periods prior to the adoption of fresh start accounting and prior to the accounting for the effects of the Plan.

For additional information, see Note 1, “Basis of Presentation” and Note 3, “Emergence from Bankruptcy and Fresh Start Accounting” to our Consolidated Financial Statements included within this Form 10-K.

Coal Characteristics
End users generally characterize coal as thermal 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.

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The Coal Industry
Background. . Coal is mined globally using various methods of surface and underground recovery. Coal is used primarily for the production of electric power and steel but is also used for chemical, food and cement processing. Coal is traded globally and can be transported to demand centers by ship, rail, barge, truck or conveyor belt.
Total world coal production exceeds 7.0 billion metric tons according to the International Energy Agency (IEA). China is the largest producer of coal in the world, producing over 3.5 billion metric tons in 2016 according to the Chinese Bureau of Statistics. The United States and India follow China with total coal production of over 600 million metric tons in 2016 based on preliminary data.

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.

We produce coal used for electric power generation (thermal) and coal used in the production of steel (metallurgical.) All of our thermal coal production occurs in the United States at mines located in Wyoming, Colorado, Illinois, Kentucky and West Virginia. Metallurgical coal is produced at operations in West Virginia and Kentucky. Heat value and sulfur content are the most important variables in the economic marketing and transportation of thermal coal. Carbon content, the composition of the non-carbon volatiles and other chemical constituents are critical characteristics for metallurgical coal.

The majority of our coal is sold at the mine where title and risk of loss transfer to the customer as coal is loaded into the railcar or truck. Customers are responsible for transportation - typically using third party carriers. There are some agreements where we retain responsibility for the coal during delivery to the customer site or intermediate terminal. Our international coal usually changes title and risk of loss as coal is loaded on an ocean vessel. We or our agent contracts for transportation services to the ocean loading port. On rare occasion, we might retain title to the coal to the ocean delivery port.

We seek to establish long-term relationships with customers through exemplary customer service while operating safe and environmentally responsible mines. We shipped to 35 states and 19 countries. During the year, we supplied coal to 117 domestic and 27 foreign customers. In 2016, approximately 92% of our coal sales volume was sold as a thermal product with the remaining 8% as metallurgical.

Coal was used to produce approximately 31% of the electric power generated in the U.S. in 2016 based on preliminary data from the Energy Information Administration (EIA.) The coal we produced fueled approximately 4% of the electricity produced in the U.S. in 2016. We also exported 7% of our production to customers outside the U.S. in 2016.

We rank among the largest metallurgical coal producers in the U.S. Based on internal estimates, we produced close to 10% of total U.S. metallurgical coal in 2016. Our metallurgical coal was sold to six domestic customers and shipped to 16 international destinations in 2016.

We operate in a very competitive environment. We compete with domestic and international coal producers, traders or brokers as well as producers of other energy sources including natural gas, renewables and nuclear, as well as other non-coal based forms of steel production. We compete with other coal producers and traders/brokers using price, coal quality, transportation, optionality, customer administration, reputation and reliability.

Coal demand and coal prices are tied to coal consumption patterns which are influenced by many uncontrollable factors. For power generation, the price of coal is affected by the relative supply and demand of competitive coal, transportation, availability and price of other non-coal forms of power production, regulatory limits on using coal, taxes, the weather and economic conditions. For metallurgical coal, the price of coal is affected by the supply, demand and price of competitive coal, transportation, the price of steel, demand for steel, as well as regulations, taxes, and economic conditions.

We have an experienced and knowledgeable sales and marketing group. This group is dedicated to meeting customer needs, coordinating transportation, providing accounting services and managing risk.

U.S. Coal Production. The United States is among the top three largest coal producers in the world, exceeded only by China and roughly equivalent to India based on preliminary data. According to the EIA, there are over 200 billion short 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 Mine Safety and Health Administration (MSHA), U.S. coal production declined by an estimated 170 million tons in 2016, to 726 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 507 million short tons in 2015 to 407 million short tons in 2016. 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 has a lower heat content, however it is produced from thick seams using surface recovery methods 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. Western bituminous coal has certain quality characteristics, especially its high heat content and low sulfur, that make this a desirable coal for domestic and international power producers.

The Appalachia region is divided into north, central and southern regions. According to the EIA, coal produced in the Appalachian region fell from 222 million short tons in 2015 to 183 million short tons in 2016. Appalachian coal is located near the prolific eastern shale-gas producing regions. Central Appalachian thermal coal is further disadvantaged for power generation because of the depletion of economically attractive reserves, permitting issues and increasing costs of production. However, all U.S. metallurgical coal is produced in Appalachia and the relative scarcity and high-quality of this coal allows for a pricing premium over thermal coal. Appalachia, while still a major producer of thermal coal, is undergoing a shift towards heavier reliance on metallurgical coal production for both domestic and international use. This is especially the case in Central Appalachia.

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 168 million short tons in 2015 to approximately 150 million short tons in 2016. 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.

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.
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.

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The following diagram illustrates a typical dragline surface mining operation:

https://cdn.kscope.io/68d9427cafb55572c10771a6ab4e536d-surfacemininga03.jpg

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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:
                        https://cdn.kscope.io/68d9427cafb55572c10771a6ab4e536d-longwallmininga03.jpg

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:
https://cdn.kscope.io/68d9427cafb55572c10771a6ab4e536d-roomandpillara08.jpg

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, 2016, we operated 12 active mines in the United States. The Company’s reportable business segments are based on two distinct lines of business, metallurgical and thermal, and may include a number of mine complexes. The Company manages its coal sales by market, not by individual mining complex. Geology, coal transportation routes to customers, and regulatory environments also have a significant impact on our marketing and operations management. Mining operations are evaluated based on Adjusted EBITDAR, per-ton cash operating costs (defined as including all mining costs except depreciation, depletion, amortization, accretion on asset retirements obligations, and pass-through transportation expenses), and on other non-financial measures, such as safety and environmental performance. Adjusted EBITDAR is not a measure of financial performance in accordance with generally accepted accounting principles, and items excluded from Adjusted EBITDAR are significant in understanding and assessing our financial condition. Therefore, Adjusted EBITDAR should not be considered in isolation, nor as an alternative to net income, income from operations, cash flows from operations or as a measure of our profitability, liquidity or performance under generally accepted accounting principles. The Company used Adjusted EBITDAR to measure the operating performance of its segments and allocate resources to the segments. Furthermore, analogous measures are used by industry analysts to evaluate the Company’s operating performance. Investors should be aware that the Company’s presentation of Adjusted EBITDAR may not be comparable to similarly titled measures used by other companies. The Company’s reportable segments are the Powder River Basin (PRB) segment containing the Company’s primary thermal operations in Wyoming; the Metallurgical (MET) segment, containing the Company’s metallurgical operations in West Virginia, Kentucky, and Virginia, and the Other Thermal segment containing the Company’s supplementary thermal operations in Colorado, Illinois, and the Coal Mac thermal operation in West Virginia. For additional information about the operating results of each of our segments for the periods October 2 through December 31, 2016, January 1 through October 1, 2016 and the years ended December 31, 2015 and 2014, see Note 25 of the Consolidated Financial Statements.
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.

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The following table provides a summary of information regarding our active mining complexes as of December 31, 2016, including the total sales associated with these complexes for the periods October 2 through December 31, 2016, January 1 through October 1, 2016 and for the years December 31, 2015 and 2014, and the total reserves associated with these complexes at December 31, 2016. 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.
 
 
 
 
Tons Sold(2)(3)
 
 
 
 
 
 
Predecessor
Successor
 
 
Mining Complex
Captive Mines(1)
Mining Equipment
Railroad
2014
2015
Jan1-Oct1, 2016
Oct2-Dec31, 2016
Total Cost of Property, Plant and Equipment at December 31, 2016
Total Assigned Recoverable Reserves
 
 
 
 
(Million tons)
($ millions)
(Million tons)
Powder River Basin:
 
 
 
 
 
 
 
 
 
Black Thunder
S
D, S
UP/BN
101.2

99.5

49.0

18.9

$
263.8

968.5

Coal Creek
S
D, S
UP/BN
9.4

7.8

5.5

2.7

43.1

146.0

Metallurgical:
 
 
 
 
 
 
 
 
 
Lone Mountain
U(3)
CM
NS/CSX
1.9

1.6

0.9

0.4

14.4

9.5

Mountain Laurel
U
LW, CM
CSX
1.7

2.0

1.2

0.4

24.0

13.2

Beckley
U
CM
CSX
1.0

0.9

0.7

0.3

34.9

24.5

Sentinel
U
CM
CSX
1.1

0.9

0.8

0.3

26.9

9.8

Leer
U
LW, CM
CSX
2.7

2.9

3.1

1.0

200.7

38.3

Other Thermal:
 
 
 
 
 
 
 
 
 
West Elk
U
LW, CM
UP
6.5

5.1

2.4

1.6

31.7

56.2

Viper
U
CM
2.2

2.1

1.3

0.3

20.5

38.3

Coal‑Mac
S
L, E
NS/CSX
2.8

2.4

1.5

0.5

30.2

23.0

Totals
 
 
 
130.5

125.2

66.4

26.4

$
690.2

1,327.3


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 mines, if more than one, at the mining complex as of December 31, 2016. Captive mines are mines that we own and operate 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)
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 in 2014. We sold 0.8 million tons of coal from these two mining complexes in 2014.

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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 thermal 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 968.5 million tons of proven and probable reserves at December 31, 2016. 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 thermal 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 146.0 million tons of proven and probable reserves at December 31, 2016. 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.
Metallurgical
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 PCI and high-quality thermal 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 9.5 million tons of proven and probable reserves at December 31, 2016.
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 High-vol B metallurgical coal and thermal coal from the Cedar Grove and Alma seams. The Mountain Laurel mining complex has approximately 13.2 million tons of proven and probable reserves at December 31, 2016.
The complex currently consists of one underground mine operating a longwall and three 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 19,500 acres in Raleigh County, West Virginia. Beckley is extracting high quality, low‑volatile metallurgical coal in the Pocahontas No. 3 seam. The Beckley mining complex had approximately 24.5 million tons of proven and probable reserves at December 31, 2016.
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.
Sentinel. The Sentinel mining complex consists of one underground mine, a preparation plant and a loadout facility located on approximately 25,500 acres in Barbour County, West Virginia. Mining operations currently extract High-vol A

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metallurgical 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. The Sentinel mining complex had approximately 9.8 million tons of proven and probable reserves at December 31, 2016.
Leer. The Leer Complex, located in Taylor County, West Virginia, includes approximately 38.3 million tons of coal reserves as of December 31, 2016 and has primarily High-vol A metallurgical quality coal in the Lower Kittanning seam, and is part of approximately 78,700 acres that is considered our Tygart Valley area. Substantially all of the reserves at Leer are owned rather than leased from third parties.
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.
Other Thermal
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 thermal 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 56.2 million tons of proven and probable reserves at December 31, 2016.
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 46,100 acres in central Illinois near the city of Springfield. Mining operations extract thermal 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, 2016, we had approximately 38.3 million tons of proven and probable reserves.
Coal‑Mac. The surface mining complex is located on approximately 46,000 acres in Logan and Mingo Counties, West Virginia. Surface mining operations at the Coal‑Mac mining complex extract thermal 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 23.0 million tons of proven and probable reserves at December 31, 2016.
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.
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 heat 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 one of our Appalachian mines. This is the case because of the higher

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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 sales personnel in our Singapore and London offices. In addition to selling coal produced from 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 thermal and metallurgical coal to steel producers, domestic and foreign power generators, and other industrial facilities. For the year ended December 31, 2016, we derived approximately 15% of our total coal revenues from sales to our three largest customers, Southern Company, U.S. Steel Canada Inc. and Tennessee Valley Authority and approximately 42% of our total coal revenues from sales to our 10 largest customers.
In 2016, we sold coal to domestic customers located in 35 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 2016 we also exported coal to Europe, Asia, North America (outside the United States) and South America. Exports to foreign countries were $0.5 billion, $0.4 billion and $0.6 billion for the years ended December 31, 2016, 2015 and 2014, respectively. As of December 31, 2016 and 2015, trade receivables related to metallurgical‑quality coal sales totaled $88.0 million and $32.8 million, respectively, or 48% and 28% of total trade receivables, respectively. 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, 2016, were as follows:
(In thousands)
 
Europe
$
175,296

Asia
124,170

Central and South America
55,085

North America
100,425

Brokered Sales

Total
$
454,976

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 2016, we sold approximately 76% 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, 2016, the average volume‑weighted remaining term of our long-term contracts was approximately 2.00 years, with remaining terms ranging from one to five years. At December 31, 2016, remaining tons under long-term supply agreements, including those subject to price re-opener or extension provisions, were approximately 119 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.

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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 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 thermal coal 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, 2016.
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, trucking 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

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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 an export terminal, and we are usually responsible for the cost of transporting coal to the export terminals. We transport our coal to Atlantic coast terminals, Pacific cost 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.
We own a 21.875% 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 primarily serves international customers, as well as domestic coal users located along the Atlantic coast of the United States.
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 Contura Energy, Coronado Coal LLC, 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. Expenditures we incur to maintain compliance with all applicable federal and state laws 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 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

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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 published the final revisions to the stream buffer zone rule in the Federal Register. The revisions reinstated the previous version of the rule, but did not announce a new interpretation of the rule regarding the ability to construct excess spoil fills. On December 19, 2016, OSM finalized the “Stream Protection Rule,” a re-written version of the stream buffer zone rule which would have required coal operators to restrict mining within 100 feet of waterways. The rule would have also required states to impose additional information gathering and monitoring at and around coal mining sties and would have mandated new financial assurance and reclamation requirements. This rule could have restricted coal producers’ ability to develop new mines, or could have required coal producers to modify existing operations, curtailing surface mine operations in and near streams, especially in Appalachia. However, on February 2, 2017, Congress voted to repeal the stream protection rule under the Congressional Review Act. President Trump signed the bill repealing the rule on February 16, 2017.
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

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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 2016, we recorded $23.6 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.
The costs of these bonds have fluctuated in recent years while the market terms of surety bonds have generally hardened for 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. As of December 31, 2016, we posted an aggregate of approximately $528.3 million in surety bonds for reclamation purposes and secured $54.7 million in letters of credit and cash for reclamation bonding obligations. In addition, we had approximately $199.2 million of surety bonds, cash and letters of credit outstanding at December 31, 2016 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.
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,

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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 2016, we recorded $47.6 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 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 the EPA, has issued regulations on additional emissions, such as greenhouse gases (GHG’s), 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. The 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. On November 17, 2016, the EPA issued a proposed implementation rule on non-attainment area classification an state implementation plans (SIPS). 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 and potential legislative action, with at least one bill introduced to delay the implementation deadline.

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.

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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 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 than 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 October 2016, the EPA issued 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. Consolidated judicial challenges to the rule are now pending. If upheld, it is likely the CSAPR update 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), which was promulgated to reduce mercury emissions from coal-fired power plants 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 the EPA’s failure to consider economic costs in determining whether to regulate. The case was remanded to the D.C. Circuit. The EPA began reconsideration of costs, and petitioners unsuccessfully sought a stay of the rule in the Supreme Court in February 2016. In April 2016, the EPA issued a final finding that it is appropriate and necessary to set standards for emissions of air toxics from coal- and oil-fired power plants. That finding is now being challenged in court. Therefore, the rule remains in effect until further order of the D.C. Circuit. The D.C. Circuit recently denied petitioners’ motion to temporarily halt the pending litigation to allow the new administration to evaluate whether it can resolve any issues raised in the case. 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

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reduce emissions and comply with stricter emission limitations. The vast majority of states failed to submit their 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).

The 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. The EPA has completed those actions for all but several states in its first planning period (2008-2010). In many eastern states, the 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 the EPA found SIPs deficient, it disapproved them and issued FIPs. It is possible that the EPA may continue to increase the stringency of control requirements imposed under the Regional Haze Program as it moves toward the next planning period, which could be delayed until 2021.

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.

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 warming, 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.
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

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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% by 2030 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 and is not revoked or revised by the current U.S. Presidential Administration, 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.
In a parallel litigation, 25 states and other parties filed lawsuits challenging the EPA’s final New Source Performance Standards rules, which we refer to as NSPS, for carbon dioxide emissions from new, modified, and reconstructed power plants under the Clean Air Act. One of the primary issues in these lawsuits is the EPA’s establishment of standards of performance based on technologies including carbon capture and sequestration, which we refer to as CCS. New coal plants cannot meet the new standards unless they implement CCS, which reportedly is not yet commercially available or technically feasible. Oral arguments in this case are scheduled for April 2017. Should the EPA’s regulations be upheld by the court, they could materially impact the ability of customers to build new, or modify or reconstruct existing, coal-fired power plants, and thus reduce the demand for coal.
In December 2015, 195 nations (including United States) signed the Paris Agreement, a long-term, international framework convention designed to address climate change over the next several decades. This agreement entered into force in November 2016 after more than 70 countries, including the United States, ratified or otherwise agreed to be bound by the agreement. The United States was among the countries that submitted its declaration of intended greenhouse gas reductions in early 2015, stating its intention to reduce U.S. greenhouse gas emissions by 26-28% by 2025 compared to 2005 levels. Whether and to what extent the United States meets its stated intention likely depends on several factors, including whether the presently-stayed Clean Power Plan (or a comparable alternative) is implemented. The Trump Administration reportedly is evaluating the United States’ continued participation in the Paris Agreement. Regardless of the extent to which the United States ultimately participates in these reductions, over the long term, international participation in the Paris Agreement framework could reduce overall demand for coal which could have a material adverse impact on us. These effects could be more adverse to the extent the United States ultimately participates in these reductions (whether via the Paris Agreement or otherwise).
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

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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 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. The federal district court for the Southern District of West Virginia has ruled in favor of the citizen suit groups in multiple suits alleging violations of the water quality standard for selenium and in two suits alleging violations of water quality standards due to discharge of conductivity (one of which was upheld on appeal by the United States Court of Appeals for the Fourth Circuit in January 2017). Additional rulings requiring operators to reduce their discharges of selenium, conductivity or sulfate could result in large treatment expenses for mine operators.
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. . Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous substances. In addition, each state has its own laws regarding the proper management and disposal of waste material. In June 2010, the EPA released a proposed rule to regulate the disposal of certain coal combustion residuals, which we refer to as CCR. The proposed rule set forth two very different options for regulating CCR under RCRA. The first option called for regulation of CCR as a hazardous waste under Subtitle C, which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option utilized Subtitle D, which would give the EPA authority to set performance standards for waste management facilities and would be enforced primarily through citizen suits. The proposal left intact the so-called Bevill exemption for beneficial uses of CCR. The EPA finalized the CCR rule on December 19, 2014, setting nationwide solid nonhazardous waste standards for CCR disposal. On April 17, 2015, the EPA finalized regulations under the solid waste provisions (Subtitle D) of RCRA and not the hazardous waste provisions (Subtitle C) which became effective on October 19, 2015. The final rule establishes national minimum criteria for existing and new CCR landfills, surface impoundments and lateral expansions, and also establishes structural integrity criteria for new and existing surface impoundments (including establishing requirements for owners and operators to conduct periodic structural integrity-related assessments). The criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post-closure care and recordkeeping, notification and internet posting requirements. While classification of CCR as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase our customers' operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, could lead to citizen suit enforcement against our customers under RCRA or other federal or state laws and potentially reduce the demand for coal. 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, 2016, we employed approximately 4,025 full and part‑time employees. We believe that our relations with employees are good.


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Executive Officers of the Registrant
The following is a list of our executive officers, their ages as of February 24, 2017 and their positions and offices during the last five years:
Name
Age
Position
Kenneth D. Cochran
56

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 Knight Hawk Holdings, LLC, and Tongue River Holding Company.
John T. Drexler
47

Mr. Drexler has served as our Senior Vice President and Chief Financial Officer since 2008. 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
59

Mr. Eaves has served as our Chief Executive Officer since 2012. Mr. Eaves served as our Chairman of the Board from 2015 to 2016 and our President and Chief Operating Officer from 2006 to 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 the National Association of Manufacturers and the National Mining Association. Mr. Eaves was previously a director of Advanced Emissions Solutions, Inc. and former chairman of the National Coal Council.
Robert G. Jones
60

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
56

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
56

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 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 the former chairman of the University of Wyoming’s School of Energy Resources Council.
Deck S. Slone
53

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 the immediate past co-chair of the Coal Utilization Research Council, the chair of the Coal Policy Committee of the National Coal Council, and a member of the steering committee of the Consortium for Clean Coal Utilization at Washington University in St. Louis.
John A. Ziegler, Jr.
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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 Emergence from Bankruptcy Protection

Information contained in our historical financial statements will not be comparable to the information contained in our financial statements after the application of fresh start accounting.

Following the consummation of the Plan, our financial condition and results of operations from and after the Effective Date are not be comparable to the financial condition or results of operations in our historical financial statements. As a result of our restructuring under Chapter 11 of the Bankruptcy Code, our financial statements are subject to fresh start accounting provisions of generally accepted accounting principles (“GAAP”). In the application of fresh start accounting, we will allocate our reorganization value to the fair value of assets and liabilities in conformity with the guidance for the acquisition method of accounting for business combinations. Adjustments to the carrying amounts could be material and could affect prospective results of operations as balance sheet items are settled, depreciated, amortized or impaired. This will make it difficult for stockholders to assess our performance in relation to prior periods. Our Annual Report on Form 10-K for the fiscal year ending December 31, 2016 reflects the consummation of the Plan and the adoption of fresh start accounting effective October 1, 2016.

Our emergence from bankruptcy will reduce or eliminate our net operating losses and other tax attributes and limit our ability to offset future taxable income with tax losses and credits incurred prior to its emergence from bankruptcy.

The use of our net operating losses (“NOLs”) and alternative minimum tax (“AMT”) credits has been limited by the “ownership change” under Section 382 of the Internal Revenue Code (the “Code”) that occurred on the Effective Date of the Plan (“the Emergence Ownership Change”). The limitation resulting from the Initial Ownership Change is substantial and applies to all NOLs and tax AMT credits existing at the time of the Initial Ownership Change. The limitation resulting from the Emergence Ownership Change will have a significant impact on our ability to offset future taxable income with carryforward net operating losses, AMT tax credits and an overall limitation of certain tax deductions. NOLs and AMT credits generated after the Emergence Ownership Change are generally not subject to the limitations from the prior ownership changes. As a result of the discharge of debt in the Chapter 11 Cases, we and our subsidiaries will be required to reduce the amount of their NOLs and AMT credits and potentially other tax attributes existing at the end of our taxable year.

Risks Related to Our Operations

Coal prices are subject to change based on a number of factors and coal prices have recently experienced an historic level of depression. If there is a 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;

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market price fluctuations for sulfur dioxide or nitric oxide emission allowances; and
technological advancements, including those related to alternative energy sources, those intended to convert coal-to-liquids or gas and those aimed at capturing, using and storing carbon dioxide.

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 recently experienced a sustained and significant downturn in coal pricing over the last several years. Pricing may be adversely affected or we may need to reduce production as a result of our uncommitted volume levels. 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, cash flows, liquidity 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 as the demand for, and price of, coal has been subject to pressure for a variety of reasons, including reductions in domestic and international demand for metallurgical and thermal coal.
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. Furthermore, because we typically seek to enter into long-term arrangements for the sale of a substantial portion of our coal, the average sales price we receive for our coal may lag behind any general economic recovery. 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. Potential changes to international trade agreements, trade concessions or other political and economic arrangements may benefit coal producers operating in countries other than the United States. We cannot assure you that we will be able to compete on the basis of price or other factors with companies that in the future may benefit from favorable foreign trade policies or other arrangements. 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.
The domestic coal industry has experienced consolidation in recent years, including consolidation among some of our major competitors. In addition, substantial overcapacity exists in the coal industry and several other large coal companies have also filed, and others may file, bankruptcy proceedings which could enable them to lower their productions costs and thereby reduce the price for coal. We cannot assure you that the result of current or further consolidation in the coal industry or current or future bankruptcy proceedings of our coal competitors will not adversely affect our competitive position.
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 or eliminate 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.

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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 92% of our coal sales by volume during 2016. 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. Overall economic activity and the associated demands for power by industrial users can have significant effects on overall electricity demand and can be caused by a number of factors. An economic slowdown can significantly slow the growth of electricity demand and could result in reduced demand for coal. For example, declines in the rate of international economic growth in countries such as China, India or other developing countries could further negatively impact the demand for U.S. coal and result in a continuing oversupply of coal in the marketplace. Weather patterns can also greatly affect electricity demand. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increase generating requirements from all sources. Mild temperatures, on the other hand, result in lower electrical demand, which allow generators to choose the source of power generation when deciding which generation source to dispatch.
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 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;
the unavailability of raw materials, equipment (including heavy mobile equipment) or other critical supplies such as tires, explosives, fuel, lubricants and other consumables of the type, quantity and/or size needed to meet production expectations;
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 72% of the coal volume we sold in 2016, 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.

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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. A decline in prices 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.
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. In certain locations, leases for oil, natural gas and coalbed methane reserves are located on, or adjacent to, some of our reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests.
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, 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. Increased opposition from non-governmental organizations and other third parties may also lengthen, delay or adversely impact the LBA process. 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;

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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 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 which 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. In addition, federal and state regulators are considering making financial assurance requirements with respect to mine closure and reclamation more stringent. 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.
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. There has been some consolidation in the supplier base providing mining materials to the coal industry, such as with suppliers of explosives in the U.S. and both surface and underground equipment globally, that has limited the number of sources for these materials. In situations where we have chosen to concentrate a large portion of purchases with one supplier, it has been to take advantage of cost savings from larger volumes of purchases and to ensure security of supply. 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.
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.

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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 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 or surface rights 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 or surface rights 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.

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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, 2016, we derived approximately 15% of our total coal revenues from sales to our three largest customers and approximately 42% 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 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 sales offices in 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

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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 flow.
Our ability to operate the Company effectively could be impaired if we lose key personnel or fail to attract qualified personnel.
We manage our business with a number of key personnel, the loss of whom could have a material adverse effect on us, absent the completion of an orderly transition. In addition, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel, particularly personnel with mining experience. We cannot provide assurance that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. Failure to retain or attract key personnel could have a material adverse effect on us.
We may be unable to comply with the restriction imposed by our New First Lien Debt 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 incur additional debt and require us to comply with various affirmative covenants. The New First Lien Debt Facility contains customary affirmative and negative covenants, which include restrictions on (i) indebtedness, (ii) liens and guarantees, (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) payment of other indebtedness, (x) no restriction in agreements on dividends or certain loans, (xi) loans and investments, (ix) transactions with respect to Bonding Subsidiaries and (xiii) changes in organizational documents. 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 New First Lien Debt Facility.
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 is in the process of being developed and implemented. 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.
Considerable uncertainty is associated with these air emissions initiatives. The content of regulatory requirements in the United States continues to evolve and develop 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, may install more

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effective pollution control equipment that reduces the need for low sulfur coal, or may cease operations, 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 the market for our products.
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 governmental regulations and unfavorable lending and investment policies by financial institutions associated with concerns about environmental impacts of coal combustion, including perceived impacts on the global climate.
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 climate change, 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 climate issues and, more specifically, levels of emissions of carbon dioxide from coal combustion by power plants. The Clean Power Plan, a set of regulations promulgated by the EPA currently under review by U.S. courts would severely limit emissions of carbon dioxide which would adversely affect our ability to sell coal. 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. Enactment of laws or passage of regulations regarding greenhouse emissions from the combustion of coal by the U.S., some of its states or other countries, or other actions to limit emissions could result in electricity generators switching from coal to other fuel sources or coal-fueled power plant closures. You should see Item 1, “Environmental and Other Regulatory Matters-Climate Change” for more information about governmental regulations relating to greenhouse gas emissions.
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. In general, 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 and required surety bonds or other instruments to secure those reclamation and restoration obligations;
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. Under certain federal and state environmental laws, our liability for such conditions may be joint and several with other owners/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. Liability under these laws is generally strict. Accordingly, we may incur liability without regard to fault or to the legality of the conduct giving rise to the conditions.
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. The matter is pending before the U.S. District Court for the Southern District of West Virginia on our subsididary’s motion for summary judgment. If the matter is resolved ultimately in a manner that is adverse to the interests of our operating 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.

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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; federal lease by application programs; costs associated with providing healthcare benefits to employees; health and safety standards; accounting standards; taxation requirements; and competition laws.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.


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ITEM 2. PROPERTIES.
Our Properties
At December 31, 2016, we owned or controlled, primarily through long‑term leases, approximately 28,315 acres of coal land in Ohio, 1,060 acres of coal land in Maryland, 46,542 acres of coal land in Virginia, 355,205 acres of coal land in West Virginia, 103,733 acres of coal land in Wyoming, 274,273 acres of coal land in Illinois, 85,459 acres of coal land in Kentucky, 9,840 acres of coal land in Montana, 21,802 acres of coal land in New Mexico, 358 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 84,958 acres of our coal land from the federal government and approximately 22,385 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 2.1 billion tons of proven and probable recoverable reserves at December 31, 2016. Our coal reserve estimates at December 31, 2016 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.”







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The following tables present our estimated assigned and unassigned recoverable coal reserves at December 31, 2016:
Total Assigned Reserves
(Tons in millions)
 
Total Assigned Recoverable Reserves
 
 
 
As Received Btus per lb. (1)
 
 
 
 
 
 
Sulfur Content (lbs. per million Btus)
 
Mining Method
Past Reserve Estimates
 
 
 
Reserve Control
 
Under-
 
Proven
Probable
<1.2
1.2-2.5
>2.5
Leased
Owned
Surface
ground
2014

2015

Wyoming
1,115

1,109

6

1,047

68


8,831

1,115

 
1,115


1,423

1,318

Colorado
56

51

5

56



11,500

56



56

65

53

Central App.
70

64

6

30

40


13,055

68

2

23

47

139

35

Northern App.
48

43

5


47

1

13,011

10

38


48

74

40

Illinois
38

23

15



38

10,730

32

6


38

33

37

Total
1,327

1,290

37

1,133

155

39

9,374

1,281

46

1,138

189

1,734

1,483


(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 Recoverable Reserves
 
 
 
 
 
 
 
 
 
 
 
Sulfur Content
 
 
Mining Method
 
 
 
(lbs. per million Btus)
As Received
Reserve Control
 
Under‑
 
Proven
Probable
<1.2
1.2-2.5
>2.5
Btus per lb.(1)
Leased
Owned
Surface
ground
Wyoming
285

239

46

237

48


8,457

285


285


Colorado
28

22

6

28



11,217

28



28

Central App.
58

49

9

20

25

13

12,530

11

47

40

18

Northern App.
169

92

77


168

1

13,000

8

161


169

Illinois
282

187

95



282

11,170

57

225

4

278

Total
822

589

233

285

241

296

10,704

389

433

329

493


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

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 66% 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 8% 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, 2016 was $0.4 billion, consisting of $2.3 million of prepaid royalties and a net book value of coal lands and mineral rights of $0.4 billion.

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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 or more from the time the coal tract is nominated to the time a final bid is accepted by the BLM. After the LBA is awarded, the company then conducts the necessary testing to determine what amount can be classified as reserves.
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 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

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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,” contained in Item 1A. “Risk Factors” for more information.
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 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 or surface rights 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, 2016, approximately 22% 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 58,758 acres of property to other coal operators in 2016. We received royalty income of $1.1 million during the period October 2 through December 31, 2016 from the mining of approximately 0.4 million tons, $1.7 million during the period January 1 through October 1, 2016 from the mining of approximately 0.6 million tons, $6.3 million in 2015 from the mining of approximately 2.1 million tons and $9.6 million in 2014 from the mining of approximately 2.6 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.
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.

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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).

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. A full account and status of this litigation surrounding the Final Determination is set forth in the immediately following section.

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 the 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.

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

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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 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 court heard oral arguments on April 11, 2016. By opinion of the court filed on July 19, 2016, the court affirmed the district court judgment thus upholding the EPA’s Final Determination.

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

On July 16, 2015, the UMWA 1974 Pension Trust (“1974 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”) bankruptcy filing) for 1974 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 1974 Plan, triggering a withdrawal. The amended complaint further alleged that Arch owes $299.8 million in withdrawal liability. On October 29, 2015, the 1974 Plan issued a letter to Arch demanding payment of this withdrawal liability amount. 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. Thereafter, on May 26, 2016, the 1974 Plan filed a proof of claim asserting a $299.0 million claim against Arch and its debtor subsidiaries. On September 9, 2016, Arch and the 1974 Plan entered into a confidential agreement in principle to settle the withdrawal liability dispute, which agreement became effective on November 3, 2016.


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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, 2016.



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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
On the Plan Effective Date, all shares of our old common stock were canceled and 24,589,834 shares of Class A Common Stock and 410,166 shares of Class B Common Stock, par value $.01 per share, were distributed to the secured lenders and to certain holders of general unsecured claims under the Plan. In addition, on the Effective Date, Arch Coal issued Warrants to purchase up to an aggregate of 1,914,856 shares of Class A Common Stock. Arch Coal relied, based on the confirmation order it received from the Bankruptcy Court, on Section 1145(a)(1) of the U.S. Bankruptcy Code to exempt from the registration requirements of the Securities Act of 1933, as amended (i) the offer and sale of Common Stock to the secured lenders and to the general unsecured creditors, (ii) the offer and sale of the Warrants to the holders of claims arising under the Cancelled Notes and (iii) the offer and sale of the Class A Common Stock issuable upon exercise of the Warrants. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under a plan of reorganization from registration under Section 5 of the Securities Act and state laws if three principal requirements are satisfied:

the securities must be offered and sold under a plan of reorganization and must be securities of the debtor, of an affiliate participating in a joint plan of reorganization with the debtor or of a successor to the debtor under the plan of reorganization;

the recipients of the securities must hold claims against or interests in the debtor; and

the securities must be issued in exchange, or principally in exchange, for the recipient’s claim against or interest in the debtor.

Our new common stock is listed on the NYSE under the symbol “ARCH” as has been trading since October 5, 2016. No prior established public trading market existed for our new common stock prior to this date. Based upon information provided by our transfer agent, as of February 16, 2017, we had one stockholder of record.

The following table sets forth the per share high and low closing prices for our common stock as reported on the NYSE for the periods presented:

 
High
 
Low
2017:
 
 
 
First Quarter (through February 16, 2017)
$
76.05

 
$
68.65

2016:
 
 
 
Fourth Quarter (from October 5, 2016)
$
85.16

 
$
61.31


We have paid no cash dividends on our stock. Any future determination to pay cash dividends will be at the discretion of our Board of Directors, subject to applicable limitations under Delaware law, and will be dependent on our results of operations, financial condition, contractual restrictions and other factors deemed relevant by our Board of Directors.

Stockholder Return Performance Presentation

The following graph compares the cumulative stockholder return from October 5, 2016, the date our common stock began trading following the Plan Effective Date, through December 31, 2016, for our current existing stock, the S&P Midcap 400 index and a customized peer group. Because the value of the Predecessor common stock bears no relation to the value of our existing common stock, the graph below reflects only our current existing common stock. The peer group consists of CONSOL Energy Inc. and Peabody Energy Corp. Peabody Energy Corp. filed for Chapter 11 bankruptcy protection, and its stock traded on the OTC Pink market during the performance period reflected in the graph. Alpha Natural Resources, Inc. is no longer included in our peer group, because the company emerged from Chapter 11 as a privately held company prior to the performance period. The graph tracks the performance of a $100 investment in our current existing common stock, in the peer group, and the index (with the reinvestment of all dividends) from October 5, 2016 through December 31, 2016.


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https://cdn.kscope.io/68d9427cafb55572c10771a6ab4e536d-stockperformancecharta02.jpg

 
10/5/2016
10/16
11/16
12/16
 
 
 
 
 
Arch Coal, Inc.
100.00

116.48

123.86

123.89

S&P Midcap 400
100.00

97.32

105.12

107.42

Peer Group
100.00

87.96

106.67

92.83


The stock price performance included in this graph is not necessarily indicative of future stock price performance.


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ITEM 6.  SELECTED FINANCIAL DATA.


 
Successor
Predecessor
(In thousands, except per share data)
October 2 through December 31, 2016
January 1 through October 1, 2016
Year Ended December 31, 2015
Year Ended December 31, 2014
Year Ended December 31, 2013
Year Ended December 31, 2012
Statement of Operations Data:
(1)
(1)
(2)
 
(3)
(4)
Revenues
$
575,688

$
1,398,709

$
2,573,260

$
2,937,119

$
3,014,357

$
3,768,126

Asset impairment and mine closure costs

129,267

2,628,303

24,113

220,879

539,182

Goodwill impairment




265,423

330,680

Income (loss) from operations
46,118

(257,138
)
(2,865,063
)
(149,531
)
(663,141
)
(757,012
)
Interest expense
(11,241
)
(135,888
)
(397,979
)
(390,946
)
(381,267
)
(317,615
)
Non-operating expenses
(759
)
1,627,828

(27,910
)

(42,921
)
(23,668
)
Income (loss) from continuing operations
33,449

1,242,081

(2,913,142
)
(558,353
)
(745,228
)
(738,915
)
Net income (loss) attributable to Arch Coal
33,449

1,242,081

(2,913,142
)
(558,353
)
(641,832
)
(683,955
)
Basic earnings (loss) per common share
$
1.34

$
58.33

$
(136.86
)
$
(26.31
)
$
(30.26
)
$
(32.36
)
Diluted earnings (loss) per common share
$
1.31

$
58.28

$
(136.86
)
$
(26.31
)
$
(30.26
)
$
(32.36
)
Balance Sheet Data:
 
 
 
 
 
 
Total assets
$
2,136,597

$
2,123,829

$
5,041,881

$
8,346,362

$
8,896,571

$
9,913,791

Working capital
566,391

522,465

(4,361,009
)
1,023,357

1,293,849

1,337,035

Current maturities of debt
11,038

6,662

5,042,353

12,191

14,419

17,557

Long-term debt, less current maturities
351,841

353,272

30,953

5,064,818

5,043,454

5,008,232

Other long-term obligations
725,948

786,015

755,283

695,881

717,174

825,080

Noncurrent deferred income tax liability



422,809

413,546

664,182

Arch Coal stockholders’ equity
746,577

687,483

(1,244,289
)
1,668,154

2,253,249

2,854,567

Cash Flow Data:
 
 
 
 
 
 
Cash provided by (used in) operating activities
84,192

(228,218
)
(44,367
)
(33,582
)
55,742

332,804

Depreciation, depletion and amortization, including amortization of sales contracts, net
33,400

190,853

370,534

405,561

438,247

500,319

Capital expenditures
15,214

82,434

119,024

147,286

296,984

395,225

Net proceeds from the issuance of long term debt



(4,519
)
623,511

1,942,685

Payments to retire debt, including redemption premium




628,660

452,934

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





(481,300
)
Dividend payments



2,123

25,475

42,440

Operating Data:
 
 
 
 
 
 
Tons sold
26,812

67,128

127,632

134,360

139,607

140,820

Tons produced
26,619

66,658

126,820

132,614

136,613

135,934

Tons purchased from third parties
193

481

1,287

1,182

2,925

4,327




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(1) 
Our 2016 results were impacted by the filing of bankruptcy, subsequent emergence and the application of fresh start accounting. See Note 3, “Emergence from Bankruptcy and Fresh Start Accounting” for additional information.
(2) 
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.”
(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.
(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 of $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.

The selected financial information presented above for the period October 2 through December 31, 2016, the period from January 1 through October 1, 2016, and the years ended December 31, 2015, 2014, 2013 and 2012 was derived from, and is qualified by, reference to our Consolidated Financial Statements, including the notes thereto, contained elsewhere herein. The selected financial information should be read in conjunction with the Consolidated Financial Statements and related notes and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

As a result of the application of fresh start accounting as of the Plan Effective Date, the financial statements on or prior to October 1, 2016 are not comparable with the financial statements after October 1, 2016. References to “Successor” refer to the Company after October 1, 2016, after giving effect to the application of fresh start accounting; references to “Predecessor” refer to the Company on or prior to October 1, 2016.

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

Our results for the Successor period from October 2 through December 31, 2016 were impacted by strengthening of both the thermal and metallurgical coal markets. The domestic thermal market rebounded somewhat from lows in the first half of 2016 as natural gas prices rose. Warmer than normal summer temperatures, increasing natural gas exports, and flat to slightly declining natural gas supply supported natural gas pricing at levels that allowed some thermal coals, particularly Powder River Basin coals, to compete economically for a larger share of electric generation. Additionally, pricing in international thermal coal markets strengthened sufficiently to make some thermal exports economically viable for certain of our operations in the Successor period.

Metallurgical coal markets continued to strengthen substantially through most of the Successor period from October 2 through December 31, 2016, with prompt international pricing reaching multi-year highs as near-term supply shortages became more evident. We believe the supply shortages were driven by: a Chinese mandate to restrict its domestic coal supply; supply rationalization in North America; years of global underinvestment in the industry; and some specific international supply disruptions, particularly in Australia. Although the majority of our metallurgical volume was committed and priced for the Successor period prior to the improvement in pricing, certain index-based and prompt sales reflected the higher prices. Late in the Successor period, prompt metallurgical pricing began to retrace from these highs as the Chinese loosened their supply restrictions and supply disruptions abated. International prompt metallurgical prices remain well above recent lows. We sold 1.9 million tons of metallurgical coal during the Successor period.

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 “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”) were jointly administered under the caption In re Arch Coal, Inc., et al. Case No. 16-40120 (lead case). During the bankruptcy proceedings, each Debtor operated 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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On September 13, 2016, the Bankruptcy Court entered an order, Docket No. 1324, confirming the Debtors’ Fourth Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code dated as of September 11, 2016 (the “Plan”), which order was amended on September 15, 2016, Docket No. 1334.
On October 5, 2016, Arch Coal satisfied the closing conditions contemplated by the Plan, which became effective on that date (the “Effective Date”).
On the plan Effective Date, we applied fresh start accounting which requires us to allocate our reorganization value to the fair value of assets and liabilities in conformity with the guidance for the acquisition method of accounting for business combinations. In addition to fresh start accounting, our consolidated financial statements reflect all impacts of the transactions contemplated by the Plan. Under the provisions of fresh start accounting, a new entity has been created for financial reporting purposes. References to “Successor” in the financial statements and accompanying footnotes are in reference to reporting dates on or after October 2, 2016; references to “Predecessor” in the financial statements and accompanying footnotes are in reference to reporting dates through October 1, 2016 which includes the impact of the Plan provisions and the application of fresh start accounting. As such, our financial statements for the Successor will not be comparable in many respects to its financial statements for periods prior to the adoption of fresh start accounting and prior to the accounting for the effects of the Plan. For further information on fresh start accounting, please see Note 3 to the Consolidated Financial Statements, “Emergence from Bankruptcy and Fresh Start Accounting.”

Results of Operations - Successor

Period from October 2 through December 31, 2016

Revenues.  Our revenues consist of coal sales.

Coal sales. The following table summarizes information about our coal sales for the period from October 2 through December 31, 2016:
 
 
Successor
 
 
October 2 through December 31, 2016
 
 
(In thousands)
Coal sales
 
$
575,688

Tons sold
 
26,812

 
Coal sales for the period from October 2 through December 31, 2016 by segment were approximately 48% Powder River Basin, 35% Metallurgical, and 17% Other. Tons sold for the period by segment were approximately 81% Powder River Basin, 9% Metallurgical, and 10% Other. See discussion in “Operational Performance” below for further information about regional results.
Costs, expenses and other.  The following table summarizes costs, expenses and other components of operating income for the period from October 2 through December 31, 2016
 
 
Successor
 
 
October 2 through December 31, 2016
 
 
(In thousands)
Cost of sales (exclusive of items shown separately below)
 
$
470,644

Depreciation, depletion and amortization
 
32,604

Accretion on asset retirement obligations
 
7,634

Amortization of sales contracts, net
 
796

Change in fair value of coal derivatives and coal trading activities, net
 
396

Selling, general and administrative expenses
 
22,836

Other operating expense (income), net
 
(5,340
)
Total costs, expenses and other
 
$
529,570



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Cost of sales.  Our cost of sales for the period from October 2 through December 31, 2016 consisted primarily of labor related costs (approximately 25%), repairs and supplies (approximately 33%), operating taxes and royalties (approximately 22%), and transportation costs (approximately 12%). See discussion in “Operational Performance” below for information about segment cost results.
 
Depreciation, depletion and amortization.  Our depreciation, depletion and amortization costs for the period from October 2 through December 31, 2016 consist of depreciation of plant and equipment (approximately 63%), depletion of reserves (approximately 20%), and amortization of development costs (approximately 17%). This reflects the application of fresh start accounting. For further information on fresh start accounting, please see Note 3 to the Consolidated Financial Statements, “Emergence from Bankruptcy and Fresh Start Accounting.”  

Accretion on asset retirement obligation.  Approximately 66% of the accretion on our asset retirement obligation is attributable to our large surface operations in the Powder River Basin.

Selling, general and administrative expenses.  Total selling, general and administrative expenses consist primarily of compensation costs of $15.3 million, and professional services and usage and maintenance agreements of $5.1 million.

Other operating expense (income), net. Other operating expense (income), net consists primarily of miscellaneous revenues including royalties and net gains on asset sales of $5.4 million and net income from equity investments of $1.7 million, partially offset by miscellaneous expenses primarily related to our land company of $2.1 million.

Non-operating expense. The following table summarizes non-operating expense for the period from October 2 through December 31, 2016:
 
Successor
 
October 2 through December 31, 2016
 
(In thousands)
Reorganization income (loss), net
$
(759
)

Nonoperating expenses in the current period are related to our reorganization. For further information on our successful reorganization, please see Note 3 to the Consolidated Financial Statements, “Emergence from Bankruptcy and Fresh Start Accounting.”

Provision for income taxes. The following table summarizes our provision for income taxes for the period from October 2 through December 31, 2016:
 
Successor
 
October 2 through December 31, 2016
 
(In thousands)
Provision for income taxes
$
1,156


See further discussion in Note 14, to the Consolidated Financial Statements “Taxes,”.


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Operational Performance- Successor

Period from October 2 through December 31, 2016

Our mining operations are evaluated based on Adjusted EBITDAR, per-ton cash operating costs (defined as including all mining costs except depreciation, depletion, amortization, accretion on asset retirements obligations, and pass-through transportation expenses), and on other non-financial measures, such as safety and environmental performance. Adjusted EBITDAR is defined as net income attributable to the Company before the effect of net interest expense, income taxes, depreciation, depletion and amortization, the amortization of sales contracts, the accretion on asset retirement obligations, and reorganization items, net. Adjusted EBITDAR may also be adjusted for items that may not reflect the trend of future results. In conjunction with our emergence from bankruptcy, we have added accretion on asset retirement obligations as an adjustment to arrive at Adjusted EBITDAR. Adjusted EBITDAR is not a measure of financial performance in accordance with generally accepted accounting principles, and items excluded from Adjusted EBITDAR are significant in understanding and assessing our financial condition. Therefore, Adjusted EBITDAR should not be considered in isolation, nor as an alternative to net income, income from operations, cash flows from operations or as a measure of our profitability, liquidity or performance under generally accepted accounting principles. Furthermore, analogous measures are used by industry analysts to evaluate the Company’s operating performance. Investors should be aware that our presentation of Adjusted EBITDAR may not be comparable to similarly titled measures used by other companies.

The following table shows operating results of continuing coal operations for the Successor period from October 2 through December 31, 2016.
 
 
 
Successor
 
 
October 2 through December 31, 2016
Powder River Basin
 
 

Tons sold (in thousands)
 
21,824

Coal sales per ton sold
 
$
12.41

Cash cost per ton sold
 
$
9.88

Cash margin per ton sold
 
$
2.53

Adjusted EBITDAR (in thousands)
 
$
55,765

Metallurgical
 
 

Tons sold (in thousands)
 
2,442

Coal sales per ton sold
 
$
65.61

Cash cost per ton sold
 
$
52.98

Cash margin per ton sold
 
$
12.63

Adjusted EBITDAR (in thousands)
 
$
30,819

Other Thermal
 
 

Tons sold (in thousands)
 
2,510

Coal sales per ton sold
 
$
34.01

Cash cost per ton sold
 
$
21.79

Cash margin per ton sold
 
$
12.22

Adjusted EBITDAR (in thousands)
 
$
31,159

           
  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 EBITDAR for the Successor period from October 2 through December 31, 2016 benefited from cost control efforts and rebounding demand driven by rising natural gas prices that increased the competitiveness of Powder River Basin coal for electric generation versus the competing fuel. Rising gas prices resulted from favorable summer heat, increased natural gas exports, both pipeline and liquefied natural gas, and flat to slightly declining natural gas production. Cost control efforts included adjusting operations to align with current market volume expectations.

Metallurgical —Adjusted EBITDAR for the Successor period from October 2 through December 31, 2016 benefited from the significant increase in international pricing for metallurgical coal. As discussed above, supply shortages driven by a Chinese mandate to restrict its domestic supply, supply rationalization in North America, years of global underinvestment in the

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industry, and some specific international supply disruptions, particularly in Australia, resulted in a significant increase in international prompt metallurgical coal prices. Our ability to take advantage of the rapid increase in prompt international pricing was muted due to having significant volumes for the period committed and priced prior to the rapid increase. Our metallurgical segment sold 1.9 million tons of metallurgical coal and 0.5 million tons of associated thermal coal in the Successor period. Longwall operations accounted for approximately 55% of our shipment volume in the period. Late in the Successor period prompt international metallurgical pricing began to retreat as loosening of Chinese supply restrictions and easing of supply disruptions began to mitigate the supply shortage.

Other Thermal— Adjusted EBITDAR for the Successor period from October 2 through December 31, 2016 benefited from the increased natural gas pricing discussed in the Powder River Basin segment discussion above, and increased international thermal prices. These benefits were primarily recognized at our West Elk operation where domestic opportunities increased and export opportunities became economic. Partially offsetting those positive trends were operating issues at our Viper operation’s largest customer that significantly reduced sales volume in the current period.

Results of Operations - Predecessor

Period from January 1 through October 1, 2016

Revenues.  Our revenues consist of coal sales.

Coal sales. The following table summarizes information about our coal sales for the period from January 1 through October 1, 2016
 
 
Predecessor
 
 
January 1 through October 1, 2016
 
 
(In thousands)
Coal sales
 
$
1,398,709

Tons sold
 
67,128

 
Coal sales for the period from January 1 through October 1, 2016 by segment were approximately 52% Powder River Basin, 31% Metallurgical, and 15% Other. Tons sold for the period by segment were approximately 82% Powder River Basin, 10% Metallurgical, and 8% Other. See discussion in “Operational Performance” below for further information about regional results.
Costs, expenses and other.  The following table summarizes costs, expenses and other components of operating income for the period from January 1 through October 1, 2016
 
 
Predecessor
 
 
January 1 through October 1, 2016
 
 
(In thousands)
Cost of sales (exclusive of items shown separately below)
 
$
1,264,464

Depreciation, depletion and amortization
 
191,581

Accretion on asset retirement obligations
 
24,321

Amortization of sales contracts, net
 
(728
)
Change in fair value of coal derivatives and coal trading activities, net
 
2,856

Asset impairment and mine closure costs
 
129,267

Selling, general and administrative expenses
 
59,343

Other operating expense (income), net
 
(15,257
)
Total costs, expenses and other
 
$
1,655,847



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Cost of sales.  Our cost of sales for the period from January 1 through October 1, 2016 consisted primarily of labor related costs (approximately 28%), repairs and supplies (approximately 34%), operating taxes and royalties (approximately 21%), and transportation costs (approximately 10%). See discussion in “Operational Performance” below for information about segment cost results.
 
Depreciation, depletion and amortization.  Our depreciation, depletion and amortization costs for the period from January 1 through October 1, 2016 consist of depreciation of plant and equipment (approximately 55%), depletion of reserves (approximately 34%), and amortization of development costs (approximately 11%).  

Accretion on asset retirement obligation.  Approximately 70% of the accretion on our asset retirement obligation for the period from January 1 through October 1, 2016 was attributable to our large surface operations in the Powder River Basin.

Asset impairment and mine closure costs.  During the period from January 1 through October 1, 2016 we received notification of intent to idle operations by a third party to whom we leased certain Appalachian reserves. As a result of the idling and weakness in the thermal coal market, we determined that the value of these reserves was impaired. Also during this period we relinquished our interest in Millennium Bulk Terminal while retaining future throughput rights. As a result of the sale, our remaining equity investment in Millennium was impaired.

Selling, general and administrative expenses.  Total selling, general and administrative expenses consist primarily of compensation costs of $38.5 million, and professional services and usage and maintenance agreements of $12.0 million.

Other operating expense (income), net. Other operating expense (income), net consists primarily of miscellaneous revenues including royalties and net gains on asset sales of $14.4 million and net income from equity investments of $5.3 million, partially offset by miscellaneous expenses primarily related to our land company of $7.3 million.

Non-operating expense. The following table summarizes non-operating expense for the period from January 1 through October 1, 2016:
 
Predecessor
 
January 1 through October 1, 2016
 
(In thousands)
Net loss resulting from early retirement of debt and debt restructuring
$
(2,213
)
Reorganization income (loss), net
1,630,041

Total non-operating (expense) benefit
$
1,627,828


Nonoperating expenses in the current period related to our proposed debt restructuring activities and Chapter 11 reorganization. For further information on our successful reorganization, please see Note 3 to the Consolidated Financial Statements, “Emergence from Bankruptcy and Fresh Start Accounting.”

Benefit from income taxes. The following table summarizes our benefit from income taxes for the period from January 1 through October 1, 2016:

 
Predecessor
 
January 1 through October 1, 2016
 
(In thousands)
Benefit from income taxes
$
(4,626
)

See further discussion in Note 14 to the Consolidated Financial Statements, “Taxes,”.




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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:
 
 
Predecessor 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 Metallurgical segment and lower tons sold in our Powder River Basin and Other Thermal segments. See discussion in “Operational Performance” below 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
 
 
Predecessor Year Ended December 31,
 
(Increase) Decrease
 
 
2015
 
2014
 
 in Net Loss
 
 
(In thousands)
Cost of sales (exclusive of items shown separately below)
 
$
2,172,753

 
$
2,533,284

 
$
360,531

Depreciation, depletion and amortization
 
379,345

 
418,748

 
39,403

Accretion on asset retirement obligations
 
33,680

 
32,909

 
(771
)
Amortization of 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” below for more 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 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.


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Losses from disposed operations resulting from the 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 6, “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 for the year ended December 31, 2015 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 increased 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.

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
 
Predecessor Year Ended December 31,
 
in Net Loss
 
2015
 
2014
 
$
 
(In thousands)
Net loss resulting from early retirement of debt and debt restructuring
$
(27,910
)
 
$

 
$
(27,910
)

Amounts reported as non-operating consist of expenses resulting from financing activities, other than interest costs.  In 2015, we incurred $24.2 million of legal and financial advisory fees associated with our debt restructuring efforts. Additionally, in the fourth quarter of 2015 we terminated our revolving credit agreement resulting in the write-off of $3.7 million of deferred financing costs.

Provision for (benefit from) income taxes. The following table summarizes our benefit from income taxes for the year ended December 31, 2015 and compares it with the information for the year ended December 31, 2014:
 
Predecessor Year Ended December 31,
 
Decrease
 
2015
 
2014
 
in Net Loss
 
(In thousands)
Provision for (benefit from) income taxes
$
(373,380
)
 
$
25,634

 
$
399,014


The income tax benefit in the year ended December 31, 2015 compared to the income tax provision in the year ended December 31, 2014 was largely due to the approximately $2.6 billion increase in asset impairment losses recorded in 2015 partially offset by the increase of a valuation allowance relating to both federal and state net operating loss carryforwards. See further discussion in Note 14, “Taxes,” to the Consolidated Financial Statements for further discussion.



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Operational Performance - Predecessor

Our mining operations are evaluated based on Adjusted EBITDAR, per-ton cash operating costs (defined as including all mining costs except depreciation, depletion, amortization, accretion on asset retirements obligations, and pass-through transportation expenses), and on other non-financial measures, such as safety and environmental performance. Adjusted EBITDAR is defined as net income attributable to the Company before the effect of net interest expense, income taxes, depreciation, depletion and amortization, the amortization of acquired sales contracts, the accretion on asset retirement obligations, and reorganization items, net. Adjusted EBITDAR may also be adjusted for items that may not reflect the trend of future results. In conjunction with our emergence from bankruptcy, we have added accretion on asset retirement obligations as an adjustment to arrive at Adjusted EBITDAR. Adjusted EBITDAR is not a measure of financial performance in accordance with generally accepted accounting principles, and items excluded from Adjusted EBITDAR are significant in understanding and assessing our financial condition. Therefore, Adjusted EBITDAR should not be considered in isolation, nor as an alternative to net income, income from operations, cash flows from operations or as a measure of our profitability, liquidity or performance under generally accepted accounting principles. Furthermore, analogous measures are used by industry analysts to evaluate the Company’s operating performance. Investors should be aware that our presentation of Adjusted EBITDAR may not be comparable to similarly titled measures used by other companies.


The following table shows operating results of continuing coal operations for the Predecessor periods January 1 through October 1, 2016 and the years ended December 31, 2015 and 2014.
 
 
 
Predecessor
 
 
January 1 through October 1, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Powder River Basin
 
 
 
 

 
 
Tons sold (in thousands)
 
54,911

 
108,481

 
111,156

Coal sales per ton sold
 
$
13.01

 
$
13.15

 
$
12.86

Cash cost per ton sold
 
$
10.95

 
$
10.54

 
$
10.87

Cash margin per ton sold
 
$
2.06

 
$
2.61

 
$
1.99

Adjusted EBITDAR (in thousands)
 
$
113,185

 
$
281,039

 
$
218,731

Metallurgical
 
 
 
 

 
 
Tons sold (in thousands)
 
6,692

 
8,352

 
8,421

Coal sales per ton sold
 
$
53.15

 
$
66.62

 
$
77.70

Cash cost per ton sold
 
$
51.40

 
$
58.36

 
$
64.43

Cash margin per ton sold
 
$
1.75

 
$
8.26

 
$
13.27

Adjusted EBITDAR (in thousands)
 
$
11,851

 
$
70,450

 
$
112,719

Other Thermal
 
 
 
 

 
 
Tons sold (in thousands)
 
5,181

 
9,764

 
12,201

Coal sales per ton sold
 
$
36.16

 
$
37.32

 
$
37.98

Cash cost per ton sold
 
$
30.28

 
$
28.01

 
$
29.20

Cash margin per ton sold
 
$
5.88

 
$
9.31

 
$
8.78

Adjusted EBITDAR (in thousands)
 
$
31,448

 
$
42,734

 
$
78,238

           
  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 EBITDAR for the Predecessor period from January 1 through October 1, 2016 was negatively impacted by demand destruction driven by historically low natural gas prices that limited the competitiveness of Powder River Basin coal for electric generation versus the competing fuel. The low natural gas prices were driven by mild winter weather and record natural gas production levels.

Adjusted EBITDAR increased 29% in 2015 when compared to 2014 due to increased coal sales per ton sold and decreased cash 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 cost control efforts. Natural gas pricing fell to historically low levels due to mild winter weather in late

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2015, and the competing fuel began to dispatch for electrical generation ahead of Power River Basin coal in some areas. This decrease in coal burn led to increasing generator stockpiles, further depressing demand.
 
Metallurgical — Adjusted EBITDAR for the Predecessor period from January 1 through October 1, 2016 was negatively impacted by declines in metallurgical coal prices. Years of global oversupply from anemic economic growth and international overproduction, particularly from Australia, drove pricing down to levels that were unprofitable for most North American producers. Our metallurgical segment sold 5.1 million tons of metallurgical coal and 1.6 million tons of associated thermal coal in the Predecessor period from January 1 through October 1, 2016. Longwall operations accounted for approximately 65% of our shipment volume in the period.

Adjusted EBITDAR decreased 38% in 2015 when compared to 2014 due to the decrease in coal sales per ton sold partially offset by the decrease in cash cost per ton sold. The decrease in coal sales per ton sold is related to lower metallurgical coal pricing, and the cost reduction is primarily from increased productivity and shifting volume to lower cost operations, particularly the Leer operation. Longwall operations accounted for 59% of our shipment volume in 2015 versus 53% in 2014.

Other Thermal— Adjusted EBITDAR for the Predecessor period from January 1 through October 1, 2016 was negatively impacted by demand destruction driven by historically low natural gas prices discussed in the Powder River Basin segment discussion above, and the lack of economic export opportunities. These conditions severely restricted tons sold and coal sales per ton sold at our West Elk and Coal Mac operations.

Adjusted EBITDAR decreased 45% in 2015 when compared to 2014 due to declining tons sold at our West Elk and Coal Mac operations related to low natural gas pricing and increased liquidated damages costs on logistics contracts.
    

Reconciliation of NON-GAAP measures

Segment coal sales per ton sold

Segment coal sales per ton sold are calculated as the segment's coal sales revenues divided by segment tons sold. The segments' sales per ton sold are adjusted for transportation costs, and may be adjusted for other items that, due to generally accepted accounting principles, are classified in "other income" on the statement of operations, but relate to price protection on the sale of coal. Segment sales per ton sold is not a measure of financial performance in accordance with generally accepted accounting principles. We believe segment sales per ton sold provides useful information to investors as it better reflects our revenue for the quality of coal sold and our operating results by including all income from coal sales. The adjustments made to arrive at these measures are significant in understanding and assessing our financial condition. Therefore, segment coal sales revenues should not be considered in isolation, nor as an alternative to coal sales revenues under generally accepted accounting principles.

 
 
Successor
Predecessor
 
 
October 2 through December 31, 2016
January 1 through October 1, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
 
 
 
 
 
 
 
 
(In thousands)
 
 
 
 
 
 
 
Reported segment coal sales revenues
 
$
516,448

$
1,257,219

 
$
2,347,132

 
$
2,547,075

Coal risk management derivative settlements classified in “other income”
 
(112
)
448

 
(3,231
)
 
(5,958
)
Coal sales revenues from idled or otherwise disposed operations not included in segments
 
2,181

19,368

 
48,126

 
146,823

Transportation costs
 
57,171

121,674

 
181,233

 
247,241

Coal sales
 
575,688

1,398,709

 
2,573,260

 
2,935,181

Other revenues
 


 

 
1,938

Revenues in the consolidated statements of operations
 
$
575,688

$
1,398,709

 
$
2,573,260

 
$
2,937,119



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Segment cost per ton sold

Segment costs per ton sold are calculated as the segment’s cost of coal sales divided by segment tons sold. The segments’ cost of tons sold are adjusted for transportation costs, and may be adjusted for other items that, due to generally accepted accounting principles, are classified in “other income” on the statement of operations, but relate directly to the costs incurred to produce coal. Segment cost of tons sold is not a measure of financial performance in accordance with generally accepted accounting principles. We believe segment cost of tons sold better reflects our controllable costs and our operating results by including all costs incurred to produce coal. The adjustments made to arrive at these measures are significant in understanding and assessing our financial condition. Therefore, segment cost of tons sold should not be considered in isolation, nor as an alternative to cost of sales under generally accepted accounting principles.
 
 
Successor
Predecessor
 
 
October 2 through December 31, 2016
January 1 through October 1, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
 
 
 
 
 
 
 
 
(In thousands)
 
 
 
 
 
 
 
Reported segment cost of coal sales
 
$
399,568

$
1,102,386

 
$
1,903,762

 
$
2,106,991

Diesel fuel risk management derivative settlements classified in “other income”
 
363

(3,696
)
 
(8,162
)
 
(6,789
)
Transportation costs
 
57,171

121,674

 
181,233

 
247,241

Cost of sales from idled or otherwise disposed operations not included in segments
 
5,853

42,513

 
79,290

 
190,220

Fresh start coal inventory fair value adjustment
 
7,345


 

 

Other (operating overhead, certain actuarial, etc.)
 
344

1,587

 
16,630

 
(4,379
)
Cost of sales in the consolidated statements of operations
 
$
470,644

$
1,264,464

 
$
2,172,753

 
$
2,533,284


Reconciliation of Segment Adjusted EBITDAR to Net Income
 
The discussion in “Results of Operations” above includes references to our Adjusted EBITDAR for each of our reportable segments. Adjusted EBITDAR is defined as net income attributable to the Company before the effect of net interest expense, income taxes, depreciation, depletion and amortization, the amortization of sales contracts, the accretion on asset retirement obligations, and reorganization items, net. Adjusted EBITDAR may also be adjusted for items that may not reflect the trend of future results. We have added accretion on asset retirement obligations as an adjustment to arrive at Adjusted EBITDAR as we believe most industry participants include this adjustment in similar measures. We use Adjusted EBITDAR to measure the operating performance of our segments and allocate resources to our segments. Adjusted EBITDAR is not a measure of financial performance in accordance with generally accepted accounting principles, and items excluded from Adjusted EBITDAR are significant in understanding and assessing our financial condition. Therefore, Adjusted EBITDAR should not be considered in isolation, nor as an alternative to net income, income from operations, cash flows from operations or as a measure of our profitability, liquidity or performance under generally accepted accounting principles. Investors should be aware that our presentation of Adjusted EBITDAR may not be comparable to similarly titled measures used by other companies. The table below shows how we calculate Adjusted EBITDAR.
 


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Successor
Predecessor
 
 
October 2 through December 31, 2016
January 1 through October 1, 2016

Year Ended December 31, 2015

Year Ended December 31, 2014
(In thousands)
 
 
 
 
 
 
 
Reported segment Adjusted EBITDAR from coal operations
 
$
117,743

$
156,484

 
$
394,223

 
$
409,688

EBITDAR from idled or otherwise disposed operations
 
(2,795
)
(14,514
)
 
(23,605
)
 
(12,834
)
Selling, general and administrative expenses