Archer Annual Report 2015

Plain-text annual report

Table of Contents UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWASHINGTON, DC 20549Form 10-K( X ) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2016 or( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934Commission file number: 1-13105Arch Coal, Inc.(Exact name of registrant as specified in its charter)Delaware(State or other jurisdictionof incorporation or organization)43-0921172(I.R.S. EmployerIdentification 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) 994-2700Securities registered pursuant to Section 12(b) of the Act:Title of Each ClassName of Each Exchange on Which RegisteredCommon Stock, $.01 par valueNYSESecurities registered pursuant to Section 12(g) of the Act: NoneIndicate 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 xIndicate 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 preceding12 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 andposted 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 andpost 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 thebest 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 Table of ContentsIndicate 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 “largeaccelerated 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 xThe aggregate market value of the voting stock held by non-affiliates of the registrant (excluding outstanding shares beneficially owned by directors, officers, other affiliates andtreasury 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 subsequentto 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 REFERENCEPortions of the registrant’s definitive proxy statement to be filed with the Securities and Exchange Commission in connection with the 2017 annualstockholders’ meeting to be held on May 4, 2017 are incorporated by reference into Part III of this Form 10-K. Table of ContentsTABLE OF CONTENTS PagePART I ITEM 1.BUSINESS6ITEM 1A.RISK FACTORS32ITEM 1B.UNRESOLVED STAFF COMMENTS43ITEM 2.PROPERTIES44ITEM 3.LEGAL PROCEEDINGS47ITEM 4.MINE SAFETY DISCLOSURES50 PART II ITEM 5.MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASESOF EQUITY SECURITIES51ITEM 6.SELECTED FINANCIAL DATA53ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS54ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK72ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA73ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUTING AND FINANCIAL DISCLOSURE73ITEM 9A.CONTROLS AND PROCEDURES73ITEM 9B.OTHER INFORMATION73 PART III ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE74ITEM 11.EXECUTIVE COMPENSATION74ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERMATTER74ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE74ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES74 PART IV ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES75ITEM 16.FORM 10-K SUMMARY753Table of ContentsIf 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 “Glossaryof 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” areto Arch Coal, Inc. and its subsidiaries.CAUTIONARY STATEMENTS REGARDING FORWARD‑LOOKING INFORMATIONThis report contains forward‑looking statements, within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E ofthe Securities Exchange Act of 1934, as amended, such as our expected future business and financial performance, and are intended to come within the safeharbor 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 thisreport. Forward‑looking statements by their nature address matters that are, to different degrees, uncertain. Actual results may vary significantly from thoseanticipated 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 orany 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;4Table of Contents•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 policiesand taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxides, nitrogen oxides, particulate matter orgreenhouse 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 thisreport.All forward‑looking statements in this report, as well as all other written and oral forward‑looking statements attributable to us or persons acting onour behalf, are expressly qualified in their entirety by the cautionary statements contained in this section and elsewhere in this report. These factors are notnecessarily 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 wecurrently 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‑lookingstatements, whether as a result of new information, future events or otherwise, except as may be required by the federal securities laws.5Table of ContentsPART I ITEM 1. BUSINESSIntroductionWe are one of the world’s largest coal producers. For the year ended December 31, 2016, we sold approximately 94 million tons of coal, includingapproximately 0.7 million tons of coal we purchased from third parties. We sell substantially all of our coal to power plants, steel mills and industrialfacilities. 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 ourmines and access to export facilities enable us to ship coal worldwide. We incorporate by reference the information about the geographical breakdown of ourcoal sales for the respective periods covered within this Form 10-K contained in Note 23 to the Consolidated Financial Statements.Our HistoryWe 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 acquisitionincluded 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 CanyonFuel Company, which operated three mines in Utah. In October 1998, we acquired a leasehold interest in the Thundercloud reserve, a 412‑million‑ton federalreserve 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 NorthRochelle mine adjacent to our Black Thunder operation. In September 2004, we acquired a leasehold interest in the Little Thunder reserve, a 719‑million‑tonfederal 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 miningcomplexes (Hobet 21, Arch of West Virginia, Samples and Campbells Creek) and approximately 455 million tons of coal reserves in Central Appalachia toMagnum 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 oflow‑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 UnitedStates.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 CodeOn 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 theU.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 thebankruptcy proceedings, each Debtor operated its business as a “debtor in possession” under the jurisdiction of the Court and in accordance with theapplicable 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 ofReorganization 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. 1334.6Table of ContentsOn 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 andliabilities in conformity with the guidance for the acquisition method of accounting for business combinations. In addition to fresh start accounting, ourconsolidated financial statements reflect all impacts of the transactions contemplated by the Plan. Under the provisions of fresh start accounting, a new entityhas been created for financial reporting purposes. We selected an accounting convenience date of October 1, 2016 for purposes of applying fresh startaccounting 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 impactof the Plan provisions and the application of fresh start accounting. As such, our financial statements for the Successor will not be comparable in manyrespects 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 ourConsolidated Financial Statements included within this Form 10-K.Coal CharacteristicsEnd users generally characterize coal as thermal coal or metallurgical coal. Heat value, sulfur, ash, moisture content, and volatility, in the case ofmetallurgical coal, are important variables in the marketing and transportation of coal. These characteristics help producers determine the best end use of aparticular 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 itcontains 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 thehighest carbon content and, therefore, the highest heat value, nearing 15,000 Btus per pound. Bituminous coal, used primarily to generate electricity and tomake 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 Btusper 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 valueranging 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 aresult 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 seamand 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 sulfurcontents, 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 animportant 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 todetermine 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 foruse 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, highmoisture content decreases the heat value and increases the weight of the coal, thereby making it more expensive to transport. Moisture content in coal, on anas‑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 ofcoke produced from a given coal or the amount of coke that certain types of coal will yield. These characteristics may be important elements in determiningthe value of the metallurgical coal we produce and market.7Table of ContentsThe Coal IndustryBackground. . Coal is mined globally using various methods of surface and underground recovery. Coal is used primarily for the production ofelectric 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 ofcoal 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 Chinawith 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 coalproduction occurs in the United States at mines located in Wyoming, Colorado, Illinois, Kentucky and West Virginia. Metallurgical coal is produced atoperations in West Virginia and Kentucky. Heat value and sulfur content are the most important variables in the economic marketing and transportation ofthermal 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. Customersare responsible for transportation - typically using third party carriers. There are some agreements where we retain responsibility for the coal during deliveryto 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 agentcontracts 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 environmentallyresponsible 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 EnergyInformation Administration (EIA.) The coal we produced fueled approximately 4% of the electricity produced in the U.S. in 2016. We also exported 7% ofour 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. metallurgicalcoal 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 producersof other energy sources including natural gas, renewables and nuclear, as well as other non-coal based forms of steel production. We compete with other coalproducers 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, theprice of coal is affected by the relative supply and demand of competitive coal, transportation, availability and price of other non-coal forms of powerproduction, 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, coordinatingtransportation, 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 equivalentto 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. Departmentof Energy estimates that current domestic recoverable coal reserves could supply enough electricity to satisfy domestic demand for over 150 years.8Table of ContentsCoal is mined from coal fields throughout the United States, with the major production centers located in the western United States, the Appalachianregion and the Interior. According to the EIA and Mine Safety and Health Administration (MSHA), U.S. coal production declined by an estimated170 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 UnitedStates declined from an estimated 507 million short tons in 2015 to 407 million short tons in 2016. The Powder River Basin is located in northeasternWyoming and southeastern Montana and is the largest producing region in the United States. Coal from this region is sub-bituminous coal with low sulfurcontent 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 ofcoal produced in other regions because Powder River Basin coal has a lower heat content, however it is produced from thick seams using surface recoverymethods thus, has a lower cost of production. The Western Bituminous region includes Colorado, Utah and southern Wyoming. Coal from this regiontypically 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 certainquality 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 from222 million short tons in 2015 to 183 million short tons in 2016. Appalachian coal is located near the prolific eastern shale-gas producing regions. CentralAppalachian thermal coal is further disadvantaged for power generation because of the depletion of economically attractive reserves, permitting issues andincreasing costs of production. However, all U.S. metallurgical coal is produced in Appalachia and the relative scarcity and high-quality of this coal allowsfor a pricing premium over thermal coal. Appalachia, while still a major producer of thermal coal, is undergoing a shift towards heavier reliance onmetallurgical 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 from10,300 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 contentranging 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 tothe 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 IllinoisBasin 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, coalfrom the Illinois Basin can generally be used by electric power generation facilities that have installed emissions control devices, such as scrubbers.Coal Mining MethodsThe geological characteristics of our coal reserves largely determine the coal mining method we employ. We use two primary methods of miningcoal: 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 miningoperations 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 thenremove the overburden with heavy earth‑moving equipment, such as draglines, power shovels, excavators and loaders. Once exposed, we drill, fracture andsystematically remove the coal using haul trucks or conveyors to transport the coal to a preparation plant or to a loadout facility. We reclaim disturbed areasas part of our normal mining activities. After final coal removal, we use draglines, power shovels, excavators or loaders to backfill the remaining pits with theoverburden removed at the beginning of the process. Once we have replaced the overburden and topsoil, we reestablish vegetation and plant life into thenatural habitat and make other improvements that have local community and environmental benefits.9Table of ContentsThe following diagram illustrates a typical dragline surface mining operation:10Table of ContentsUnderground Mining. We use underground mining methods when coal is located deep beneath the surface. We have included the identity andlocation 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 longrectangular coal blocks. Hydraulically powered supports temporarily hold up the roof of the mine while a rotating drum mechanically advances across theface 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 tothe surface. Once coal is extracted from an area, the roof is allowed to collapse in a controlled fashion. The following diagram illustrates a typicalunderground mining operation using longwall mining techniques: Room‑and‑Pillar Mining. Room‑and‑pillar mining is effective for small blocks of thin coal seams. In room‑and‑pillar mining, a network of rooms iscut 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 totransport 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% ofthe 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 workersretreat. As retreat mining occurs, the roof is allowed to collapse in a controlled fashion.11Table of ContentsThe following diagram illustrates our typical underground mining operation using room‑and‑pillar mining techniques:Coal Preparation and Blending. We crush the coal mined from our Powder River Basin mining complexes and ship it directly from our mines to thecustomer. Typically, no additional preparation is required for a saleable product. Coal extracted from some of our underground mining operations containsimpurities, 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 coalpreparation 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 thosemines 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 thedifference in the density between coal and waste rock and, for the very fine fractions, the separation process relies on the difference in surface chemicalproperties 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 usedense 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 thanits 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 isspun 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, whensuspended 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 columnwhere 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.12Table of ContentsOur Mining OperationsGeneral. At December 31, 2016, we operated 12 active mines in the United States. The Company’s reportable business segments are based on twodistinct lines of business, metallurgical and thermal, and may include a number of mine complexes. The Company manages its coal sales by market, not byindividual mining complex. Geology, coal transportation routes to customers, and regulatory environments also have a significant impact on our marketingand operations management. Mining operations are evaluated based on Adjusted EBITDAR, per-ton cash operating costs (defined as including all miningcosts 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 withgenerally accepted accounting principles, and items excluded from Adjusted EBITDAR are significant in understanding and assessing our financialcondition. Therefore, Adjusted EBITDAR should not be considered in isolation, nor as an alternative to net income, income from operations, cash flows fromoperations or as a measure of our profitability, liquidity or performance under generally accepted accounting principles. The Company used AdjustedEBITDAR to measure the operating performance of its segments and allocate resources to the segments. Furthermore, analogous measures are used byindustry analysts to evaluate the Company’s operating performance. Investors should be aware that the Company’s presentation of Adjusted EBITDAR maynot be comparable to similarly titled measures used by other companies. The Company’s reportable segments are the Powder River Basin (PRB) segmentcontaining the Company’s primary thermal operations in Wyoming; the Metallurgical (MET) segment, containing the Company’s metallurgical operationsin 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 October2 through December 31, 2016, January 1 through October 1, 2016 and the years ended December 31, 2015 and 2014, see Note 25 of the ConsolidatedFinancial Statements.In general, we have developed our mining complexes and preparation plants at strategic locations in close proximity to rail or barge shippingfacilities. Coal is transported from our mining complexes to customers by means of railroads, trucks, barge lines, and ocean‑going vessels from terminalfacilities. We currently own or lease under long‑term arrangements a substantial portion of the equipment utilized in our mining operations. We employsophisticated preventative maintenance and rebuild programs and upgrade our equipment to ensure that it is productive, well‑maintained andcost‑competitive.13Table of ContentsThe following table provides a summary of information regarding our active mining complexes as of December 31, 2016, including the total salesassociated 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, plantand 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) PredecessorSuccessor Mining ComplexCaptiveMines(1)MiningEquipmentRailroad20142015Jan1-Oct1,2016Oct2-Dec31,2016Total Cost ofProperty, Plantand Equipmentat December 31,2016Total AssignedRecoverableReserves (Million tons)($ millions)(Million tons)Powder River Basin: Black ThunderSD, SUP/BN101.299.549.018.9$263.8968.5Coal CreekSD, SUP/BN9.47.85.52.743.1146.0Metallurgical: Lone MountainU(3)CMNS/CSX1.91.60.90.414.49.5Mountain LaurelULW, CMCSX1.72.01.20.424.013.2BeckleyUCMCSX1.00.90.70.334.924.5SentinelUCMCSX1.10.90.80.326.99.8LeerULW, CMCSX2.72.93.11.0200.738.3Other Thermal: West ElkULW, CMUP6.55.12.41.631.756.2ViperUCM—2.22.11.30.320.538.3Coal‑MacSL, ENS/CSX2.82.41.50.530.223.0Totals 130.5125.266.426.4$690.21,327.3S = Surface mineD = DraglineUP = Union Pacific RailroadU = Underground mineL = Loader/truckCSX = CSX Transportation S = Shovel/truckBN = Burlington Northern‑Santa Fe Railway E = Excavator/truckNS = 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 aremines 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 thetable 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 theCumberland River mining complex, which was idled in 2014. We sold 0.8 million tons of coal from these two mining complexes in 2014.14Table of ContentsPowder River BasinBlack Thunder. Black Thunder is a surface mining complex located on approximately 35,800 acres in Campbell County, Wyoming. The BlackThunder 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 968.5million 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 rateof 190 million tons per year. Several large tracts of coal adjacent to the Black Thunder mining complex have been nominated for lease, and other potentiallarge 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 viathe 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 a15,000‑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 miningcomplex 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 approximately146.0 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 arate 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 BurlingtonNorthern 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 thanthree hours.MetallurgicalLone Mountain. Lone Mountain is an underground mining complex located on approximately 54,000 acres in Harlan County, Kentucky and LeeCounty, 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 tonsof 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 a1,200‑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 andBoone County, West Virginia. Underground mining operations at the Mountain Laurel mining complex extract High-vol B metallurgical coal and thermalcoal from the Cedar Grove and Alma seams. The Mountain Laurel mining complex has approximately 13.2 million tons of proven and probable reserves atDecember 31, 2016.The complex currently consists of one underground mine operating a longwall and three continuous miner sections, a preparation plant and aloadout 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 highquality, low‑volatile metallurgical coal in the Pocahontas No. 3 seam. The Beckley mining complex had approximately 24.5 million tons of proven andprobable 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 a10,000‑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 approximately25,500 acres in Barbour County, West Virginia. Mining operations currently extract High-vol A15Table of Contentsmetallurgical coal from the Clarion coal seam. Coal from the Sentinel mining complex is processed through the preparation plant and shipped by CSX rail tocustomers. 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 ourTygart 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 inless than four hours.Other ThermalWest Elk. West Elk is an underground mining complex located on approximately 17,800 acres in Gunnison County, Colorado. The West Elk miningcomplex 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 milliontons 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 ourcustomers 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 centralIllinois 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 isprocessed 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 ofproven and probable reserves.Coal‑Mac. The surface mining complex is located on approximately 46,000 acres in Logan and Mingo Counties, West Virginia. Surface miningoperations 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 ofproven 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 andRagland. We ship coal trucked to the Ragland loadout facility directly to our customers via the Norfolk Southern railroad. The Ragland loadout facility canload 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. Wewash 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 loada 10,000‑ton train in about four hours.Sales, Marketing and TradingOverview. Coal prices are influenced by a number of factors and can vary materially by region. The price of coal within a region is influenced bymarket conditions, coal quality, transportation costs involved in moving coal from the mine to the point of use and mine operating costs. For example, higherheat and lower ash content generally result in higher prices, and higher sulfur and higher ash content generally result in lower prices within a givengeographic region.The cost of coal at the mine is also influenced by geologic characteristics such as seam thickness, overburden ratios and depth of undergroundreserves. 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 aparticular geographic region, underground mining, which is the primary mining method we use in certain of our Appalachian mines, is generally moreexpensive 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 becauseof the higher16Table of Contentscapital costs, including costs for construction of extensive ventilation systems, and higher per unit labor costs due to lower productivity associated withunderground mining.Our sales, marketing and trading functions are principally based in St. Louis, Missouri and consist of sales and trading, transportation anddistribution, quality control and contract administration personnel as well as revenue management. We also have sales personnel in our Singapore andLondon 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 whichwe 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 industrialfacilities. For the year ended December 31, 2016, we derived approximately 15% of our total coal revenues from sales to our three largest customers, SouthernCompany, 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 majorcoal-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 foreigncountries 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 and2015, trade receivables related to metallurgical‑quality coal sales totaled $88.0 million and $32.8 million, respectively, or 48% and 28% of total tradereceivables, 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$175,296Asia124,170Central and South America55,085North America100,425Brokered Sales—Total$454,976Long-Term Coal Supply ArrangementsAs 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 thecontract. Long-term contracts allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and salesprices. In 2016, we sold approximately 76% of our coal under long-term supply arrangements. The majority of our supply contracts include a fixed price forthe 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 pricingsystem. 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 exceedingfive years. At December 31, 2016, the average volume‑weighted remaining term of our long-term contracts was approximately 2.00 years, with remainingterms ranging from one to five years. At December 31, 2016, remaining tons under long-term supply agreements, including those subject to price re-opener orextension 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 agreementsresult from competitive bidding and negotiations with customers. Consequently, the terms of these contracts vary by customer, including base priceadjustment features, price re‑opener terms, coal quality requirements, quantity parameters, permitted sources of supply, future regulatory changes, extensionoptions, force majeure, termination, damages and assignment provisions. Our long‑term supply contracts typically contain provisions to adjust the base pricedue to new statutes, ordinances or regulations. Additionally, some of our contracts contain provisions that allow for the recovery of costs affected bymodifications or changes in the interpretations or application of any applicable statute by local, state or federal government authorities. These provisionsonly apply to the base price of coal contained in these supply contracts. In some circumstances, a significant adjustment in base price can lead to terminationof the contract.17Table of ContentsCertain of our contracts contain index provisions that change the price based on changes in market based indices or changes in economic indices orboth. 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‑determinedtime. 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 toterminate the contract. In addition, certain of our contracts contain clauses that may allow customers to terminate the contract in the event of certain changesin 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 insome cases the volume specified may vary depending on the customer consumption requirements. Most of our coal sales agreements contain provisionsrequiring us to deliver coal within certain ranges for specific coal characteristics such as heat content (for thermal coal contracts), volatile matter (formetallurgical coal contracts), and for both types of contracts, sulfur, ash and moisture content. Failure to meet these specifications can result in economicpenalties, 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 serioustransportation problems that affect us or unanticipated plant outages that may affect the buyer. Our contracts also generally provide that in the event a forcemajeure circumstance exceeds a certain time period, the unaffected party may have the option to terminate the purchase or sale in whole or in part. Somecontracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer. Agreements between our customers and therailroads 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 coalfrom different mines, including third‑party mines, as long as the replacement coal meets quality specifications and will be sold at the same equivalentdelivered 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 onour 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 ourcoal while on our property.Trading. In addition to marketing and selling coal to customers through traditional coal supply arrangements, we seek to optimize our coalproduction and leverage our knowledge of the coal industry through a variety of other marketing, trading and asset optimization strategies. From time totime, we may employ strategies to use coal and coal‑related commodities and contracts for those commodities in order to manage and hedge volumes and/orprices associated with our coal sales or purchase commitments, reduce our exposure to the volatility of market prices or augment the value of our portfolio oftraditional assets. These strategies may include physical coal contracts, as well as a variety of forward, futures or options contracts, swap agreements or otherfinancial instruments.We maintain a system of complementary processes and controls designed to monitor and manage our exposure to market and other risks that mayarise as a consequence of these strategies. These processes and controls seek to preserve our ability to profit from certain marketing, trading and assetoptimization strategies while mitigating our exposure to potential losses. You should see Item 7A, entitled “Quantitative and Qualitative Disclosures AboutMarket 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 oftransportation. We generally sell coal used for domestic consumption free on board (f.o.b.) at the mine or nearest loading facility. Our domestic customersnormally 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 stabledelivery costs. Transportation can be a large component of a purchaser’s total cost. Although the purchaser pays the freight, transportation costs still areimportant to coal mining companies because the purchaser may choose a supplier largely based on cost of transportation. Transportation costs borne by thecustomer vary greatly based on each customer’s proximity to the mine and our proximity to the loadout facilities. Trucks and overland conveyors haul coalover shorter distances, while barges, Great Lake carriers and ocean vessels move coal to export markets and domestic markets requiring shipment over theGreat 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 BurlingtonNorthern‑Santa Fe railroad and the Union Pacific railroad. We generally transport coal produced at our18Table of ContentsAppalachian mining complexes via the CSX railroad or the Norfolk Southern railroad. Besides rail deliveries, some customers in the eastern United Statesrely 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 exportterminals. We transport our coal to Atlantic coast terminals, Pacific cost terminals or terminals along the Gulf of Mexico for transportation to internationalcustomers. Our international customers are generally responsible for paying the cost of ocean freight. We may also sell coal to international customersdelivered 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 inNewport News, Virginia. The facility has a rated throughput capacity of 20 million tons of coal per year and ground storage capacity of approximately1.7 million tons. The facility primarily serves international customers, as well as domestic coal users located along the Atlantic coast of the United States.CompetitionThe coal industry is intensely competitive. The most important factors on which we compete are coal quality, delivered costs to the customer andreliability of supply. Our principal domestic competitors include Contura Energy, Coronado Coal LLC, Cloud Peak Energy, CONSOL Energy Inc. andPeabody 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 alsocompete 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 oneor 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 electricalpower generation. Costs and other factors relating to these alternative fuels, such as safety and environmental considerations, affect the overall demand forcoal as a fuel.SuppliersPrincipal supplies used in our business include petroleum‑based fuels, explosives, tires, steel and other raw materials as well as spare parts and otherconsumables used in the mining process. We use third‑party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services andconstruction. We use sole source suppliers for certain parts of our business such as explosives and fuel, and preferred suppliers for other parts of our businesssuch as dragline and shovel parts and related services. We believe adequate substitute suppliers are available. For more information about our suppliers, youshould see Item 1A, “Risk Factors-Increases in the costs of mining and other industrial supplies, including steel‑based supplies, diesel fuel and rubber tires, orthe 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 MattersFederal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety and theenvironment, including the protection of air quality, water quality, wetlands, special status species of plants and animals, land uses, cultural and historicproperties and other environmental resources identified during the permitting process. Reclamation is required during production and after mining has beencompleted. Materials used and generated by mining operations must also be managed according to applicable regulations and law. These laws have, and willcontinue 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 tothe extensive, comprehensive and changing regulatory requirements, violations during mining operations occur from time to time. We cannot assure you thatwe have been or will be at all times in complete compliance with such laws and regulations. Expenditures we incur to maintain compliance with allapplicable federal and state laws have been and are expected to continue to be significant. Federal and state mining laws and regulations require us to obtainsurety 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 fordomestic coal producers.Future laws, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, may requiresubstantial increases in equipment and operating costs and delays, interruptions or a termination of operations, the extent to which we cannot predict. Futurelaws, regulations or orders may also cause coal to19Table of Contentsbecome 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 permitsand approvals, we may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposedproduction or processing of coal may have upon the environment. For example, in order to obtain a federal coal lease, an environmental impact statementmust 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 andimplementation requirements imposed by federal, state and local authorities may be costly and time consuming and may delay commencement orcontinuation of mining operations. In the states where we operate, the applicable laws and regulations also provide that a mining permit or modification canbe delayed, refused or revoked if officers, directors, shareholders with specified interests or certain other affiliated entities with specified interests in theapplicant or permittee have, or are affiliated with another entity that has, outstanding permit violations. Thus, past or ongoing violations of applicable lawsand 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 forrestoring, upon the completion of mining operations, the mined property to its prior condition or other authorized use. Typically, we submit the necessarypermit applications several months or even years before we plan to begin mining a new area. Some of our required permits are becoming increasingly moredifficult and expensive to obtain, and the application review processes are taking longer to complete and becoming increasingly subject to challenge, evenafter a permit has been issued.Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the lawsdescribed 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. Miningoperators must obtain SMCRA permits and permit renewals from the Office of Surface Mining, which we refer to as OSM, or from the applicable state agencyif the state agency has obtained regulatory primacy. A state agency may achieve primacy if the state regulatory agency develops a mining regulatory programthat is no less stringent than the federal mining regulatory program under SMCRA. All states in which we conduct mining operations have achieved primacyand 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 thedecision was later reversed on jurisdictional grounds, the extent to which the rule applied to fills was left unaddressed. On December 12, 2008, OSM finalizeda rulemaking regarding the interpretation of the stream buffer zone provisions of SMCRA which confirmed that excess spoil from mining and refuse from coalpreparation 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 infederal 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 theFederal Register. The revisions reinstated the previous version of the rule, but did not announce a new interpretation of the rule regarding the ability toconstruct excess spoil fills. On December 19, 2016, OSM finalized the “Stream Protection Rule,” a re-written version of the stream buffer zone rule whichwould have required coal operators to restrict mining within 100 feet of waterways. The rule would have also required states to impose additional informationgathering and monitoring at and around coal mining sties and would have mandated new financial assurance and reclamation requirements. This rule couldhave restricted coal producers’ ability to develop new mines, or could have required coal producers to modify existing operations, curtailing surface mineoperations in and near streams, especially in Appalachia. However, on February 2, 2017, Congress voted to repeal the stream protection rule under theCongressional 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 control20Table of Contentsfor underground mines; surface runoff and drainage control; establishment of suitable post mining land uses; and revegetation. We begin the process ofpreparing 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 andhistorical resources; geology; soils; vegetation; aquatic organisms; wildlife; potential for threatened, endangered or other special status species; surface andground water hydrology; climatology; riverine and riparian habitat; and wetlands. The geologic data and information derived from the other surveys and/orassessments are used to develop the mining and reclamation plans presented in the permit application. The mining and reclamation plans address theprovisions and performance standards of the state’s equivalent SMCRA regulatory program, and are also used to support applications for other authorizationsand/or permits required to conduct coal mining activities. Also included in the permit application is information used for documenting surface and mineralownership, variance requests, access roads, bonding information, mining methods, mining phases, other agreements that may relate to coal, other minerals, oiland gas rights, water rights, permitted areas, and ownership and control information required to determine compliance with OSM’s Applicant ViolatorSystem, 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 thoroughtechnical review. Also, before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of all reclamationobligations. After the application is submitted, a public notice or advertisement of the proposed permit is required to be given, which begins a notice periodthat 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 toprepare, 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. Thevariability in time frame required to prepare the application and issue the permit can be attributed primarily to the various regulatory authorities’ discretionin 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 permitto 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 feeon 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 perton 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 relatedto 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 othermiscellaneous 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. Thesechanges 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 ofDecember 31, 2016, we posted an aggregate of approximately $528.3 million in surety bonds for reclamation purposes and secured $54.7 million in letters ofcredit and cash for reclamation bonding obligations. In addition, we had approximately $199.2 million of surety bonds, cash and letters of credit outstandingat 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 andcoal 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 effecton our business and results of operations,” contained in Item 1A, “Risk Factors—Risk Related to Our Operations,” for a discussion of certain risks associatedwith our surety bonds.Mine Safety and Health. Stringent safety and health standards have been imposed by federal legislation since Congress adopted the Mine Safety andHealth Act of 1969. The Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposedcomprehensive safety and health standards on all aspects of mining operations. In addition to federal regulatory programs, all of the states in which weoperate also have programs aimed at improving mine safety and health. Collectively, federal and state safety and health regulation in the coal miningindustry 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 securepayment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medicalexpenses to claimants who last worked in the coal industry prior to July 1,21Table of Contents1973. 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 forcoal 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 theUnited 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. Directimpacts on coal mining and processing operations include Clean Air Act permitting requirements and emissions control requirements relating to particulatematter which may include controlling fugitive dust. The Clean Air Act also indirectly affects coal mining operations, for example, by extensively regulatingthe emissions of fine particulate matter measuring 2.5 micrometers in diameter or smaller, sulfur dioxide, nitrogen oxides, mercury and other compoundsemitted by coal‑fueled power plants and industrial boilers, which are the largest end‑users of our coal. Continued tightening of the already stringentregulation of emissions is likely, such as the Mercury and Air Toxics Standard (MATS), finalized in 2011 and discussed in more detail below. In addition, theU.S. Environmental Protection Agency, which we refer to as the EPA, has issued regulations on additional emissions, such as greenhouse gases (GHG’s), fromnew, modified, reconstructed and existing electric generating units, including coal-fired plants. Other GHG regulations apply to industrial boilers (seediscussion 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 affectedpower plants have sought to comply with these requirements by switching to lower sulfur fuels, installing pollution control devices, reducingelectricity generating levels or purchasing or trading sulfur dioxide emissions allowances. Although we cannot accurately predict the futureeffect of this Clean Air Act provision on our operations, we believe that implementation of Phase II has been factored into the pricing of the coalmarket.•Particulate Matter. The Clean Air Act requires the EPA to set national ambient air quality standards, which we refer to as NAAQS, for certainpollutants associated with the combustion of coal, including sulfur dioxide, particulate matter, nitrogen oxides and ozone. Areas that are not incompliance with these standards, referred to as non‑attainment areas, must take steps to reduce emissions levels. For example, NAAQS currentlyexist for particulate matter measuring 10 micrometers in diameter or smaller (PM10) and for fine particulate matter measuring 2.5 micrometers indiameter or smaller (PM2.5), and the EPA revised the PM2.5 NAAQS on December 14, 2012, making it more stringent. The states were requiredto make recommendations on nonattainment designations for the new NAAQS in late 2013. The EPA issued final designations for most areas ofthe country in 2012 and made some revisions in 2015. Individual states must now identify the sources of emissions and develop emissionreduction plans. These plans may be state‑specific or regional in scope. Under the Clean Air Act, individual states have up to 12 years from thedate of designation to secure emissions reductions from sources contributing to the problem. Future regulation and enforcement of the newPM2.5 standard, as well as future revisions of PM standards, will affect many power plants, especially coal‑fueled power plants, and all plants innon‑attainment areas.•Ozone. On October 26, 2015, the EPA published a final rule revising the existing primary and secondary NAAQS for ozone, reducing them to70ppb on an 8-hour average. On November 17, 2016, the EPA issued a proposed implementation rule on non-attainment area classification anstate implementation plans (SIPS). Significant additional emission control expenditures will likely be required at certain coal‑fueled powerplants to meet the new stricter NAAQS. Nitrogen oxides, which are a byproduct of coal combustion, are classified as an ozone precursor. As aresult, emissions control requirements for new and expanded coal‑fueled power plants and industrial boilers will continue to become moredemanding in the years ahead. The new standard is subject to pending judicial challenge and potential legislative action, with at least one billintroduced 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 reducethe transport of ozone on prevailing winds from the Midwest and South to states in the Northeast, which said that they could not meet federal airquality standards because of migrating pollution. The program was designed to reduce nitrous oxide emissions by one million tons per year in22 eastern states and the District of Columbia. Phase II reductions were required by May 2007. As a result of the program, many power plantswere required to install additional emission control measures, such as selective catalytic reduction devices.22Table of ContentsInstallation of additional emission control measures has made it more costly to operate coal‑fueled power plants, which could make coal a lessattractive fuel.•Interstate Transport. The EPA finalized the Clean Air Interstate Rule, which we refer to as CAIR, in March 2005. CAIR called for power plantsin 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 nowin 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 theDistrict 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 revisedtransport rule on August 2, 2010 (75 Fed. Reg. 45209) to address attainment of the 1997 ozone NAAQS and the 2006 PM2.5 NAAQS. The rulewas 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, theFederal 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 multipleexisting 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 theAugust 21, 2012 District of Columbia Circuit decision, remanding the case back to the District of Columbia Circuit. The EPA then requestedthat the court lift the CSAPR stay and toll the CSAPR compliance deadlines by three years. On October 23, 2014, the District of ColumbiaCircuit granted the EPA’s request, and that court later dismissed all pending challenges to the rule on July 28, 2015 but it remanded some statebudgets to EPA for further consideration. CSAPR Phase 1 implementation began in 2015, with Phase 2 beginning in 2017. CSAPR generallyrequires greater reductions than under CAIR. As a result, some coal‑fired power plants will be required to install costly pollution controls or shutdown which may adversely affect the demand for coal. Finally, in October 2016, the EPA issued an update to the CSAPR to address interstatetransport of air pollution under the more recent 2008 ozone NAAQS and the state budgets remanded by the D.C. Circuit. Consolidated judicialchallenges 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 wasfinalized April 16, 2012, and required compliance for most plants by 2015. In addition, before the court decision vacating the CAMR, somestates had either adopted the CAMR or adopted state‑specific rules to regulate mercury emissions from power plants that are more stringent thanthe CAMR. MATS compliance, coupled with state mercury and air toxics laws and other factors have required many plants to install costlycontrols, 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 economiccosts in determining whether to regulate. The case was remanded to the D.C. Circuit. The EPA began reconsideration of costs, and petitionersunsuccessfully sought a stay of the rule in the Supreme Court in February 2016. In April 2016, the EPA issued a final finding that it isappropriate and necessary to set standards for emissions of air toxics from coal- and oil-fired power plants. That finding is now being challengedin court. Therefore, the rule remains in effect until further order of the D.C. Circuit. The D.C. Circuit recently denied petitioners’ motion totemporarily 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, nationalwilderness 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 wouldhave to23Table of Contentsreduce 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 actionagainst states to finalize implementation plans and was slowly dealing with the state Regional Haze SIPs that were submitted, which resulted inthe National Parks Conservation Association commencing litigation in the D.C. Circuit Court of Appeals on August 3, 2012, against the EPAfor failure to enforce the rule (National Parks Conservation Act v. EPA, D.C. Cir). Industry groups, including the Utility Air Regulatory Grouphave 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 totake action on regional haze SIPs before the agency for 42 states and the District of Columbia. The EPA has completed those actions for all butseveral states in its first planning period (2008-2010). In many eastern states, the EPA has allowed states to meet “best available controltechnology” (BART) requirements for power plants through compliance with CAIR and CSAPR (a policy under pending litigation). Other stateshave had BART imposed on a case-by-case basis, and where the EPA found SIPs deficient, it disapproved them and issued FIPs. It is possiblethat the EPA may continue to increase the stringency of control requirements imposed under the Regional Haze Program as it moves toward thenext 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 andaround federally protected areas. This program may also require certain existing coal‑fueled power plants to install additional control measuresdesigned to limit haze‑causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. Theselimitations 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 equipmentrequired 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 withrespect to greenhouse gases such as carbon dioxide and the relationship that greenhouse gases may have with perceived global warming, continue to attractsignificant public and scientific attention. For example, the Fourth and Fifth Assessment Reports of the Intergovernmental Panel on Climate Change haveexpressed concern about the impacts of human activity, especially from fossil fuel combustion, on global climate issues. As a result of the public andscientific attention, several governmental bodies increasingly are focusing on global climate issues and, more specifically, levels of emissions of carbondioxide from coal combustion by power plants. Future regulation of greenhouse gas emissions in the United States could occur pursuant to future U.S. treatyobligations, 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 gasemissions. Further, the United States and a number of international development banks, such as the World Bank, the European Investment Bank andEuropean Bank for Reconstruction and Development, have announced that they will no longer provide financing for the development of new coal-fueledpower 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, nosuch federal proposals have been adopted into law to date. In the absence of U.S. federal legislation on these topics, the U.S. Environmental ProtectionAgency (the “EPA”) has been the primary source of federal oversight, although future regulation of greenhouse gases and global climate matters in the UnitedStates could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act, federal adoption of a greenhouse gasregulatory 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 andcan decide against regulation only if the EPA determines that carbon dioxide does not significantly contribute to climate change and does not endangerpublic health or the environment. Although the Supreme Court’s holding did not expressly involve the EPA’s authority to regulate greenhouse gas emissionsfrom stationary sources, such as coal-fueled power plants, the EPA since has determined on its own that it has the authority to regulate greenhouse gas24Table of Contentsemissions from power plants, and the EPA has published a formal determination that six greenhouse gases, including carbon dioxide, endanger both thepublic 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 toreduce carbon dioxide emissions from electrical power generation by 32% by 2030 relative to 2005 levels through reduction of emissions from coal-burningpower plants and increased use of renewable energy and energy conservation methods. Under the Clean Power Plan, states are free to reduce emissions byvarious means and must submit emissions reduction plans to the EPA by September 2016 or, with an approved extension, September 2018. If a state has notsubmitted 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 hasdivided the country into three regions based on connected regional electricity grids. States are to implement their plans by focusing on (i) increasing thegeneration 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 useregionally available low carbon generation sources when substituting for in-state coal generation and coordinate with other states to develop multi-stateplans. Following the adoption, 27 states sued the EPA, claiming that the EPA overstepped its legal authority in adopting the Clean Power Plan. In February2016, 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 SupremeCourt 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 SupremeCourt 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 isprojected 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 referto as NSPS, for carbon dioxide emissions from new, modified, and reconstructed power plants under the Clean Air Act. One of the primary issues in theselawsuits 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. Oralarguments in this case are scheduled for April 2017. Should the EPA’s regulations be upheld by the court, they could materially impact the ability ofcustomers 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 toaddress climate change over the next several decades. This agreement entered into force in November 2016 after more than 70 countries, including the UnitedStates, ratified or otherwise agreed to be bound by the agreement. The United States was among the countries that submitted its declaration of intendedgreenhouse gas reductions in early 2015, stating its intention to reduce U.S. greenhouse gas emissions by 26-28% by 2025 compared to 2005 levels. Whetherand to what extent the United States meets its stated intention likely depends on several factors, including whether the presently-stayed Clean Power Plan (ora comparable alternative) is implemented. The Trump Administration reportedly is evaluating the United States’ continued participation in the ParisAgreement. Regardless of the extent to which the United States ultimately participates in these reductions, over the long term, international participation inthe Paris Agreement framework could reduce overall demand for coal which could have a material adverse impact on us. These effects could be more adverseto 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 greenhousegas reduction initiatives. Some states also have enacted legislation or regulations requiring electricity suppliers to use renewable energy sources to generate acertain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources. For example, nine northeasternstates currently are members of the Regional Greenhouse Gas Initiative, which is a mandatory cap-and-trade program established in 2005 to cap regionalcarbon dioxide emissions from power plants. Six midwestern states and one Canadian province entered into the Midwestern Regional Greenhouse GasReduction Accord to establish voluntary regional greenhouse gas reduction targets and develop a voluntary multi-sector cap-and-trade system to help meetthe targets, although it has been reported that the members no longer are actively pursuing the group’s activities. Lastly, California and Quebec remainmembers 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 statesand 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 orother regional group, may25Table of Contentshave 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 thata 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 ourcustomers 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 coalmining operations by restricting the discharge of pollutants, including dredged and fill materials, into waters of the United States. The Clean Water Actprovisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. Recentcourt decisions and regulatory actions have created uncertainty over Clean Water Act jurisdiction and permitting requirements that could variously increaseor 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 areprotective of water quality standards through the National Pollutant Discharge Elimination System, which we refer to as the NPDES, or anequally stringent program delegated to a state regulatory agency. Regular monitoring, reporting and compliance with performance standards arepreconditions 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, andpersistent non‑compliance could lead to significant penalties, compliance costs and delays in coal production. In addition, the imposition offuture restrictions on the discharge of certain pollutants into waters of the United States could increase the difficulty of obtaining andcomplying with NPDES permits, which could impose additional time and cost burdens on our operations. You should see Item 3, “LegalProceedings,” 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 toTotal Maximum Daily Load, which we refer to as TMDL, regulations. The TMDL regulations establish a process for calculating the maximumamount of a pollutant that a water body can receive while maintaining state water quality standards. Pollutant loads are allocated among thevarious sources that discharge pollutants into that water body. Mine operations that discharge into water bodies designated as impaired will berequired to meet new TMDL allocations. The adoption of more stringent TMDL‑related allocations for our coal mines could require more costlywater 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 waterquality standards. The issuance and renewal of permits for the discharge of pollutants to waters that have been designated as “high quality” aresubject to anti‑degradation review that may increase the costs, time and difficulty associated with obtaining and complying with NPDESpermits.Under the Clean Water Act, citizens may sue to enforce NPDES permit requirements. Beginning in 2012, multiple citizens’ suits were filed inWest Virginia against mine operators for alleged violations of NPDES permit conditions requiring compliance with West Virginia’s waterquality standards. Some of the lawsuits alleged violations of water quality standards for selenium, whereas others alleged that discharges ofconductivity and sulfate were causing violations of West Virginia water quality standards that prohibit adverse effects to aquatic life. The suitssought penalties as well as injunctive relief that would limit future discharges of selenium, conductivity or sulfate through the implementationof expensive treatment technologies. The federal district court for the Southern District of West Virginia has ruled in favor of the citizen suitgroups in multiple suits alleging violations of the water quality standard for selenium and in two suits alleging violations of water qualitystandards due to discharge of conductivity (one of which was upheld on appeal by the United States Court of Appeals for the Fourth Circuit inJanuary 2017). Additional rulings requiring operators to reduce their discharges of selenium, conductivity or sulfate could result in largetreatment expenses for mine operators.Citizens may also sue under the Clean Water Act when pollutants are being discharged without NPDES permits. Beginning in 2013, multiplecitizens’ 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 beenterminated following the completion of reclamation. While it is difficult to predict the outcome of such suits, any determination that dischargesfrom valley fills require NPDES permits could result in increased compliance costs following the completion of mining at our operations.26Table of Contents•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 certaininstances, man‑made conveyances that have a hydrologic connection to such streams or wetlands. Under the Clean Water Act, coal companiesare required to obtain a Section 404 permit from the Army Corps of Engineers, which we refer to as the Corps, prior to conducting such miningactivities. The Corps is authorized to issue general “nationwide” permits for specific categories of activities that are similar in nature and thatare determined to have minimal adverse effects on the environment. Permits issued pursuant to Nationwide Permit 21, which we refer to asNWP 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 tostrengthen environmental protections. There must be appropriate mitigation in accordance with nationwide general permit conditions ratherthan less restricted state‑required mitigation requirements, and permit holders must receive explicit authorization from the Corps beforeproceeding with proposed mining activities.Notwithstanding the additional environmental protections designed in the NWP 21, on July 15, 2009, the Corps proposed to immediatelysuspend 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 thatcan be filled in the course of mining operations. The Corps’ decisions regarding the use of NWP 21 does not prevent the Company’s operationsfrom seeking an individual permit under § 404 of the CWA, nor does it restrict an operation from utilizing another version of the nationwidepermit, 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 miningoperations through its requirements for the management, handling, transportation and disposal of hazardous wastes. . Many mining wastes are excluded fromthe 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 lawsregarding the proper management and disposal of waste material. In June 2010, the EPA released a proposed rule to regulate the disposal of certain coalcombustion residuals, which we refer to as CCR. The proposed rule set forth two very different options for regulating CCR under RCRA. The first optioncalled for regulation of CCR as a hazardous waste under Subtitle C, which creates a comprehensive program of federally enforceable requirements for wastemanagement and disposal. The second option utilized Subtitle D, which would give the EPA authority to set performance standards for waste managementfacilities and would be enforced primarily through citizen suits. The proposal left intact the so-called Bevill exemption for beneficial uses of CCR. The EPAfinalized the CCR rule on December 19, 2014, setting nationwide solid nonhazardous waste standards for CCR disposal. On April 17, 2015, the EPAfinalized regulations under the solid waste provisions (Subtitle D) of RCRA and not the hazardous waste provisions (Subtitle C) which became effective onOctober 19, 2015. The final rule establishes national minimum criteria for existing and new CCR landfills, surface impoundments and lateral expansions, andalso establishes structural integrity criteria for new and existing surface impoundments (including establishing requirements for owners and operators toconduct periodic structural integrity-related assessments). The criteria include location restrictions, design and operating criteria, groundwater monitoringand corrective action, closure requirements and post-closure care and recordkeeping, notification and internet posting requirements. While classification ofCCR as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase our customers' operating costs andpotentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, could lead to citizen suitenforcement against our customers under RCRA or other federal or state laws and potentially reduce the demand for coal. In another development regardingcoal combustion wastes, the EPA conducted an assessment of impoundments and other units that manage residuals from coal combustion and that containfree liquids following a massive coal ash spill in Tennessee in 2008, the EPA contractors conducted site assessments at many impoundments and is requiringappropriate 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 theassessment on its web site as the responses are received. Future regulations resulting from the EPA coal combustion refuse assessments may impact the abilityof the Company’s utility customers to continue to use coal in their power plants.27Table of ContentsComprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation andLiability Act, which we refer to as CERCLA, and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements forthreatened 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 disposalactivity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, incertain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used bycoal companies in operations, such as chemicals, could trigger the liability provisions of the statute. Thus, coal mines that we currently own or havepreviously owned or operated, and sites to which we sent waste materials, may be subject to liability under CERCLA and similar state laws. In particular, wemay 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 possibleextinction. Protection of threatened, endangered and other special status species may have the effect of prohibiting or delaying us from obtaining miningpermits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species. Anumber of species indigenous to our properties are protected under the Endangered Species Act or other related laws or regulations. Based on the species thathave been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected underthe 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 morestringent protective measures be applied to threatened, endangered or other special status species or to their critical habitat, then we could experienceincreased 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, weincur costs to design and implement blast schedules and to conduct pre‑blast surveys and blast monitoring. In addition, the storage of explosives is subject tostrict regulatory requirements established by four different federal regulatory agencies. For example, pursuant to a rule issued by the Department of HomelandSecurity in 2007, facilities in possession of chemicals of interest, including ammonium nitrate at certain threshold levels, must complete a screening reviewin 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 thosepreviously discussed. These additional laws include, for example, the Safe Drinking Water Act, the Toxic Substance Control Act and the EmergencyPlanning and Community Right‑to‑Know Act.EmployeesAt December 31, 2016, we employed approximately 4,025 full and part‑time employees. We believe that our relations with employees are good.28Table of ContentsExecutive Officers of the RegistrantThe 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:NameAgePositionKenneth D. Cochran56Mr. Cochran has served as our Senior Vice President-Operations since August 2012. From May 2011 to August2012, Mr. Cochran served as Group President of our western operations, which included Thunder Basin CoalCompany, the Arch Western Bituminous Group, Arch of Wyoming and the Otter Creek development, and servedas President and General Manager of Thunder Basin Coal Company from 2005 to April 2011. Prior to joiningArch Coal in 2005, Mr. Cochran spent 20 years with TXU Corporation. Mr. Cochran currently serves on theboards of Knight Hawk Holdings, LLC, and Tongue River Holding Company.John T. Drexler47Mr. Drexler has served as our Senior Vice President and Chief Financial Officer since 2008. Mr. Drexler served asour Vice President-Finance and Accounting from 2006 to 2008. From 2005 to 2006, Mr. Drexler served as ourDirector of Planning and Forecasting. Prior to 2005, Mr. Drexler held several other positions within our financeand accounting department.John W. Eaves59Mr. Eaves has served as our Chief Executive Officer since 2012. Mr. Eaves served as our Chairman of the Boardfrom 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 theboards of the National Association of Manufacturers and the National Mining Association. Mr. Eaves waspreviously a director of Advanced Emissions Solutions, Inc. and former chairman of the National Coal Council.Robert G. Jones60Mr. Jones has served as our Senior Vice President-Law, General Counsel and Secretary since 2008. Mr. Jonesserved as Vice President-Law, General Counsel and Secretary from 2000 to 2008.Allen R. Kelley56Mr. 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 asour Director of Internal Audit. Prior to 2005, Mr. Kelley held various finance and accounting positions withinthe corporate and operations functions of Arch Coal, Inc.Paul A. Lang56Mr. Lang was elected our President and Chief Operating Officer in April 2015. He has served as our ExecutiveVice President and Chief Operating Officer since April 2012 and as our Executive Vice President-Operationsfrom August 2011 to April 2012. Mr. Lang served as Senior Vice President-Operations from 2006 throughAugust 2011, as President of Western Operations from 2005 through 2006 and President and General Manager ofThunder 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 ofthe Missouri University of Science & Technology, and is the former chairman of the University of Wyoming’sSchool of Energy Resources Council.Deck S. Slone53Mr. Slone has served as our Senior Vice President-Strategy and Public Policy since June 2012. Mr. Slone servedas our Vice President-Government, Investor and Public Affairs from 2008 to June 2012. Mr. Slone served as ourVice President-Investor Relations and Public Affairs from 2001 to 2008. Mr. Slone is the immediate past co-chairof 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 Universityin St. Louis.John A. Ziegler, Jr.50Mr. 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 ourSenior 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 andMarketing Administration. Mr. Ziegler joined Arch Coal in 2002 as Director-Internal Audit. Prior to joining ArchCoal, Mr. Ziegler held various finance and accounting positions with bioMerieux and Ernst & Young.29Table of ContentsAvailable InformationWe file annual, quarterly and current reports, and amendments to those reports, proxy statements and other information with the Securities andExchange Commission. You may access and read our filings without charge through the SEC’s website, at sec.gov. You may also read and copy anydocument 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 at1‑800‑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 furnishthem 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 CityPlaceDrive, Suite 300, St. Louis, Missouri, 63141 Attention: Senior Vice President-Strategy and Public Policy. The information on our website is not part of thisAnnual Report on Form 10-K.30Table of ContentsGLOSSARY OF SELECTED MINING TERMSCertain 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 selectedmining terms and the definitions we attribute to them.Assigned reservesRecoverable reserves designated for mining by a specific operation.Brown coalCoal of gross calorific value of less than 5700 kilocalories per kilogramme (kcal/kg), which includes lignite andsub‑bituminous coal where lignite has a gross calorific value of less than 4165 kcal/kg and sub‑bituminous coal has agross calorific value between 4165 kcal/kg and 5700 kcal/kg.BtuA measure of the energy required to raise the temperature of one pound of water one degree of Fahrenheit.Compliance coalCoal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus, requiring no blending or othersulfur dioxide reduction technologies in order to comply with the requirements of the Clean Air Act.Continuous minerA machine used in underground mining to cut coal from the seam and load it onto conveyors or into shuttle cars in acontinuous operation.DraglineA 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 largeamounts of overburden as it is dragged across the excavation area and redeposit the overburden in another area.Hard coalCoal of gross calorific value greater than 5700 kcal/kg on an ashfree but moist basis and further disaggregated intoanthracite, coking coal and other bituminous coal.Longwall miningOne of two major underground coal mining methods, generally employing two rotating drums pulled mechanicallyback and forth across a long face of coal.Low‑sulfur coalCoal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btus.Preparation plantA facility used for crushing, sizing and washing coal to remove impurities and to prepare it for use by a particularcustomer.Probable reservesReserves for which quantity and grade and/or quality are computed from information similar to that used for provenreserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequatelyspaced.Proven reservesReserves 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 andmeasurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineralcontent of reserves are well established.ReclamationThe restoration of land and environmental values to a mining site after the coal is extracted. The process commonlyincludes “recontouring” or shaping the land to its approximate original appearance, restoring topsoil and plantingnative grass and ground covers.Recoverable reservesThe amount of proven and probable reserves that can actually be recovered from the reserve base taking into accountall mining and preparation losses involved in producing a saleable product using existing methods and under currentlaw.ReservesThat part of a mineral deposit which could be economically and legally extracted or produced at the time of thereserve determination.Room‑and‑pillar miningOne 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 reservesRecoverable reserves that have not yet been designated for mining by a specific operation.31Table of ContentsITEM 1A. RISK FACTORS.Our business involves certain risks and uncertainties. In addition to the risks and uncertainties described below, we may face other risks anduncertainties, some of which may be unknown to us and some of which we may deem immaterial and the following review of important risk factors shouldnot be construed as exhaustive and should be read in conjunction with other cautionary statements that are included herein or elsewhere. If one or more ofthese risks or uncertainties occur, our business, financial condition or results of operations may be materially and adversely affected.Risks Related to Emergence from Bankruptcy ProtectionInformation contained in our historical financial statements will not be comparable to the information contained in our financial statements after theapplication 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 thefinancial 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 freshstart accounting, we will allocate our reorganization value to the fair value of assets and liabilities in conformity with the guidance for the acquisitionmethod of accounting for business combinations. Adjustments to the carrying amounts could be material and could affect prospective results of operations asbalance sheet items are settled, depreciated, amortized or impaired. This will make it difficult for stockholders to assess our performance in relation to priorperiods. 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 startaccounting 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 taxableincome 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 Section382 of the Internal Revenue Code (the “Code”) that occurred on the Effective Date of the Plan (“the Emergence Ownership Change”). The limitationresulting 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 withcarryforward net operating losses, AMT tax credits and an overall limitation of certain tax deductions. NOLs and AMT credits generated after the EmergenceOwnership 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 ourtaxable year.Risks Related to Our OperationsCoal 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 adecline 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 futurefor 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 andenergy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions or providing forincreased funding and incentives for alternative energy sources;•the proximity to, capacity of and cost of transportation and port facilities;32Table of Contents•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 thoseaimed 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 andregulations), an oversupplied market and increased competition particularly from non-U.S. suppliers taking advantage of a strong dollar, we have recentlyexperienced a sustained and significant downturn in coal pricing over the last several years. Pricing may be adversely affected or we may need to reduceproduction 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 couldmaterially 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 severalyears 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 formetallurgical 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 extremevolatility of security prices, severely limited liquidity and credit availability, and resulted in declining valuations of assets. If there are downturns ineconomic conditions, our customers’ and our businesses, financial conditions or results of operations could be adversely affected. Furthermore, because wetypically 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 lagbehind any general economic recovery. During unfavorable economic conditions we are focused on cost control and capital discipline, but there can be noassurance 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 productionwithin the coal industry, both domestically and internationally, and decelerating steel demand in China have, and could further, materially reduce coal pricesand therefore materially reduce our revenues and profitability. Potential changes to international trade agreements, trade concessions or other political andeconomic arrangements may benefit coal producers operating in countries other than the United States. We cannot assure you that we will be able to competeon 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, ourability to ship our coal to international customers depends on port capacity, which is limited. Increased competition within the coal industry for internationalsales 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 itis 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. Inaddition, substantial overcapacity exists in the coal industry and several other large coal companies have also filed, and others may file, bankruptcyproceedings 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 orfurther consolidation in the coal industry or current or future bankruptcy proceedings of our coal competitors will not adversely affect our competitiveposition.In addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas. Natural gas pricing hasdeclined 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 pricescould reduce or eliminate construction of any new coal-fired power plants. This trend has, and could continue to have, a material adverse effect on demandand prices for our coal.33Table of ContentsAny change in the coal consumption of electric power generators could result in less demand and lower prices for coal, which could materially andadversely 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 amountof coal consumed for electric power generation is affected primarily by the overall demand for electricity, the availability, quality and price of competingfuels for power generation and governmental regulations. Overall economic activity and the associated demands for power by industrial users can havesignificant effects on overall electricity demand and can be caused by a number of factors. An economic slowdown can significantly slow the growth ofelectricity demand and could result in reduced demand for coal. For example, declines in the rate of international economic growth in countries such asChina, India or other developing countries could further negatively impact the demand for U.S. coal and result in a continuing oversupply of coal in themarketplace. 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 generatorsto 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 thishas 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 befueled 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 ashaving a lower environmental impact than coal-fueled generation. In addition, state and federal mandates for increased use of electricity from renewableenergy sources also have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to userenewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standardalthough none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economicsof renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by electric powergenerators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and resultsof operations.Our coal mining operations are subject to operating risks that are beyond our control, which could result in materially increased operating expenses anddecreased 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 ourcoal 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 causedamage 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 orcustomers;•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 coalbedmethane 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 coalvolume 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 operatingcosts could increase significantly. In addition, if our insurance coverage is limited or excludes certain of these conditions or events, then we may not be ableto recover any of the losses we may incur as a result of such conditions or events, some of which may be substantial.34Table of ContentsA decline in demand for metallurgical coal would limit our ability to sell our coal into higher-priced metallurgical markets and could substantially affectour business.Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or highquality steam coal, depending on the prevailing conditions in the metallurgical and steam coal markets. We decide whether to mine, process and market thesecoals 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 anumber of factors when making this assessment, including the difference between the current and anticipated future market prices of steam coal andmetallurgical coal and the increased costs incurred in producing coal for sale in the metallurgical market instead of the steam market. A decline in prices inthe metallurgical market relative to the steam market could cause us, as well as our competitors, to shift coal from the metallurgical market to the steammarket, 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 ourbusiness.Our profitability depends substantially on our ability to mine and process, in a cost-effective manner, coal reserves that possess the qualitycharacteristics desired by our customers. As we mine, our coal reserves decline. As a result, our future success depends upon our ability to acquire additionalcoal that is economically recoverable. If we fail to acquire or develop additional coal reserves, our existing reserves will eventually be depleted. We may notbe able to obtain replacement reserves when we require them. If available, replacement reserves may not be available at favorable prices, or we may not becapable of mining those reserves at costs that are comparable with our existing coal reserves. In certain locations, leases for oil, natural gas and coalbedmethane reserves are located on, or adjacent to, some of our reserves, potentially creating conflicting interests between us and lessees of those interests. Otherlessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seekdamages 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 availablefinancing, 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 replacementreserves, our future production may decrease significantly and our operating results may be negatively affected. In addition, we may not be able to minefuture 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 thegovernment’s management of federally-owned coal. The delay in the LBA process caused by the moratorium could prevent us from obtaining replacementreserves 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 inany number of ways including by limiting our ability to mine reserves under ongoing or future applications, by increasing the costs or timeframe associatedwith obtaining leases under the LBA program, by making it uneconomical for us to participate in the programs or by preventing us from obtainingreplacement 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 ourestimates 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, updatedgeological models and mining recovery data, the tonnage contained in new lease areas acquired and estimated costs of production and sales prices. There arenumerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond ourcontrol, 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 inareas where we currently mine;•the percentage of coal ultimately recoverable;35Table of Contents•the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, andother 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 andexplosives, 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 asprepared by different engineers, or by the same engineers at different times, may vary materially due to changes in the above factors and assumptions. Actualproduction recovered from identified reserve areas and properties, and revenues and expenditures associated with our mining operations, may vary materiallyfrom estimates. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues and/orhigher 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, ourability 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 havefluctuated in recent years while the market terms of such bonds have generally become more unfavorable to mine operators. These changes in the terms of thebonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. In addition, federal and state regulators areconsidering making financial assurance requirements with respect to mine closure and reclamation more stringent. Because we are required by state andfederal 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 orsecurity 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 asufficient 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 ofroof 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 trucksand other heavy machinery, particularly at our Black Thunder mining complex. There has been some consolidation in the supplier base providing miningmaterials to the coal industry, such as with suppliers of explosives in the U.S. and both surface and underground equipment globally, that has limited thenumber 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 takeadvantage of cost savings from larger volumes of purchases and to ensure security of supply. If the prices of mining and other industrial supplies, particularlysteel based supplies, diesel fuel and rubber tires, increase, our operating costs could be negatively affected. In addition, if we are unable to procure thesesupplies, 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 tofill 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. Inaddition, we purchase coal from third parties that we sell to our customers. Operational difficulties at contractor-operated mines or mines operated by thirdparties from whom we purchase coal, changes in demand for contract miners from other coal producers and other factors beyond our control could affect theavailability, pricing, and quality of coal produced for or purchased by us. Disruptions in the quantities of coal produced for or purchased by us could impairour 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 orderor 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 couldincrease.36Table of ContentsOur profitability depends upon the long-term coal supply agreements we have with our customers. Changes in purchasing patterns in the coal industrycould 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 newcustomers. 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 productseffectively, 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 adverselyaffected. 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 intoagreements 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 competingfuels, 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 duringspecified events beyond their control. Most of our long-term coal supply agreements also contain provisions requiring us to deliver coal that satisfies certainquality specifications, such as heat value, sulfur content, ash content, hardness and ash fusion temperature. These provisions in our long-term coal supplyagreements 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 duringadverse economic conditions or if we incur financial or other economic penalties as a result of these provisions of our long-term supply agreements. For moreinformation 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 materiallyand 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 acustomer 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 thecustomer’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, thebankruptcy 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 thatmay be less creditworthy, thereby increasing the risk we bear for customer payment default. Some power plant owners may have credit ratings that are belowinvestment grade, or may become below investment grade after we enter into contracts with them. In addition, competition with other coal suppliers couldforce 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 otherpressures 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 insignificant 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 couldadversely affect our ability to mine the associated coal reserves. We may not verify title to our leased properties or associated coal reserves until we havecommitted to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permitsand 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 ourability to conduct mining operations. Similarly, our leasehold interests may be subject to superior property rights of other third parties. In order to conductour mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimumquantity of coal and require us to pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest toterminate.37Table of ContentsThe availability, reliability and cost-effectiveness of transportation facilities and fluctuations in transportation costs could affect the demand for our coalor 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 ourcustomers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, route closures andother events beyond our control could impair our ability to supply coal to our customers. Since we do not have long-term contracts with all transportationproviders we utilize, decreased performance levels over longer periods of time could cause our customers to look to other sources for their coal needs. Inaddition, increases in transportation costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy whencompared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of theUnited States or abroad. If we experience disruptions in our transportation services or if transportation costs increase significantly and we are unable to findalternative transportation providers, our coal mining operations may be disrupted, we could experience a delay or halt of production or our profitabilitycould 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 internationalcustomers. Our ability to maintain and grow our export sales revenue and margins depends on a number of factors, including the existence of sufficient andcost-effective export terminal capacity for the shipment of coal to foreign markets. At present, there is limited terminal capacity for the export of coal intoforeign markets. Our access to existing and future terminal capacity may be adversely affected by regulatory and permit requirements, environmental andother legal challenges, public perceptions and resulting political pressures, operational issues at terminals and competition among domestic coal producersfor access to limited terminal capacity, among other factors. If we are unable to maintain terminal capacity, or are unable to access additional future terminalcapacity 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 aminimum 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 sufficientexport sales to meet our minimum obligations under these contracts we are still obligated to make payments to the railway or port facility, which could havea 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 andapproximately 42% of our total coal revenues from sales to our ten largest customers. We are currently discussing the extension of coal sales agreements withsome of these customers. However, we may be unsuccessful in obtaining coal supply agreements with those customers, and some or all of these customerscould discontinue purchasing coal from us. If any of those customers, particularly any of our three largest customers, was to significantly reduce thequantities 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 theresults 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 assetoptimization strategies. We maintain a system of complementary processes and controls designed to monitor and control our exposure to market and otherrisks as a consequence of these strategies. These processes and controls seek to balance our ability to profit from certain marketing, trading and assetoptimization strategies with our exposure to potential losses. While we employ a variety of risk monitoring and mitigation techniques, those techniques andaccompanying judgments cannot anticipate every potential outcome or the timing of such outcomes. In addition, the processes and controls that we use tomanage our exposure to market and other risks resulting from these strategies involve assumptions about the degrees of correlation or lack thereof amongprices of various assets or other market indicators. These correlations may change significantly in times of market turbulence or other unforeseencircumstances. 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 andcurrency risks. In addition, our international offices are selling our coal to new customers and customers in new countries, whose business practices andreputations are not as well known to us. We are also challenged by political risks by expanding internationally, including the potential for expropriation ofassets and limits on the repatriation of38Table of Contentsearnings. In the event that we are unable to effectively manage these new risks, our results of operations, financial position or cash flow could be adverselyaffected 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 confidentialinformation, 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 financialobligations for damages related to the theft or misuse of such information, any of which could have a substantial impact on our results of operations, financialcondition 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 anorderly transition. In addition, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled andqualified personnel, particularly personnel with mining experience. We cannot provide assurance that key personnel will continue to be employed by us orthat 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 creditfacilities, leases and other financing arrangements contain financial and other covenants that create limitations on our ability to borrow the full amount underour credit facilities, effect acquisitions or dispositions and incur additional debt and require us to comply with various affirmative covenants. The New FirstLien 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 certainsubsidiaries, partnerships and joint ventures, (vii) continuation of or change in business, (viii) restricted payments, (ix) payment of other indebtedness, (x) norestriction in agreements on dividends or certain loans, (xi) loans and investments, (ix) transactions with respect to Bonding Subsidiaries and (xiii) changes inorganizational documents. Our ability to comply with these provisions may be affected by events beyond our control and our failure to comply could resultin an event of default under the New First Lien Debt Facility.Risks Related to Environmental, Other Regulations and LegislationExtensive environmental regulations, including existing and potential future regulatory requirements relating to air emissions, affect our customers andcould 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 intothe air when coal is burned. The operations of our customers are subject to extensive environmental regulation particularly with respect to air emissions. Forexample, the federal Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, andother 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 toparticulate matter, ozone, haze, mercury, sulfur dioxide, nitrogen oxide and other air pollutants is in the process of being developed and implemented. TheClean Power Plan, under review by U.S. courts, would severely limit emissions of carbon dioxide which would adversely affect our ability to sell coal. Inaddition, 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 toevolve and develop and many new regulatory initiatives remain subject to review by federal or state agencies or the courts. Stringent air emissions limitationsare either in place or are likely to be imposed in the short to medium term, and these limitations will likely require significant emissions control expendituresfor many coal‑fueled power plants. As a result, these power plants may switch to other fuels that generate fewer of these emissions, may install more39Table of Contentseffective pollution control equipment that reduces the need for low sulfur coal, or may cease operations, possibly reducing future demand for coal and areduced need to construct new coal‑fueled power plants. Any switching of fuel sources away from coal, closure of existing coal‑fired plants, or reducedconstruction of new plants could have a material adverse effect on demand for and prices received for our coal. Alternatively, less stringent air emissionslimitations, particularly related to sulfur, to the extent enacted could make low sulfur coal less attractive, which could also have a material adverse effect onthe 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 affectingthe 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 byincreased governmental regulations and unfavorable lending and investment policies by financial institutions associated with concerns aboutenvironmental 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 togreenhouse gases such as carbon dioxide and the relationship that greenhouse gases may have with perceived climate change, continue to attract significantpublic and scientific attention. For example, the Fourth and Fifth Assessment Reports of the Intergovernmental Panel on Climate Change have expressedconcern about the impacts of human activity, especially from fossil fuel combustion, on global climate issues. As a result of the public and scientificattention, several governmental bodies increasingly are focusing on climate issues and, more specifically, levels of emissions of carbon dioxide from coalcombustion by power plants. The Clean Power Plan, a set of regulations promulgated by the EPA currently under review by U.S. courts would severely limitemissions of carbon dioxide which would adversely affect our ability to sell coal. Future regulation of greenhouse gas emissions in the United States couldoccur pursuant to future U.S. treaty obligations, statutory or regulatory changes and the federal, state or local level or otherwise. Enactment of laws or passageof regulations regarding greenhouse emissions from the combustion of coal by the U.S., some of its states or other countries, or other actions to limitemissions 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 powerplants, which also may adversely impact the future global demand for coal. Further, there have been recent efforts by members of the general financial andinvestment communities, such as investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to divest themselves andto promote the divestment of securities issued by companies involved in the fossil fuel extraction market, such as coal producers. Those entities also havebeen pressuring lenders to limit financing available to such companies. These efforts may adversely affect the market for our securities and our ability toaccess 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 towhich any particular law, regulation or policy impacts us will depend on several factors, including the substantive terms involved, the relevant time periodsfor 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 connectionwith coal mining. These include permits issued by various federal, state and local agencies and regulatory bodies. The permitting rules, and theinterpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by the regulators, all of which may makecompliance 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 submitobjections to requested permits and environmental impact statements prepared in connection with applicable regulatory processes, and otherwise engage inthe permitting process, including bringing citizens’ lawsuits to challenge the issuance of permits, the validity of environmental impact statements orperformance of mining activities. Accordingly, required permits may not be issued or renewed in a timely fashion or at all, or permits issued or renewed maybe conditioned in a40Table of Contentsmanner that may restrict our ability to efficiently and economically conduct our mining activities, any of which would materially reduce our production, cashflow 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 asfatalities, 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. Inthe event that these agencies order the closing of our mines, our coal sales contracts generally permit us to issue force majeure notices which suspend ourobligations to deliver coal under these contracts. However, our customers may challenge our issuances of force majeure notices. If these challenges aresuccessful, we may have to purchase coal from third‑party sources, if it is available, to fulfill these obligations, incur capital expenditures to re‑open themines and/or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time fordelivery 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 orlimit 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 suchas:•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 thosereclamation 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 andtime‑consuming and may delay commencement or continuation of exploration or production operations. We cannot assure you that we have been or will beat all times in compliance with the applicable laws and regulations. Failure to comply with these laws and regulations may result in the assessment ofadministrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or ceaseoperations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. Wemay incur material costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we are pursued forsanctions, 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 changeoperations significantly or incur increased costs. Such changes could have a material adverse effect on our financial condition and results of operations. Youshould see the section entitled “Environmental and Other Regulatory Matters” in Item 1 for more information about the various governmental regulationsaffecting us.41Table of ContentsIf 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 wellas most aspects of underground mining. We base our estimates of reclamation and mine closure liabilities on permit requirements, engineering studies andour engineering expertise related to these requirements. Our management and engineers periodically review these estimates. The estimates can changesignificantly if actual costs vary from our original assumptions or if governmental regulations change significantly. We are required to record newobligations as liabilities at fair value under generally accepted accounting principles. In estimating fair value, we considered the estimated current costs ofreclamation and mine closure and applied inflation rates and a third‑party profit, as required. The third‑party profit is an estimate of the approximate markupthat would be charged by contractors for work performed on our behalf. The resulting estimated reclamation and mine closure obligations could changesignificantly if actual amounts change significantly from our assumptions, which could have a material adverse effect on our results of operations andfinancial condition.Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, whichcould 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 toclaims for toxic torts, natural resource damages and other damages as well as for the investigation and cleanup of soil, surface water, groundwater, and othermedia. 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 otherowners/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. Liabilityunder 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 subjectto extensive regulation. Slurry impoundments can fail, which could release large volumes of coal slurry into the surrounding environment. Structural failureof 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 asliability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined-out areas, which can pose aheightened 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 theresulting 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 minedrainage,” 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 ispossible 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 wastesassociated 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 purchasingour 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 operatevalley fills and surface impoundments. Some of these permits are Clean Water Act § 404 permits issued by the Army Corps of Engineers (the Corps). Two ofour operating subsidiaries were identified in an existing lawsuit, which challenged the issuance of such permits and asked that the Corps be ordered torescind them. Two of our operating subsidiaries intervened in the suit to protect their interests in being allowed to operate under the issued permits, and theclaims 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 fromdecisions rendered prior to our intervention. The matter is pending before the U.S. District Court for the Southern District of West Virginia on oursubsididary’s motion for summary judgment. If the matter is resolved ultimately in a manner that is adverse to the interests of our operating subsidiaries, suchsubsidiaries’ operating results may be adversely impacted. For more information regarding this litigation matter you should see the section entitled “LegalProceedings—Permit Litigation Matters” under Item 3.42Table of ContentsChanges 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 theUnited States. These laws and regulations may change, sometimes dramatically, as a result of political, economic or social events or in response to significantevents. Environmental and other non-governmental organizations and activists, many of which are well funded, continue to exert pressure on regulators andother government bodies to enact more stringent laws and regulations. Changes in the legal and regulatory environment in which we operate may impact ourresults, increase our costs or liabilities, complicate or limit our business activities or result in litigation. Such legal and regulatory environment changes mayinclude changes in such items as: the processes for obtaining or renewing permits; federal lease by application programs; costs associated with providinghealthcare benefits to employees; health and safety standards; accounting standards; taxation requirements; and competition laws.ITEM 1B. UNRESOLVED STAFF COMMENTS.None.43Table of ContentsITEM 2. PROPERTIES.Our PropertiesAt December 31, 2016, we owned or controlled, primarily through long‑term leases, approximately 28,315 acres of coal land in Ohio, 1,060 acres ofcoal 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, 274,273acres 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 acresof 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 ofproperty in Alabama, Indiana, Washington, Arkansas, California, Utah and Texas. We lease approximately 84,958 acres of our coal land from the federalgovernment and approximately 22,385 acres of our coal land from various state governments. Certain of our preparation plants or loadout facilities arelocated on properties held under leases which expire at varying dates over the next 30 years. Most of the leases contain options to renew. Our remainingpreparation 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 theequipment utilized in their mining operations. You should see “Our Mining Operations” for more information about our mining operations, miningcomplexes and transportation facilities.Our Coal ReservesWe estimate that we owned or controlled approximately 2.1 billion tons of proven and probable recoverable reserves at December 31, 2016. Our coalreserve estimates at December 31, 2016 were prepared by our engineers and geologists and reviewed by Weir International, Inc., a mining and geologicalconsultant. Our coal reserve estimates are based on data obtained from our drilling activities and other available geologic data. Our coal reserve estimates areperiodically updated to reflect past coal production and other geologic and mining data. Acquisitions or sales of coal properties will also change theseestimates. 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. Indetermining whether our reserves meet this standard, we take into account, among other things, our potential inability to obtain a mining permit, the possiblenecessity 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 meetregulatory requirements and obtaining mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on sellingprices. We use various assumptions in preparing our estimates of our coal reserves. You should see “Inaccuracies in our estimates of our coal reserves couldresult in decreased profitability from lower than expected revenues or higher than expected costs” contained in Item 1A, “Risk Factors.”44Table of ContentsThe following tables present our estimated assigned and unassigned recoverable coal reserves at December 31, 2016:Total Assigned Reserves(Tons in millions) Total AssignedRecoverableReserves AsReceivedBtus per lb.(1) Sulfur Content (lbs. permillion Btus) Mining MethodPast ReserveEstimates Reserve Control Under- ProvenProbable<1.21.2-2.5>2.5LeasedOwnedSurfaceground20142015Wyoming1,1151,10961,04768—8,8311,115 1,115—1,4231,318Colorado5651556——11,50056——566553Central App.706463040—13,055682234713935Northern App.48435—47113,0111038—487440Illinois382315——3810,730326—383337Total1,3271,290371,133155399,3741,281461,1381891,7341,483(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) TotalUnassignedRecoverableReserves Sulfur Content Mining Method (lbs. per million Btus)As ReceivedReserve Control Under‑ ProvenProbable<1.21.2-2.5>2.5Btus per lb.(1)LeasedOwnedSurfacegroundWyoming2852394623748—8,457285—285—Colorado2822628——11,21728——28Central App.5849920251312,53011474018Northern App.1699277—168113,0008161—169Illinois28218795——28211,170572254278Total82258923328524129610,704389433329493(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 whichmay 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 topreliminary coal seam analysis to test sulfur content. Of these reserves, approximately 66% consist of compliance coal, or coal which emits 1.2 pounds or lessof sulfur dioxide per million Btus upon combustion, while an additional approximately 8% could be sold as low-sulfur coal. The balance is classified ashigh-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 ata 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 ofcoal lands and mineral rights of $0.4 billion.45Table of ContentsReserve Acquisition ProcessWe acquire a significant portion of the coal we control in the western United States through the lease‑by‑application (LBA) process. Under thisprocess, 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 acompetitive 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 finalbid is accepted by the BLM. After the LBA is awarded, the company then conducts the necessary testing to determine what amount can be classified asreserves.To initiate the LBA process, companies wanting to acquire additional coal must file an application with the BLM’s state office indicating interest ina specific coal tract. The BLM reviews the initial application to determine whether the application conforms to existing land‑use plans for that particular tractof 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 analysisor an environmental impact statement to be completed. This analysis or impact statement is subject to publication and public comment. The BLM mayconsult with other governmental agencies during this process, including state and federal agencies, surface management agencies, Native American tribes orbands, 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‑dayperiod.After the environmental analysis or environmental impact statement has been issued and a recommendation has been published that supports thelease 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 thatis based on its economic analysis and comparable sales analysis. Prior to the lease sale, companies interested in acquiring the lease must send sealed bids tothe BLM. The bid amounts for the lease are payable in five annual installments, with the first 20% installment due when the mining operator submits itsinitial 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 rentalong 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 theBLM 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 theBLM 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 valueestimate, 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 marketvalue 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 applicantcertain fees it paid in connection with the application process, for example the fees associated with the environmental analysis or environmental impactstatement, 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 existingLBAs through an agreed upon lease modification with the BLM. Once the BLM has issued a lease, the company must also complete the permitting processbefore 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 isproduced in commercial quantities. These leases require diligent development within the first ten years of the lease award with a required coal extraction of1.0% 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 maintaincontinuous 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 operationrequirements for the entire LMU. Some of our mines are also subject to coal leases with applicable state regulatory agencies and have different terms andconditions 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 developedduring the initial 10‑year development period or if certain other terms of the leases are not complied with, including the requirement to produce a minimumquantity of coal or pay a minimum production royalty, if applicable, the BLM or the applicable state regulatory agency can terminate the lease prior to theexpiration 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 thegovernment’s management of federally-owned coal. The review could take the form of a programmatic environmental impact statement, which allows abroader look at all aspects of federal coal leasing across regions46Table of Contentsand 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 inabilityto acquire additional coal reserves or our inability to develop coal reserves in an economically feasible manner may adversely affect our business,” containedin Item 1A. “Risk Factors” for more information.Title to Coal PropertyTitle to coal properties held by lessors or grantors to us and our subsidiaries and the boundaries of properties are normally verified at the time ofleasing or acquisition. However, in cases involving less significant properties and consistent with industry practices, title and boundaries are not completelyverified until such time as our independent operating subsidiaries prepare to mine such reserves. If defects in title or boundaries of undeveloped reserves arediscovered 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 leaseholdinterest 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 expireuntil the exhaustion of mineable and merchantable coal. Under current mining plans, substantially all reported leased reserves will be mined out within theperiod 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 ofthe 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, payableeither at the time of execution of the lease or in annual installments. In most cases, the prepaid royalty amount is applied to reduce future productionroyalties.From time to time, lessors or sublessors of land leased by our subsidiaries have sought to terminate such leases on the basis that such subsidiarieshave 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 theleases. Some of these allegations relate to leases upon which we conduct operations material to our consolidated financial position, results of operations andliquidity, 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 periodOctober 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, 2016from 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 fromthe 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 reservefigures 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, includingemployee injury claims. After conferring with counsel, it is the opinion of management that the ultimate resolution of these claims, to the extent notpreviously provided for, will not have a material adverse effect on our consolidated financial condition, results of operations or liquidity.Permit Litigation MattersSurface mines at our Mingo Logan and Coal-Mac mining operations were identified in an existing lawsuit brought by the Ohio Valley EnvironmentalCoalition (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 ArmyCorps of Engineers (Corps), allegedly in violation of the Clean Water Act and the National Environmental Policy Act. The lawsuit, brought by OVEC inSeptember 2005, originally was filed against the Corps for permits it had issued to four subsidiaries of a company unrelated to us or our operatingsubsidiaries. The suit claimed that the Corps had issued permits to the subsidiaries of the unrelated company that did not comply with the NationalEnvironmental 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 rescindedthe four permits, finding that the Corps had inadequately assessed the likely impact of valley fills on headwater streams and had relied on inadequate orunproven mitigation to offset those impacts. In the second order, the court entered a declaratory judgment that discharges of sediment from the valley fillsinto 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 forthe Fourth Circuit.47Table of ContentsBefore 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 toprogress 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 WaterAct 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 theNational Environmental Policy Act and no significant degradation under the Clean Water Act are entitled to deference. Such findings entitle the Corps toavoid preparing an environmental impact statement, the absence of which was one issue on appeal. These holdings also validated the type of mitigationprojects 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 notexceeded 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. Anappeal 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 nooutstanding legal issues remained for decision as a result of the Fourth Circuit’s February 2009 decision. By a series of motions, the United States obtainedextensions 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 (discussedbelow). 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 EPAAdministrator reviewed the “Recommended Determination” issued by the EPA Region 3. By Memorandum Opinion and Order dated November 2, 2010, thecourt granted the United States’ motion. On January 13, 2011, the EPA issued its “Final Determination” to withdraw the specification of two of the threewatersheds as a disposal site for dredged or fill material approved under the current Section 404 permit. The court was notified of the Final Determination andby 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 “FinalDetermination” then pending in federal court in Washington, D.C. A full account and status of this litigation surrounding the Final Determination is set forthin 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 caseto proceed on Mingo Logan’s Motion for Summary Judgment. Shortly thereafter, OVEC filed a motion for leave to file a seventh amended and supplementalcomplaint 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 forSummary Judgment on August 31, 2012, along with its Answer to the Seventh Amended and Supplemental Complaint and the matter remains pending beforethe court.EPA Actions Related to Water Discharges from the Spruce PermitBy 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 toMingo Logan under Section 404 of the Clean Water Act, claiming that “new information and circumstances have arisen which justify reconsideration of thepermit.” 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 ofOctober 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 andwildlife resources” and that it intends to issue a public notice of a proposed determination to restrict or prohibit discharges of fill material that already areapproved by the Corps’ permit. By federal register publication dated April 2, 2010, the EPA issued its “Proposed Determination to Prohibit, Restrict or Denythe 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 theClean Water Act, the EPA accepted written comments on its proposed action (sometimes known as a “veto proceeding”), through June 4, 2010 and conducteda 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 watershedsfor which filling is approved under the current48Table of ContentsSection 404 permit. Mingo Logan, along with the Corps, West Virginia DEP and the mineral owner, engaged in a consultation with the EPA as required bythe regulations, to discuss “corrective action” to address the “unacceptable adverse effects” identified. On January 13, 2011, the EPA issued its “FinalDetermination” pursuant to Section 404(c) of the Clean Water Act to withdraw the specification of two of the three watersheds approved in the currentSection 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 inWashington, D.C. seeking a ruling that the EPA has no authority under the Clean Water Act to veto a previously issued permit (Mingo Logan CoalCompany, 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. OnNovember 30, 2011, the court heard arguments from the parties limited only to the threshold issue of whether the EPA had the authority underSection 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). Thecourt deferred consideration of the remaining issue (i.e. whether the EPA’s “Final Determination” is otherwise lawful) until after consideration of thethreshold 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 validand 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 oralarguments 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 thematter 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 forRehearing 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 federaldistrict court for the District of Columbia for further consideration on the merits of the Final Determination. On September 30, 2014, the court entered anopinion and order denying Mingo Logan’s motion for summary judgment and granting the government’s motion for summary judgment. The court upheldthe Final Determination finding that EPA’s decision to withdraw the specifications for filling in Oldhouse Branch and Pigeonroost Branch under MingoLogan’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 ofAppeals 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 courtaffirmed the district court judgment thus upholding the EPA’s Final Determination.UMWA 1974 Pension Plan et al. v Peabody Energy and ArchOn July 16, 2015, the UMWA 1974 Pension Trust (“1974 Plan”) and its Trustees filed a Complaint for Declaratory Judgment against Peabody EnergyCorporation, Peabody Holding Company, LLC and Arch, in the U.S. District Court in Washington D.C., seeking an order from the court requiring thedefendants 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 thecourt to declare that Peabody and Arch are liable for Patriot’s withdrawal liability. With respect to Arch, plaintiffs allege that Arch engaged in actions toavoid 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 anamended complaint to reflect that Patriot formally rejected its obligations to contribute to the 1974 Plan, triggering a withdrawal. The amended complaintfurther 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 thiswithdrawal liability amount. Arch notified the District Court and the parties to the litigation of its bankruptcy filing and the automatic stay and, on January21, 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, Archand the 1974 Plan entered into a confidential agreement in principle to settle the withdrawal liability dispute, which agreement became effective onNovember 3, 2016.49Table of ContentsITEM 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 Reformand 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 endedDecember 31, 2016.50Table of ContentsPART IIITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITYSECURITIES.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 ofClass 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. Inaddition, 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 registrationrequirements 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 Stockissuable upon exercise of the Warrants. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under a plan of reorganizationfrom 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 planof 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 tradingmarket 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 onestockholder 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 Low2017: First Quarter (through February 16, 2017)$76.05 $68.652016: Fourth Quarter (from October 5, 2016)$85.16 $61.31We 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, subjectto applicable limitations under Delaware law, and will be dependent on our results of operations, financial condition, contractual restrictions and otherfactors deemed relevant by our Board of Directors.Stockholder Return Performance PresentationThe following graph compares the cumulative stockholder return from October 5, 2016, the date our common stock began trading following the PlanEffective 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 thePredecessor common stock bears no relation to the value of our existing common stock, the graph below reflects only our current existing common stock. Thepeer group consists of CONSOL Energy Inc. and Peabody Energy Corp. Peabody Energy Corp. filed for Chapter 11 bankruptcy protection, and its stocktraded 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 $100investment in our current existing common stock, in the peer group, and the index (with the reinvestment of all dividends) from October 5, 2016 throughDecember 31, 2016.51Table of Contents 10/5/201610/1611/1612/16 Arch Coal, Inc.100.00116.48123.86123.89S&P Midcap 400100.0097.32105.12107.42Peer Group100.0087.96106.6792.83The stock price performance included in this graph is not necessarily indicative of future stock price performance.52Table of ContentsITEM 6. SELECTED FINANCIAL DATA. SuccessorPredecessor(In thousands, except per share data)October 2throughDecember 31,2016January 1throughOctober 1, 2016Year EndedDecember 31,2015Year EndedDecember 31,2014Year EndedDecember 31,2013Year EndedDecember 31,2012Statement of Operations Data:(1)(1)(2) (3)(4)Revenues$575,688$1,398,709$2,573,260$2,937,119$3,014,357$3,768,126Asset impairment and mine closure costs—129,2672,628,30324,113220,879539,182Goodwill impairment————265,423330,680Income (loss) from operations46,118(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 operations33,4491,242,081(2,913,142)(558,353)(745,228)(738,915)Net income (loss) attributable to Arch Coal33,4491,242,081(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$9,913,791Working capital566,391522,465(4,361,009)1,023,3571,293,8491,337,035Current maturities of debt11,0386,6625,042,35312,19114,41917,557Long-term debt, less current maturities351,841353,27230,9535,064,8185,043,4545,008,232Other long-term obligations725,948786,015755,283695,881717,174825,080Noncurrent deferred income tax liability———422,809413,546664,182Arch Coal stockholders’ equity746,577687,483(1,244,289)1,668,1542,253,2492,854,567Cash Flow Data: Cash provided by (used in) operating activities84,192(228,218)(44,367)(33,582)55,742332,804Depreciation, depletion and amortization, includingamortization of sales contracts, net33,400190,853370,534405,561438,247500,319Capital expenditures15,21482,434119,024147,286296,984395,225Net proceeds from the issuance of long term debt———(4,519)623,5111,942,685Payments to retire debt, including redemption premium————628,660452,934Net decrease in borrowings under lines of credit andcommercial paper program—————(481,300)Dividend payments———2,12325,47542,440Operating Data: Tons sold26,81267,128127,632134,360139,607140,820Tons produced26,61966,658126,820132,614136,613135,934Tons purchased from third parties1934811,2871,1822,9254,32753Table of Contents(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 closureand asset impairment charges during the year; for additional information see Note 5 to the Consolidated Financial Statements, “Impairment Chargesand 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 BowieResources, LLC for $423 million. Canyon Fuel operated the Sufco and Skyline longwall mining complexes and the Dugout Canyon continuous mineroperation 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 curtailedproduction at other thermal mines. We incurred $523.6 million of closure and impairment costs relating to the closures, and recognized goodwillimpairment charges of $330.7 million. In addition, we refinanced our debt, increasing our average borrowing level to build cash and highly liquidinvestments 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 FinancialStatements, including the notes thereto, contained elsewhere herein. The selected financial information should be read in conjunction with the ConsolidatedFinancial 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 notcomparable with the financial statements after October 1, 2016. References to “Successor” refer to the Company after October 1, 2016, after giving effect tothe 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. OverviewOur results for the Successor period from October 2 through December 31, 2016 were impacted by strengthening of both the thermal andmetallurgical coal markets. The domestic thermal market rebounded somewhat from lows in the first half of 2016 as natural gas prices rose. Warmer thannormal summer temperatures, increasing natural gas exports, and flat to slightly declining natural gas supply supported natural gas pricing at levels thatallowed some thermal coals, particularly Powder River Basin coals, to compete economically for a larger share of electric generation. Additionally, pricing ininternational thermal coal markets strengthened sufficiently to make some thermal exports economically viable for certain of our operations in the Successorperiod.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 drivenby: a Chinese mandate to restrict its domestic coal supply; supply rationalization in North America; years of global underinvestment in the industry; andsome specific international supply disruptions, particularly in Australia. Although the majority of our metallurgical volume was committed and priced for theSuccessor period prior to the improvement in pricing, certain index-based and prompt sales reflected the higher prices. Late in the Successor period, promptmetallurgical pricing began to retrace from these highs as the Chinese loosened their supply restrictions and supply disruptions abated. International promptmetallurgical 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, togetherwith 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 thebankruptcy proceedings, each Debtor operated its business as a “debtor in possession” under the jurisdiction of the Court and in accordance with theapplicable provisions of the Bankruptcy Code and the orders of the Court.54Table of ContentsOn September 13, 2016, the Bankruptcy Court entered an order, Docket No. 1324, confirming the Debtors’ Fourth Amended Joint Plan of Reorganizationunder 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 andliabilities in conformity with the guidance for the acquisition method of accounting for business combinations. In addition to fresh start accounting, ourconsolidated financial statements reflect all impacts of the transactions contemplated by the Plan. Under the provisions of fresh start accounting, a new entityhas been created for financial reporting purposes. References to “Successor” in the financial statements and accompanying footnotes are in reference toreporting dates on or after October 2, 2016; references to “Predecessor” in the financial statements and accompanying footnotes are in reference to reportingdates through October 1, 2016 which includes the impact of the Plan provisions and the application of fresh start accounting. As such, our financialstatements for the Successor will not be comparable in many respects to its financial statements for periods prior to the adoption of fresh start accounting andprior to the accounting for the effects of the Plan. For further information on fresh start accounting, please see Note 3 to the Consolidated FinancialStatements, “Emergence from Bankruptcy and Fresh Start Accounting.”Results of Operations - SuccessorPeriod from October 2 through December 31, 2016Revenues. 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 throughDecember 31, 2016 (In thousands)Coal sales $575,688Tons 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 2through December 31, 2016: Successor October 2 throughDecember 31, 2016 (In thousands)Cost of sales (exclusive of items shown separately below) $470,644Depreciation, depletion and amortization 32,604Accretion on asset retirement obligations 7,634Amortization of sales contracts, net 796Change in fair value of coal derivatives and coal trading activities, net 396Selling, general and administrative expenses 22,836Other operating expense (income), net (5,340)Total costs, expenses and other $529,57055Table of ContentsCost of sales. Our cost of sales for the period from October 2 through December 31, 2016 consisted primarily of labor related costs (approximately25%), repairs and supplies (approximately 33%), operating taxes and royalties (approximately 22%), and transportation costs (approximately 12%). Seediscussion 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 developmentcosts (approximately 17%). This reflects the application of fresh start accounting. For further information on fresh start accounting, please see Note 3 to theConsolidated 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 surfaceoperations in the Powder River Basin.Selling, general and administrative expenses. Total selling, general and administrative expenses consist primarily of compensation costs of $15.3million, 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 andnet gains on asset sales of $5.4 million and net income from equity investments of $1.7 million, partially offset by miscellaneous expenses primarily relatedto our land company of $2.1 million.Non-operating expense. The following table summarizes non-operating expense for the period from October 2 through December 31, 2016: Successor October 2 throughDecember 31, 2016 (In thousands)Reorganization income (loss), net$(759)Nonoperating expenses in the current period are related to our reorganization. For further information on our successful reorganization, please seeNote 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 throughDecember 31, 2016 (In thousands)Provision for income taxes$1,156See further discussion in Note 14, to the Consolidated Financial Statements “Taxes,”.56Table of ContentsOperational Performance- SuccessorPeriod from October 2 through December 31, 2016Our mining operations are evaluated based on Adjusted EBITDAR, per-ton cash operating costs (defined as including all mining costs exceptdepreciation, depletion, amortization, accretion on asset retirements obligations, and pass-through transportation expenses), and on other non-financialmeasures, such as safety and environmental performance. Adjusted EBITDAR is defined as net income attributable to the Company before the effect of netinterest 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 ouremergence from bankruptcy, we have added accretion on asset retirement obligations as an adjustment to arrive at Adjusted EBITDAR. Adjusted EBITDAR isnot a measure of financial performance in accordance with generally accepted accounting principles, and items excluded from Adjusted EBITDAR aresignificant in understanding and assessing our financial condition. Therefore, Adjusted EBITDAR should not be considered in isolation, nor as an alternativeto net income, income from operations, cash flows from operations or as a measure of our profitability, liquidity or performance under generally acceptedaccounting principles. Furthermore, analogous measures are used by industry analysts to evaluate the Company’s operating performance. Investors should beaware 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 2throughDecember 31,2016Powder River Basin Tons sold (in thousands) 21,824Coal sales per ton sold $12.41Cash cost per ton sold $9.88Cash margin per ton sold $2.53Adjusted EBITDAR (in thousands) $55,765Metallurgical Tons sold (in thousands) 2,442Coal sales per ton sold $65.61Cash cost per ton sold $52.98Cash margin per ton sold $12.63Adjusted EBITDAR (in thousands) $30,819Other Thermal Tons sold (in thousands) 2,510Coal sales per ton sold $34.01Cash cost per ton sold $21.79Cash margin per ton sold $12.22Adjusted 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 ofthese 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 titledmeasures. Powder River Basin — Adjusted EBITDAR for the Successor period from October 2 through December 31, 2016 benefited from cost control effortsand rebounding demand driven by rising natural gas prices that increased the competitiveness of Powder River Basin coal for electric generation versus thecompeting fuel. Rising gas prices resulted from favorable summer heat, increased natural gas exports, both pipeline and liquefied natural gas, and flat toslightly 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 ininternational pricing for metallurgical coal. As discussed above, supply shortages driven by a Chinese mandate to restrict its domestic supply, supplyrationalization in North America, years of global underinvestment in the57Table of Contentsindustry, and some specific international supply disruptions, particularly in Australia, resulted in a significant increase in international prompt metallurgicalcoal prices. Our ability to take advantage of the rapid increase in prompt international pricing was muted due to having significant volumes for the periodcommitted and priced prior to the rapid increase. Our metallurgical segment sold 1.9 million tons of metallurgical coal and 0.5 million tons of associatedthermal coal in the Successor period. Longwall operations accounted for approximately 55% of our shipment volume in the period. Late in the Successorperiod prompt international metallurgical pricing began to retreat as loosening of Chinese supply restrictions and easing of supply disruptions began tomitigate the supply shortage.Other Thermal— Adjusted EBITDAR for the Successor period from October 2 through December 31, 2016 benefited from the increased natural gaspricing discussed in the Powder River Basin segment discussion above, and increased international thermal prices. These benefits were primarily recognizedat our West Elk operation where domestic opportunities increased and export opportunities became economic. Partially offsetting those positive trends wereoperating issues at our Viper operation’s largest customer that significantly reduced sales volume in the current period.Results of Operations - PredecessorPeriod from January 1 through October 1, 2016Revenues. 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 throughOctober 1, 2016 (In thousands)Coal sales $1,398,709Tons 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, and15% 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 1through October 1, 2016: Predecessor January 1 throughOctober 1, 2016 (In thousands)Cost of sales (exclusive of items shown separately below) $1,264,464Depreciation, depletion and amortization 191,581Accretion on asset retirement obligations 24,321Amortization of sales contracts, net (728)Change in fair value of coal derivatives and coal trading activities, net 2,856Asset impairment and mine closure costs 129,267Selling, general and administrative expenses 59,343Other operating expense (income), net (15,257)Total costs, expenses and other $1,655,84758Table of ContentsCost 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 discussionin “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 developmentcosts (approximately 11%). Accretion on asset retirement obligation. Approximately 70% of the accretion on our asset retirement obligation for the period from January 1through 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 idleoperations 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 determinedthat the value of these reserves was impaired. Also during this period we relinquished our interest in Millennium Bulk Terminal while retaining futurethroughput 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 $38.5million, 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 andnet gains on asset sales of $14.4 million and net income from equity investments of $5.3 million, partially offset by miscellaneous expenses primarily relatedto our land company of $7.3 million.Non-operating expense. The following table summarizes non-operating expense for the period from January 1 through October 1, 2016: Predecessor January 1 throughOctober 1, 2016 (In thousands)Net loss resulting from early retirement of debt and debt restructuring$(2,213)Reorganization income (loss), net1,630,041Total non-operating (expense) benefit$1,627,828Nonoperating expenses in the current period related to our proposed debt restructuring activities and Chapter 11 reorganization. For furtherinformation on our successful reorganization, please see Note 3 to the Consolidated Financial Statements, “Emergence from Bankruptcy and Fresh StartAccounting.”Benefit from income taxes. The following table summarizes our benefit from income taxes for the period from January 1 through October 1, 2016: Predecessor January 1 throughOctober 1, 2016 (In thousands)Benefit from income taxes$(4,626)See further discussion in Note 14 to the Consolidated Financial Statements, “Taxes,”.59Table of ContentsYear Ended December 31, 2015 Compared to Year Ended December 31, 2014Revenues. 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 theinformation 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 lowertons 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 December31, 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 $360,531Depreciation, depletion and amortization 379,345 418,748 39,403Accretion 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 15,440Other 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 transportationcosts on lower export sales volumes (a decrease of approximately $66 million), lower diesel fuel costs (approximately $88 million), improved productivity atour Leer longwall operation (approximately $28 million), savings associated with one sold and two idled Appalachian complexes (approximately $77million), 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 costsdecreased in the year ended December 31, 2015 due to the effect of lower production and sales volume, continued low capital spending levels, and the effectof 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 ofcertain assets. Our testing indicated impairment of several active and undeveloped properties. Impairment costs in the year ended December 31, 2015 includea 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, “ImpairmentCharges and Mine Closure Costs,” to the Consolidated Financial Statements for further discussion.60Table of ContentsLosses from disposed operations resulting from the Patriot Coal bankruptcy. In the year ended December 31, 2015 we recorded liabilities related toreclamation and employee obligations that we inherited as a result of the Patriot Coal bankruptcy. See further information regarding the losses related to thePatriot 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 decreasedwhen 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 increasedduring the year ended December 31, 2015, as a result of increased costs of $16.4 million related to shortfalls under throughput arrangements, and lower netgains 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 theinformation 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 $24.2million of legal and financial advisory fees associated with our debt restructuring efforts. Additionally, in the fourth quarter of 2015 we terminated ourrevolving credit agreement resulting in the write-off of $3.7 million of deferred financing costs.Provision for (benefit from) income taxes. The following table summarizes our benefit from income taxes for the year ended December 31, 2015 andcompares it with the information for the year ended December 31, 2014: Predecessor Year Ended December 31, Decrease 2015 2014 in Net Loss (In thousands)Provision for (benefit from) income taxes$(373,380) $25,634 $399,014The income tax benefit in the year ended December 31, 2015 compared to the income tax provision in the year ended December 31, 2014 waslargely due to the approximately $2.6 billion increase in asset impairment losses recorded in 2015 partially offset by the increase of a valuation allowancerelating to both federal and state net operating loss carryforwards. See further discussion in Note 14, “Taxes,” to the Consolidated Financial Statements forfurther discussion.61Table of ContentsOperational Performance - PredecessorOur mining operations are evaluated based on Adjusted EBITDAR, per-ton cash operating costs (defined as including all mining costs exceptdepreciation, depletion, amortization, accretion on asset retirements obligations, and pass-through transportation expenses), and on other non-financialmeasures, such as safety and environmental performance. Adjusted EBITDAR is defined as net income attributable to the Company before the effect of netinterest expense, income taxes, depreciation, depletion and amortization, the amortization of acquired sales contracts, the accretion on asset retirementobligations, and reorganization items, net. Adjusted EBITDAR may also be adjusted for items that may not reflect the trend of future results. In conjunctionwith our emergence from bankruptcy, we have added accretion on asset retirement obligations as an adjustment to arrive at Adjusted EBITDAR. AdjustedEBITDAR is not a measure of financial performance in accordance with generally accepted accounting principles, and items excluded from AdjustedEBITDAR are significant in understanding and assessing our financial condition. Therefore, Adjusted EBITDAR should not be considered in isolation, nor asan alternative to net income, income from operations, cash flows from operations or as a measure of our profitability, liquidity or performance under generallyaccepted accounting principles. Furthermore, analogous measures are used by industry analysts to evaluate the Company’s operating performance. Investorsshould 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 theyears ended December 31, 2015 and 2014. Predecessor January 1through October1, 2016 Year EndedDecember 31,2015 Year EndedDecember 31,2014Powder River Basin Tons sold (in thousands) 54,911 108,481 111,156Coal sales per ton sold $13.01 $13.15 $12.86Cash cost per ton sold $10.95 $10.54 $10.87Cash margin per ton sold $2.06 $2.61 $1.99Adjusted EBITDAR (in thousands) $113,185 $281,039 $218,731Metallurgical Tons sold (in thousands) 6,692 8,352 8,421Coal sales per ton sold $53.15 $66.62 $77.70Cash cost per ton sold $51.40 $58.36 $64.43Cash margin per ton sold $1.75 $8.26 $13.27Adjusted EBITDAR (in thousands) $11,851 $70,450 $112,719Other Thermal Tons sold (in thousands) 5,181 9,764 12,201Coal sales per ton sold $36.16 $37.32 $37.98Cash cost per ton sold $30.28 $28.01 $29.20Cash margin per ton sold $5.88 $9.31 $8.78Adjusted 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 ofthese 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 titledmeasures. Powder River Basin — Adjusted EBITDAR for the Predecessor period from January 1 through October 1, 2016 was negatively impacted by demanddestruction driven by historically low natural gas prices that limited the competitiveness of Powder River Basin coal for electric generation versus thecompeting 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 winterseason when the market was stronger. Cost benefited from lower diesel fuel pricing and cost control efforts. Natural gas pricing fell to historically low levelsdue to mild winter weather in late62Table of Contents2015, 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 toincreasing generator stockpiles, further depressing demand. Metallurgical — Adjusted EBITDAR for the Predecessor period from January 1 through October 1, 2016 was negatively impacted by declines inmetallurgical coal prices. Years of global oversupply from anemic economic growth and international overproduction, particularly from Australia, drovepricing down to levels that were unprofitable for most North American producers. Our metallurgical segment sold 5.1 million tons of metallurgical coal and1.6 million tons of associated thermal coal in the Predecessor period from January 1 through October 1, 2016. Longwall operations accounted forapproximately 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 incash 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 increasedproductivity and shifting volume to lower cost operations, particularly the Leer operation. Longwall operations accounted for 59% of our shipment volumein 2015 versus 53% in 2014.Other Thermal— Adjusted EBITDAR for the Predecessor period from January 1 through October 1, 2016 was negatively impacted by demanddestruction driven by historically low natural gas prices discussed in the Powder River Basin segment discussion above, and the lack of economic exportopportunities. 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 tolow natural gas pricing and increased liquidated damages costs on logistics contracts. Reconciliation of NON-GAAP measuresSegment coal sales per ton soldSegment 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 areadjusted 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 inaccordance with generally accepted accounting principles. We believe segment sales per ton sold provides useful information to investors as it better reflectsour 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 measuresare significant in understanding and assessing our financial condition. Therefore, segment coal sales revenues should not be considered in isolation, nor as analternative to coal sales revenues under generally accepted accounting principles. SuccessorPredecessor October 2throughDecember 31,2016January 1through October1, 2016 Year EndedDecember 31,2015 Year EndedDecember 31,2014 (In thousands) Reported segment coal sales revenues $516,448$1,257,219 $2,347,132 $2,547,075Coal 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 insegments 2,18119,368 48,126 146,823Transportation costs 57,171121,674 181,233 247,241Coal sales 575,6881,398,709 2,573,260 2,935,181Other revenues —— — 1,938Revenues in the consolidated statements of operations $575,688$1,398,709 $2,573,260 $2,937,11963Table of ContentsSegment cost per ton soldSegment 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 areadjusted 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 inaccordance with generally accepted accounting principles. We believe segment cost of tons sold better reflects our controllable costs and our operatingresults by including all costs incurred to produce coal. The adjustments made to arrive at these measures are significant in understanding and assessing ourfinancial condition. Therefore, segment cost of tons sold should not be considered in isolation, nor as an alternative to cost of sales under generally acceptedaccounting principles. SuccessorPredecessor October 2throughDecember 31,2016January 1 throughOctober 1, 2016 Year EndedDecember 31, 2015 Year EndedDecember 31, 2014 (In thousands) Reported segment cost of coal sales $399,568$1,102,386 $1,903,762 $2,106,991Diesel fuel risk management derivative settlements classified in “otherincome” 363(3,696) (8,162) (6,789)Transportation costs 57,171121,674 181,233 247,241Cost of sales from idled or otherwise disposed operations not included insegments 5,85342,513 79,290 190,220Fresh start coal inventory fair value adjustment 7,345— — —Other (operating overhead, certain actuarial, etc.) 3441,587 16,630 (4,379)Cost of sales in the consolidated statements of operations $470,644$1,264,464 $2,172,753 $2,533,284Reconciliation 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. AdjustedEBITDAR is defined as net income attributable to the Company before the effect of net interest expense, income taxes, depreciation, depletion andamortization, the amortization of sales contracts, the accretion on asset retirement obligations, and reorganization items, net. Adjusted EBITDAR may also beadjusted for items that may not reflect the trend of future results. We have added accretion on asset retirement obligations as an adjustment to arrive atAdjusted EBITDAR as we believe most industry participants include this adjustment in similar measures. We use Adjusted EBITDAR to measure theoperating performance of our segments and allocate resources to our segments. Adjusted EBITDAR is not a measure of financial performance in accordancewith generally accepted accounting principles, and items excluded from Adjusted EBITDAR are significant in understanding and assessing our financialcondition. Therefore, Adjusted EBITDAR should not be considered in isolation, nor as an alternative to net income, income from operations, cash flows fromoperations or as a measure of our profitability, liquidity or performance under generally accepted accounting principles. Investors should be aware that ourpresentation of Adjusted EBITDAR may not be comparable to similarly titled measures used by other companies. The table below shows how we calculateAdjusted EBITDAR. 64Table of Contents SuccessorPredecessor October 2throughDecember 31,2016January 1 throughOctober 1, 2016Year EndedDecember 31, 2015Year EndedDecember 31,2014(In thousands) Reported segment Adjusted EBITDAR from coal operations $117,743$156,484 $394,223 $409,688EBITDAR from idled or otherwise disposed operations (2,795)(14,514) (23,605) (12,834)Selling, general and administrative expenses (22,836)(59,343) (98,783) (114,223)Other 2,3854,676 11,962 30,421Adjusted EBITDAR 94,49787,303 283,797 313,052Income tax benefit (provision) (1,156)4,626 373,380 (25,634)Interest expense, net (10,754)(133,235) (393,549) (383,188)Depreciation, depletion and amortization(32,604)(191,581)(379,345)(418,748)Accretion on asset retirement obligations(7,634)(24,321)(33,680)(32,909)Amortization of sales contracts, net(796)7288,81113,187Asset impairment and mine closure costs—(129,267)(2,628,303)(24,113)Losses from disposed operations resulting from Patriot Coal bankruptcy——(116,343)—Net loss resulting from early retirement of debt and debt restructuring —(2,213) (27,910) —Reorganization items, net (759)1,630,041 — —Fresh start coal inventory fair value adjustment (7,345)— — —Net income (loss) $33,449$1,242,081 $(2,913,142) $(558,353) Other includes primarily income from our equity investments, certain actuarial adjustments, and certain changes in the fair value of coal derivativesand coal trading activities.For the Successor period from October 2 through December 31, 2016 corporate and other consists primarily of net income from equity investments of$1.7 million.For the Predecessor period from January 1 through October 1, 2016 Other consists primarily of net income from equity investments of $5.3 million.Other decreased $18.5 million in the Predecessor year ended December 31, 2015 when compared to the Predecessor year ended December 31, 2014due to the unfavorable year over year net change in pension settlement and curtailment costs of $11.9 million, further unfavorable year over year net changeof $4.9 million in other various actuarial liabilities, and reduced net income from equity investments of $2.5 million. Liquidity and Capital Resources Our primary sources of liquidity are proceeds from coal sales to customers and certain financing arrangements. Excluding significant investingactivity, we intend to satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated fromoperations and cash on hand. Our focus is growing liquidity and prudently managing costs, including capital expenditures. Any future determinations to return capital to stockholders, such as dividends or share repurchases, will be at the discretion of our Board of Directorsand will depend on a variety of factors, including our net income or other sources of cash, liquidity position and potential alternative uses of cash, such asinternal development projects or acquisitions, as well as economic conditions and expected future financial results. Our ability to declare dividends orrepurchase shares in the future will depend on our future financial performance, which in turn depends on the successful implementation of our strategy andon financial, competitive, regulatory, technical and other factors, general economic conditions, demand for and selling prices of coal and other factorsspecific to our industry, many of which are beyond our control.On the Effective Date, pursuant to the Plan and as a condition to its effectiveness, we entered into a new senior secured term loan credit agreement inan aggregate principal amount of $326.5 million (the “New First Lien Debt Facility”) with65Table of ContentsWilmington Trust, National Association, as administrative agent and collateral agent (in such capacities, the “Agent”) for the lenders party thereto from timeto time (collectively, the “Lenders”). The term loan matures on October 5, 2021. Borrowings under the term loan bear interest at a per annum rate equal to, atour option, either (i) a London interbank offered rate plus an applicable margin of 9%, per annum subject to a 1% LIBOR floor (the “LIBOR Rate”), or (ii) abase rate plus an applicable margin of 8% per annum. Interest payments are payable in cash, unless our Liquidity (as defined therein) after giving effect to theapplicable interest payment would not exceed $300 million, in which case interest shall be payable in kind. To the extent any interest is paid in kind on anyinterest payment date, the amount of the term loans in respect of which such paid-in-kind interest is payable will be deemed to have accrued additionalinterest over the preceding interest period at a rate of 1.00% per annum, which additional interest will be capitalized and added to the principal amount ofoutstanding term loans. Quarterly principal amortization payments in an amount equal to $816,250 are required under the term loan. We have the right toprepay the term loan at any time and from time to time in whole or in part without premium or penalty, upon written notice, except that any prepayment ofterm loans that bear interest at the LIBOR Rate other than at the end of the applicable interest periods therefor shall be made with reimbursement for anyfunding losses and redeployment costs of the Lenders resulting therefrom.On the Effective Date, we extended and amended our existing $200 million trade accounts receivable securitization facility provided to ArchReceivable Company, LLC (“Arch Receivable”), a non-Debtor special-purpose entity that is a wholly owned subsidiary of Arch Coal (the “ExtendedSecuritization Facility”), which continues to support the issuance of letters of credit and reinstates Arch Receivable’s ability to request cash advances, asexisted prior to the filing of the voluntary petitions for relief under the Bankruptcy Code. The Extended Securitization Facility will terminate at the earliestof (i) three years from the Effective Date, (ii) if the Liquidity (as defined in the Extended Securitization Facility and consistent with the definition in the NewFirst Lien Debt Facility) is less than $175 million for a period of 60 consecutive days, the date that is the 364th day after the first day of such 60 consecutiveday period and (iii) the occurrence of certain predefined events substantially consistent with the existing transaction documents. As of December 31, 2016,letters of credit totaling $154.4 million were outstanding under the Extended Securitization Facility and the borrowing base was $83.4 million. As a result,cash collateral of $71.0 million has been placed in the Extended Securitization Facility at December 31, 2016 and there is no availability for borrowings. The following is a summary of cash provided by or used in each of the indicated types of activities: SuccessorPredecessor October 2throughDecember 31,2016January 1throughOctober 1, 2016 Year EndedDecember 31,2015 Year EndedDecember 31,2014 (In thousands) Cash provided by (used in): Operating activities $84,192$(228,218) $(44,367) $(33,582)Investing activities 17,98415,134 (180,341) (111,434)Financing activities 2,709(37,210) (58,742) (31,852) 66Table of ContentsCash Flow - SuccessorCash provided by operating activities in the Successor period October 2 through December 31, 2016 resulted from improved market conditions formost of our products and solid operating cost performance across all of our segments discussed in the Operational Performance section above. In addition,low cash interest expense and favorable working capital adjustments contributed to the cash provided by operating activities.Cash provided by investing activities in the Successor period October 2 through December 31, 2016 resulted from the sale of short term investmentsand withdrawals of restricted cash as collateral requirements under the securitization facility discussed above diminished over the period. These benefits werepartially offset by capital expenditures that have been effectively managed to minimal levels.Cash provided by financing activities in the Successor period October 2 through December 31, 2016 resulted from insurance premium financingproceeds partially offset by the first principal amortization payment on the term loan discussed above.Cash Flow - PredecessorCash used in operating activities in the Predecessor period January 1 through October 1, 2016 resulted from difficult market conditions for all of ourproducts as discussed in the Operational Performance section above. In addition significant cash interest expense and cash restructuring costs impacted cashused in operating activities.Cash used in operating activities in the Predecessor years ended December 31, 2015 and December 31, 2014 resulted from deteriorating marketconditions and high cash interest expenses. Cash provided by investing activities in the Predecessor period January 1 through October 1, 2016 resulted from the net sale of short terminvestments and withdrawals of restricted cash as collateral requirements under the Predecessor securitization facility diminished over the period. Thesebenefits were partially offset by capital expenditures that were effectively managed to minimal levels, but did include the final of five annual $60 millionlease by application bonus bid payments for reserves acquired in the Powder River Basin.Cash used in investing activities in the Predecessor year ended December 31, 2015 increased from the Predecessor year ended December 31, 2014due to increased deposits of restricted cash as collateral requirements under the Predecessor securitization facility increased over the 2015 period, and theabsence of significant proceeds from disposals and divestitures in the year ended December 31, 2015 versus approximately $62 million in proceeds in theyear ended December 31, 2014. These benefits were partially offset by decreased capital spending and net proceeds from the sale of short term investments in2015 versus 2014.Cash used in financing activities in the Predecessor period January 1 through October 1, 2016 resulted from financing costs associated with theprevious DIP facility and securitization facility discussed above, insurance premium financing payments, and expenses related to pre-filing debt restructuringcosts.Cash used in financing activities in the Predecessor year ended December 31, 2015 increased from the Predecessor year ended December 31, 2014due to expenses related to pre-filing debt restructuring costs in 2015.Contractual Obligations Payments Due by Period 2017 2018-2019 2020-2021 after 2021 Total (Dollars in thousands)Long-term debt, including related interest$44,148 $86,465 $389,368 $290 $520,271Operating leases14,653 19,806 4,245 10,317 49,021Coal lease rights3,994 12,126 14,956 46,499 77,575Coal purchase obligations8,406 — — — 8,406Unconditional purchase obligations39,571 — — — 39,571Total contractual obligations$110,772 $118,397 $408,569 $57,106 $694,84467Table of ContentsThe related interest on long-term debt was calculated using rates in effect at December 31, 2016 for the remaining term of outstanding borrowings.Coal lease rights represent non-cancelable royalty lease agreements, as well as lease bonus payments due.Unconditional purchase obligations include open purchase orders and other purchase commitments, which have not been recognized as a liability. Thecommitments in the table above relate to contractual commitments for the purchase of materials and supplies, payments for services and capital expenditures.The table above excludes our asset retirement obligations. Our consolidated balance sheet reflects a liability of $356.7 million for asset retirementobligations that arise from SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and anapproved reclamation plan. Asset retirement obligations are recorded at fair value when incurred and accretion expense is recognized through the expecteddate of settlement. Determining the fair value of asset retirement obligations involves a number of estimates, as discussed in the section entitled “CriticalAccounting Policies” below, including the timing of payments to satisfy the obligations. The timing of payments to satisfy asset retirement obligations isbased on numerous factors, including mine closure dates. Please see the notes to our Consolidated Financial Statements for more information about our assetretirement obligations.The table above also excludes certain other obligations reflected in our consolidated balance sheet, including estimated funding for pension andpostretirement benefit plans and worker’s compensation obligations. The timing of contributions to our pension plans varies based on a number of factors,including changes in the fair value of plan assets and actuarial assumptions. Please see the section entitled “Critical Accounting Policies” below for moreinformation about these assumptions. We expect to make contributions of $0.4 million to our pension plans in 2017, which is impacted by the MovingAhead for Progress in the 21st Century Act (MAP-21) enacted July 6, 2012. MAP-21 does not reduce our obligations under the plan, but redistributes thetiming of required payments by providing near term funding relief for sponsors under the Pension Protection Act.Please see the Notes to our Consolidated Financial Statements for more information about the amounts we have recorded for workers’ compensation andpension and postretirement benefit obligations.Off-Balance Sheet ArrangementsIn the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications,financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. Liabilities related to these arrangements arenot reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cashflows to result from these off-balance sheet arrangements.We use a combination of surety bonds, letters of credit and cash to secure our financial obligations for reclamation, workers’ compensation, coal leaseobligations and other obligations as follows as of December 31, 2016: Workers’ Reclamation Lease Compensation Obligations Obligations Obligations Other Total (Dollars in thousands)Surety bonds528,301 32,584 19,534 2,824 583,243Letters of credit21,321 — 115,568 17,547 154,436Cash on deposit with others33,409 — 11,132 — 44,54168Table of ContentsCritical Accounting PoliciesWe prepare our financial statements in accordance with accounting principles that are generally accepted in the United States. The preparation of thesefinancial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses aswell as the disclosure of contingent assets and liabilities. Management bases our estimates and judgments on historical experience and other factors that arebelieved to be reasonable under the circumstances. Additionally, these estimates and judgments are discussed with our audit committee on a periodic basis.Actual results may differ from the estimates used under different assumptions or conditions. We have provided a description of all significant accountingpolicies in the notes to our Consolidated Financial Statements. We believe that of these significant accounting policies, the following may involve a higherdegree of judgment or complexity:Fresh Start AccountingOn the plan Effective Date, the Company applied fresh start accounting which requires the Company to allocate our reorganization value to the fairvalue of assets and liabilities in conformity with the guidance for the acquisition method of accounting for business combinations.Fresh start accounting provides, among other things, for a determination of the value to be assigned to the equity of the emerging company as of a dateselected for financial reporting purposes. In conjunction with the bankruptcy proceedings, a third party financial advisor provided an enterprise value of theCompany of approximately $650 million to $950 million. The final equity value of $687.5 million was based upon the approximate high end of theenterprise value established by the third party valuation. The high end of the enterprise assumed a minimum cash balance at emergence of $250 million.The enterprise value of the Company was estimated using various valuation methods including: (i) comparable public company analysis, (ii) discountedcash flow analysis (“DCF”) and (iii) sum-of-the-parts analysis.All estimates, assumptions and financial projections, including the fair value adjustments, the financial projections, and the enterprise value andreorganization value projections, are inherently subject to significant uncertainties. Accordingly, there can be no assurance that the estimates, assumptionsand financial projections will be realized, and actual results could vary materially.For the impact of the adoption of fresh start accounting, see Note 3, “Emergence from Bankruptcy and Fresh Start Accounting,” of the Notes to theConsolidated Financial Statements.Derivative Financial InstrumentsWe utilize derivative instruments to manage exposures to commodity prices. Additionally, we may hold certain coal derivative instruments for tradingpurposes. Derivative financial instruments are recognized in the balance sheet at fair value. Certain coal contracts may meet the definition of a derivativeinstrument, but because they provide for the physical purchase or sale of coal in quantities expected to be used or sold by us over a reasonable period in thenormal course of business, they are not recognized on the balance sheet.Certain derivative instruments are designated as the hedge instrument in a hedging relationship. In a cash flow hedge, we hedge the risk of changes infuture cash flows related to a forecasted purchase or sale. Changes in the fair value of the derivative instrument used as a hedge instrument in a cash flowhedge are recorded in other comprehensive income. Amounts in other comprehensive income are reclassified to earnings when the hedged transaction affectsearnings and are classified in a manner consistent with the transaction being hedged.We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertakingvarious hedge transactions. We evaluate the effectiveness of our hedging relationships both at the hedge inception and on an ongoing basis.Impairment of Long-lived AssetsWe review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not berecoverable. These events and circumstances include, but are not limited to, a current expectation that a long-lived asset will be disposed of significantlybefore the end of its previously estimated useful life, a significant adverse change in the extent or manner in which we use a long-lived asset or a change in itsphysical condition.When such events or changes in circumstances occur, a recoverability test is performed comparing projected undiscounted cash flows from the use andeventual disposition of an asset or asset group to its carrying amount. If the projected undiscounted cash flows are less than the carrying amount, animpairment is recorded for the excess of the carrying amount over the estimate fair value, which is generally determined using discounted future cash flows. Ifwe recognize an impairment loss, the adjusted carrying amount of the asset becomes the new cost basis. For a depreciable long-lived asset, the new cost basiswill be depreciated (amortized) over the remaining estimated useful life of the asset.69Table of ContentsWe make various assumptions, including assumptions regarding future cash flows in our assessments of long-lived assets for impairment. Theassumptions about future cash flows and growth rates are based on the current and long-term business plans related to the long-lived assets. Discount rateassumptions are based on an assessment of the risk inherent in the future cash flows of the long-lived assets. These assumptions require significant judgmentson our part, and the conclusions that we reach could vary significantly based upon these judgments.For additional information on impairment charges related to this filing, see Note 5, “Impairment Charges and Mine Closure Costs” to the ConsolidatedFinancial Statements.Asset Retirement ObligationsOur asset retirement obligations arise from SMCRA and similar state statutes, which require that mine property be restored in accordance with specifiedstandards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and supportacreage at surface mines, and sealing portals at deep mines. Our asset retirement obligations are initially recorded at fair value, or the amount at which theobligations could be settled in a current transaction between willing parties. This involves determining the present value of estimated future cash flows on amine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, reclamationcosts and assumptions regarding equipment productivity. We estimate disturbed acreage based on approved mining plans and related engineering data. Sincewe plan to use internal resources to perform the majority of our reclamation activities, our estimate of reclamation costs involves estimating third-party profitmargins, which we base on our historical experience with contractors that perform certain types of reclamation activities. We base productivity assumptionson historical experience with the equipment that we expect to utilize in the reclamation activities. In order to determine fair value, we discount our estimatesof cash flows to their present value. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for ourcredit standing.Accretion expense is recognized on the obligation through the expected settlement date. On at least an annual basis, we review our entire reclamationliability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing and extent of reclamation activities, andrevisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the recorded amount of the liability and theactual cost of reclamation will be recognized as a gain or loss when the obligation is settled. We expect our actual cost to reclaim our properties will be lessthan the expected cash flows used to determine the asset retirement obligation. At December 31, 2016, our balance sheet reflected asset retirement obligationliabilities of $356.7 million, including amounts classified as a current liability. As of December 31, 2016, we estimate the aggregate undiscounted cost offinal mine closures to be approximately $926 million.See the rollforward of the asset retirement obligation liability in Note 15 to the Consolidated Financial Statements, “Asset Retirement Obligations”.Employee Benefit PlansWe have non-contributory defined benefit pension plans covering certain of our salaried and hourly employees. Benefits are generally based on theemployee’s years of service and compensation. The actuarially-determined funded status of the defined benefit plans is reflected in the balance sheet.The calculation of our net periodic benefit costs (pension expense) and benefit obligation (pension liability) associated with our defined benefit pensionplans requires the use of a number of assumptions. These assumptions are summarized in Note 20, “Employee Benefit Plans”, to the Consolidated FinancialStatements. Changes in these assumptions can result in different pension expense and liability amounts, and actual experience can differ from theassumptions.•The expected long-term rate of return on plan assets is an assumption reflecting the average rate of earnings expected on the funds invested or to beinvested to provide for the benefits included in the projected benefit obligation. We establish the expected long-term rate of return at the beginningof each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The pension plan’s investmenttargets are 55% equity and 45% fixed income securities. Investments are rebalanced on a periodic basis to approximate these targeted guidelines.The long-term rate of return assumptions are less than the plan’s actual life-to-date returns. Any difference between the actual experience and theassumed experience is recorded in other comprehensive income and amortized into earnings in the future. The impact of lowering the expected long-term rate of return on plan assets 0.5% for 2016 would have been an increase in expense of approximately $1.4 million.•The discount rate represents our estimate of the interest rate at which pension benefits could be effectively settled. Assumed discount rates are usedin the measurement of the projected, accumulated and vested benefit obligations and the service and interest cost components of the net periodicpension cost. The determination of the discount rate was updated from our actuary’s proprietary Yield Curve model, under which the expectedbenefit payments of the plan are matched against a series of spot rates from a market basket of high quality fixed income securities. The impact oflowering the discount rate 0.5% for 2016 would have been an increase in expense of approximately $1.2 million.70Table of ContentsThe differences generated from changes in assumed discount rates and returns on plan assets are amortized into earnings using the corridor method,whereby the unrecognized (gains)/losses in excess of 10% of the greater of the beginning of the year projected benefit obligation or market-related value ofassets are amortized over the average remaining life expectancy of the plan participants.We also currently provide certain postretirement medical and life insurance coverage for eligible employees. Generally, covered employees whoterminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The salariedemployee postretirement benefit plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such asdeductibles and coinsurance.Actuarial assumptions are required to determine the amounts reported as obligations and costs related to the postretirement benefit plan. The discountrate assumption reflects the rates available on high-quality fixed-income debt instruments at year-end and is calculated in the same manner as discussedabove for the pension plan. A change of 0.5% in these assumptions would not have had a significant impact on the benefit costs in 2016 .Income TaxesWe provide for deferred income taxes for temporary differences arising from differences between the financial statement and tax basis of assets andliabilities existing at each balance sheet date using enacted tax rates expected to be in effect when the related taxes are expected to be paid or recovered. Weinitially recognize the effects of a tax position when it is more than 50 percent likely, based on the technical merits, that the position will be sustained uponexamination, including resolution of the related appeals or litigation processes, if any. Our determination of whether or not a tax position has met therecognition threshold considers the facts, circumstances, and information available at the reporting date.We reassess our ability to realize our deferred tax assets annually in the fourth quarter, during our annual budget process, or when circumstances indicatethat the ability to realize deferred tax assets has changed. The assessment takes into account expectations of future taxable income or loss, available taxplanning strategies and the reversal of temporary differences. The development of these expectations involves the use of estimates such as production levels,operating profitability, timing of development activities and the cost and timing of reclamation work. A valuation allowance may be recorded to reflect theamount of future tax benefits that management believes are not likely to be realized. If actual outcomes differ from our expectations, we may recordadditional valuation allowance through income tax expense in the period such determination is made.As our recent cumulative losses constitute significant negative evidence with regards to future taxable income, we have relied solely on the expectedreversal of taxable temporary differences to support the future realization of our deferred tax assets. We perform a detailed scheduling process of our nettaxable temporary differences.At December 31, 2014, all deductible temporary differences were expected to be realized as there were sufficient deferred tax liabilities within the samejurisdiction and of the same character that are available to offset them. Valuation allowances were established for federal and state net operating losses andtax credits that were not offset by the reversal of other net taxable temporary differences before the expiration of the attribute.At December 31, 2015, additional losses were realized relating primarily to financial conditions and asset impairment charges. As a result, the expectedreversal of taxable temporary differences were not sufficient to support the future realization of the deferred tax assets and an additional $865.1 millionvaluation allowance was recorded. Net deferred tax assets of $1,135 million were completely offset by a valuation allowance.At December 31, 2016, additional tax losses were realized primarily as a result of the non-recognition of CODI under section 108 of the IRC by thePredecessor entity. As a result, the expected reversal of taxable temporary differences were not sufficient to support the future realization of the deferred taxassets and an additional $1,185 million valuation allowance was recorded to the provision. Offsetting this increase was a net reduction in the valuationallowance of $1,289 million which did not impact the provision. This reduction was primarily the result of a decrease in NOLs and AMT credits due to theIRC section 108 offset rules. Net deferred tax assets of $1,022 million are completely offset by a valuation allowance.71Table of ContentsITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. We manage our commodity price risk for our non-trading, thermal coal sales through the use of long-term coal supply agreements, and to a limitedextent, through the use of derivative instruments. Sales commitments in the metallurgical coal market are typically not long-term in nature, and we aretherefore subject to fluctuations in market pricing. Our commitments for 2017 are as follows: 2017 Tons $ per tonMetallurgical (in millions) Committed, Priced Coking 3.3 $89.70Committed, Unpriced Coking 1.7 Committed, Priced PCI 0.7 $64.82Committed, Unpriced PCI — Committed, Priced Thermal 1.0 $34.52Committed, Unpriced Thermal — Powder River Basin Committed, Priced 66.1 $12.51Committed, Unpriced 3.3 Other Thermal Committed, Priced 6.6 $35.76Committed, Unpriced — We are also exposed to commodity price risk in our coal trading activities, which represents the potential future loss that could be caused by anadverse change in the market value of coal. Our coal trading portfolio included forward, swap and put and call option contracts at December 31, 2016. Theestimated future realization of the value of the trading portfolio is $0.2 million of gains in 2017. We monitor and manage market price risk for our trading activities with a variety of tools, including Value at Risk (VaR), position limits,management alerts for mark to market monitoring and loss limits, scenario analysis, sensitivity analysis and review of daily changes in market dynamics.Management believes that presenting high, low, end of year and average VaR is the best available method to give investors insight into the level ofcommodity risk of our trading positions. Illiquid positions, such as long-dated trades that are not quoted by brokers or exchanges, are not included in VaR. VaR is a statistical one-tail confidence interval and down side risk estimate that relies on recent history to estimate how the value of the portfolio ofpositions will change if markets behave in the same way as they have in the recent past. While presenting VaR will provide a similar framework for discussingrisk across companies, VaR estimates from two independent sources are rarely calculated in the same way. Without a thorough understanding of how eachVaR model was calculated, it would be difficult to compare two different VaR calculations from different sources. The level of confidence is 95%. The timeacross which these possible value changes are being estimated is through the end of the next business day. A closed-form delta-neutral method usedthroughout the finance and energy sectors is employed to calculate this VaR. VaR is back tested to verify usefulness. On average, portfolio value should not fall more than VaR on 95 out of 100 business days. Conversely, portfolio value declines of more than VaRshould be expected, on average, 5 out of 100 business days. When more value than VaR is lost due to market price changes, VaR is not representative of howmuch value beyond VaR will be lost.During the year ended December 31, 2016, VaR for our coal trading positions that are recorded at fair value through earnings ranged from under $0.1million to $0.3 million. The linear mean of each daily VaR was $0.1 million. The final VaR at December 31, 2016 was $0.1 million.72Table of Contents We are exposed to fluctuations in the fair value of coal derivatives that we enter into to manage the price risk related to future coal sales, but forwhich we do not elect hedge accounting. Any gains or losses on these derivative instruments would be offset in the pricing of the physical coal sale. Duringthe year ended December 31, 2016 VaR for our risk management positions that are recorded at fair value through earnings ranged from $0.1 million to $0.2million. The linear mean of each daily VaR was $0.1 million. The final VaR at December 31, 2016 was $0.1 million. We are also exposed to the risk of fluctuations in cash flows related to our purchase of diesel fuel. We expect to use approximately 45 to 50 milliongallons of diesel fuel for use in our operations during 2017. We may enter into forward physical purchase contracts, as well as purchased heating oil options,to reduce volatility in the price of diesel fuel for our operations. At December 31, 2016, we had purchased heating oil call options for approximately 31million gallons for the purpose of protecting against substantial increases in price relating to 2017 diesel purchases. These positions reduce our risk of cashflow fluctuations related to these surcharges but the positions are not accounted for as hedges. A $0.25 per gallon decrease in the price of heating oil wouldnot result in an increase in our expense related to the heating oil derivatives. We also at times have purchased heating oil call options to manage the pricerisk associated with fuel surcharges on barge and rail shipments, which cover increases in diesel fuel prices. At December 31, 2016, we had no positionsoutstanding for this purpose. We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At December 31, 2016, of our $362.9 millionprincipal amount of debt outstanding, approximately $325.7 million of outstanding borrowings have interest rates that fluctuate based on changes in themarket rates. An increase in the interest rates related to these borrowings of 25 basis points would not result in an annualized increase in interest expensebased on interest rates in effect at December 31, 2016, because our term loan has a minimum interest rate that exceeds the current market rates.ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.The Consolidated Financial Statements and consolidated financial statement schedule of Arch Coal, Inc. and subsidiaries are included in thisAnnual Report on Form 10-K beginning on page F-1.ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.None.ITEM 9A. CONTROLS AND PROCEDURES. We performed an evaluation under the supervision and with the participation of our management, including our chief executive officer and chieffinancial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2016. Based on thatevaluation, our management, including our chief executive officer and chief financial officer, concluded that the disclosure controls and procedures wereeffective as of such date. There were no changes in our internal control over financial reporting during the fiscal quarter to which this report relates that havematerially affected, or are reasonably likely to materially affect, our internal control over financial reporting.We incorporate by reference management’s report on internal control over financial reporting included within the Financial Statement section of thisAnnual Report on Form 10-K.ITEM 9B. OTHER INFORMATION.None.73Table of ContentsPART IIIITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.Except for the disclosures contained in Part I of this report under the caption “Executive Officers of the Registrant”, the information required underthis item is incorporated herein by reference to “Director Qualifications, Diversity and Biographies,” “Section 16(a) Beneficial Ownership ReportingCompliance,” “Corporate Governance Guidelines and Code of Business Conduct,” “Nomination Process for Election of Directors” and “Board Meetings andCommittees” in our Proxy Statement for the 2017 Annual Meeting of Stockholders, which is expected to be filed with the SEC within 120 days after the closeof our fiscal year.ITEM 11.EXECUTIVE COMPENSATION.The information required under this item is incorporated herein by reference to “Executive Compensation,” “Director Compensation,”“Compensation Committee Interlocks and Inside Participation” and “Personnel and Compensation Committee Report” in our Proxy Statement for the 2017Annual Meeting of Stockholders, which is expected to be filed with the SEC within 120 days after the close of our fiscal year.ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.The information required under this item is incorporated herein by reference to “Equity Compensation Plan Information,” “Security Ownership ofDirectors and Executive Officers” and “Security Ownership of Certain Beneficial Owners” in our Proxy Statement for the 2017 Annual Meeting ofStockholders, which is expected to be filed with the SEC within 120 days after the close of our fiscal year.ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.The information required under this item is incorporated herein by reference to “Director Independence” in our Proxy Statement for the 2017 AnnualMeeting of Stockholders, which is expected to be filed with the SEC within 120 days after the close of our fiscal year.ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.The information required under this item is incorporated herein by reference to “Fees Paid to Auditors” in our Proxy Statement for the 2017 AnnualMeeting of Stockholders, which is expected to be filed with the SEC within 120 days after the close of our fiscal year.74Table of ContentsPART IVITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.Financial StatementsReference is made to the index set forth on page F-1 of this report.Financial Statement SchedulesThe following financial statement schedule of Arch Coal, Inc. is at the page indicated: Schedule PageValuation and Qualifying AccountsF- 61All other financial statement schedules listed under SEC rules but not included in this report are omitted because they are not applicable or therequired information is provided in the notes to our consolidated financial statements.ExhibitsReference is made to the Exhibit Index beginning on page 79 of this report.ITEM 16.FORM 10-K SUMMARY.None.75Table of ContentsSignaturesPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed onits behalf by the undersigned, thereunto duly authorized. Arch Coal, Inc. /s/ John W. Eaves John W. EavesChief Executive Officer, Director February 24, 201776Table of Contents Signatures Capacity Date /s/ John W. Eaves John W. EavesChief Executive Officer, Director (Principal ExecutiveOfficer)February 24, 2017 /s/ John T. Drexler John T. DrexlerSenior Vice President and Chief Financial Officer(Principal Financial Officer)February 24, 2017 /s/ John W. Lorson John W. LorsonVice President and Chief Accounting Officer (PrincipalAccounting Officer)February 24, 2017 * James N. ChapmanChairmanFebruary 24, 2017 * Patrick J. Bartels, Jr.DirectorFebruary 24, 2017 * Sherman K. Edmiston IIIDirectorFebruary 24, 2017 * Patrick A. KriegshauserDirectorFebruary 24, 2017 * Richard A. NavarreDirectorFebruary 24, 2017 * Scott D. VogelDirectorFebruary 24, 2017 77Table of Contents*By/s/ Robert G. Jones Robert G. Jones,Attorney-in-Fact 78Table of ContentsExhibits to be included in 10-K DescriptionExhibit 2.1Debtors’ Fourth Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (incorporated by reference to Exhibit2.1 of Arch Coal’s Current Report on Form 8-K on September 15, 2016).Exhibit 2.2Order Confirming Debtors’ Fourth Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code on September 13,2016 (incorporated by reference to Exhibit 2.2 of Arch Coal’s Current Report on Form 8-K filed on September 15, 2016).Exhibit 3.1Amended and Restated Certificate of Incorporation of Arch Coal, Inc. (incorporated by reference to Exhibit 3.1 of Arch Coal’sregistration statement on Form 8-K filed on October 4, 2016).Exhibit 3.2Bylaws of Arch Coal, Inc. (incorporated by reference to Exhibit 3.2 of Arch Coal’s registration statement on Form 8-K filed on October4, 2016).Exhibit 4.1Indenture, dated as of August 9, 2010, by and between Arch Coal, Inc. and U.S. Bank National Association, as trustee (incorporatedherein by reference to Exhibit 4.1 to Arch Coal’s Current Report on Form 8-K filed on August 9, 2010)Exhibit 4.2First Supplemental Indenture, dated as of August 9, 2010, by and among Arch Coal, Inc., the subsidiary guarantors named therein, andU.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to Arch Coal’s Current Report on Form 8-Kfiled on August 9, 2010)Exhibit 4.3Second Supplemental Indenture, dated as of December 16, 2010, by and among Arch Coal West, LLC, Arch Coal, Inc., the subsidiaryguarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.7 to Arch Coal’sAnnual Report on Form 10-K for the period ended December 31, 2010).Exhibit 4.4Third Supplemental Indenture, dated as of June 24, 2011, by and among Arch Coal, Inc., the subsidiary guarantors named therein andU.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.13 to Arch Coal’s Annual Report on Form 10-K for the year ended December 31, 2011).Exhibit 4.5Fourth Supplemental Indenture, dated as of October 7, 2011, by and among Arch Coal, Inc., the subsidiary guarantors named thereinand U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.14 to Arch Coal's Annual Report onForm 10-K for the year ended December 31, 2011).Exhibit 4.6Fifth Supplemental Indenture, dated as of July 2, 2012, by and among Arch Coal, Inc., the subsidiary guarantors named therein and U.S.Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to Arch Coal's Quarterly Report on Form 10-Q forthe period ended June 30, 2012).Exhibit 4.7Sixth Supplemental Indenture, dated as of July 31, 2012, by and among Arch Coal, Inc., the subsidiary guarantors named therein andU.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.5 to Arch Coal's Quarterly Report on Form 10-Q for the period ended June 30, 2012).Exhibit 4.8Seventh Supplemental Indenture, dated as of July 26, 2013, by and among Arch Coal, Inc., the subsidiary guarantors named therein andU.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to Arch Coal's Quarterly Report on Form 10-Q for the period ended June 30, 2013).Exhibit 4.9Eighth Supplemental Indenture, dated December 2, 2013, by and among Arch Coal, Inc. the subsidiary guarantors named therein andU.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.21 to Arch Coal's Annual Report on Form 10-K for the period ended December 31, 2013).Exhibit 4.10Indenture, dated as of June 14, 2011, by and among Arch Coal, Inc., the subsidiary guarantors named therein and UMB Bank NationalAssociation, as trustee (incorporated herein by reference to Exhibit 4.1 to Arch Coal's Current Report on Form 8-K filed on June 14,2011).Exhibit 4.11First Supplemental Indenture, dated as of July 5, 2011, by and among Arch Coal, Inc., the subsidiary guarantors named therein andUMB Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.16 to Arch Coal's Annual Report on Form 10-K for the year ended December 31, 2011).Exhibit 4.12Second Supplemental Indenture, dated as of October 7, 2011, by and among Arch Coal, Inc., the subsidiary guarantors named thereinand UMB Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.17 to Arch Coal's Annual Report onForm 10-K for the year ended December 31, 2011).Exhibit 4.13Third Supplemental Indenture, dated as of July 2, 2012, by and among Arch Coal, Inc., the subsidiary guarantors named therein andUMB Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to Arch Coal's Quarterly Report onForm 10-Q for the period ended June 30, 2012).Exhibit 4.14Fourth Supplemental Indenture, dated as of July 31, 2012, by and among Arch Coal, Inc., the subsidiary guarantors named therein andUMB Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.6 to Arch Coal's Quarterly Report onForm 10-Q for the period ended June 30, 2012).79Table of ContentsExhibit 4.15Fifth Supplemental Indenture, dated as of July 26, 2013, by and among Arch Coal, Inc., the subsidiary guarantors named therein andUMB Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to Arch Coal's Quarterly Report on Form10-Q for the period ended June 30, 2013).Exhibit 4.16Sixth Supplemental Indenture, dated as of December 2, 2013, by and among Arch Coal, Inc., the subsidiary guarantors named thereinand UMB Bank National Association (incorporated herein by reference to Exhibit 4.28 to Arch Coal’s Annual Report on Form 10-K forthe year ended December 31, 2013).Exhibit 4.17Indenture, dated as of November 21, 2012, among Arch Coal, Inc., the subsidiary guarantors named therein and UMB Bank NationalAssociation, as trustee (incorporated herein by reference to Exhibit 4.1 to Arch Coal's Current Report on Form 8-K filed onNovember 26, 2012).Exhibit 4.18First Supplemental Indenture, dated as of July 26, 2013, by and among Arch Coal, Inc., the subsidiary guarantors named therein andUMB Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.4 to Arch Coal's Quarterly Report on Form10-Q for the period ended June 30, 2013).Exhibit 4.19Second Supplemental Indenture, dated as of December 2, 2013, by and among Arch Coal, Inc., the subsidiary guarantors named thereinand UMB Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.31 to Arch Coal's Annual Report onForm 10-K for the year ended December 31, 2013).Exhibit 4.20Indenture, dated as of December 17, 2013, by and among Arch Coal, Inc., the subsidiary guarantors named therein and UMB BankNational Association, as trustee and collateral agent (incorporated herein by reference to Exhibit 4.1 to Arch Coal's Current Report onForm 8-K filed on December 17, 2013).Exhibit 4.21Form of specimen Class A Common Stock Certificate (incorporated by reference to Exhibit 4.1of Arch Coal’s Current Report on Form8-K filed on October 11, 2016).Exhibit 4.22Form of specimen Class B Common Stock Certificate (incorporated by reference to Exhibit 4.1of Arch Coal’s Current Report on Form8-K filed on October 11, 2016).Exhibit 4.23Form of specimen Series A Warrant Certificate (incorporated by reference to Exhibit 4.1of Arch Coal’s Current Report on Form 8-K filedon October 11, 2016).Exhibit 10.1Amended and Restated Credit Agreement, dated as of June 14, 2011, by and among the Company, the lenders party thereto, PNC Bank,National Association, as administrative agent and Bank of America, N.A., The Royal Bank of Scotland PLC and Citibank, N.A., as co-documentation agents (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Arch Coal onJune 17, 2011).Exhibit 10.2Incremental Amendment, dated as of November 21, 2012, by and among Arch Coal, Inc., as Borrower, the guarantors party thereto, theincremental term loan lenders party thereto, Bank of America, N.A., as Term Loan Administrative Agent, and Merrill Lynch, Pierce,Fenner & Smith Incorporated, PNC Capital Markets LLC, Morgan Stanley Senior Funding, Inc., Citigroup Global Markets Inc., CreditSuisse Securities (USA) LLC, BBVA Securities Inc., RBS Securities Inc. and Union Bank, N.A., as Lead Arrangers, as Lead Arrangers(incorporated herein by reference to Exhibit 10.1 to Arch Coal's Current Report on Form 8-K filed on November 26, 2012).Exhibit 10.3First Amendment to Amended and Restated Credit Agreement, dated as of May 16, 2012, by and among Arch Coal, Inc., as Borrower,the guarantors party thereto, the lenders party thereto, and PNC Bank, National Association, as Revolver Administrative Agent(incorporated herein by reference to Exhibit 10.1 to Arch Coal's Current Report on Form 8-K filed on May 17, 2012).Exhibit 10.4Second Amendment to Amended and Restated Credit Agreement, dated as of November 21, 2012, by and among Arch Coal, Inc., asBorrower, the guarantors party thereto, the lenders party thereto, Bank of America, N.A., as Term Loan Administrative Agent, and PNCBank, National Association, as Revolver Administrative Agent (incorporated herein by reference to Exhibit 10.2 to Arch Coal's CurrentReport on Form 8-K filed on November 26, 2012).Exhibit 10.5Third Amendment to Amended and Restated Credit Agreement, dated as of November 21, 2012, by and among Arch Coal, Inc., asBorrower, the guarantors party thereto, the revolver lenders party thereto and PNC Bank, National Association, as RevolverAdministrative Agent (incorporated herein by reference to Exhibit 10.3 to Arch Coal's Current Report on Form 8-K filed onNovember 26, 2012).Exhibit 10.6Amendment Number Four to Amended and Restated Credit Agreement, dated as of December 17, 2013, by and among Arch Coal, Inc.,as Borrower, the guarantors party thereto, the lenders party thereto, Bank of America, N.A., as term loan administrative agent, and PNCBank, National Association, as Revolver Administrative Agent (incorporated herein by reference to Exhibit 10.1 to Arch Coal's CurrentReport on Form 8-K filed on December 17, 2013).Exhibit 10.7Credit Agreement, dated as of October 5, 2016, among Arch Coal, Inc., as borrower, the lenders from time to time party thereto andWilmington Trust, National Association, in its capacities as administrative agent and as collateral agent (incorporated by reference toExhibit 10.1 of Arch Coal’s Current Report on Form 8-K filed on October 11, 2016).Exhibit 10.8Amended and Restated Receivables Purchase Agreement, dated as of February 24, 2010, among Arch Receivable Company, LLC, ArchCoal Sales Company, Inc., Market Street Funding LLC, as issuer, the financial institutions form time to time party thereto, as LCParticipants, and PNC Bank, National Association, as Administrator on behalf of the Purchasers and as LC Bank (incorporated herein byreference to Exhibit 10.2 to Arch Coal’s Quarterly Report on Form 10-Q for the period ended March 31, 2010).80Table of ContentsExhibit 10.9First Amendment to Amended and Restated Receivables Purchase Agreement, dated January 31, 2011, among Arch ReceivableCompany, LLC, Arch Coal Sales Company, Inc. and the other parties thereto (incorporated by reference to Exhibit 10.41 to Arch Coal’sAnnual Report on Form 10-K for the period ended December 31, 2010).Exhibit 10.10Second Amendment to Amended and Restated Receivables Purchase Agreement dated June 15, 2011 (incorporated by reference toExhibit 10.5 to Arch Coal’s Quarterly Report on Form 10-Q for the period ended June 30, 2011).Exhibit 10.11Third Amendment to Amended and Restated Receivables Purchase Agreement dated November 21, 2011, among Arch ReceivableCompany, LLC, Arch Coal Sales Company, Inc. and the other parties thereto (incorporated herein by reference to Exhibit 10.38 to ArchCoal’s Annual Report on Form 10-K for the year ended December 31, 2011).Exhibit 10.12Fourth Amendment to Amended and Restated Receivables Purchase Agreement dated December 13, 2011, among Arch ReceivableCompany, LLC, Arch Coal Sales Company, Inc. and the other parties thereto (incorporated herein by reference to Exhibit 10.39 to ArchCoal’s Annual Report on Form 10-K for the year ended December 31, 2011).Exhibit 10.13Fifth Amendment to Amended and Restated Receivables Purchase Agreement dated December 11, 2012, among Arch ReceivableCompany, LLC, Arch Coal Sales Company, Inc. and the other parties thereto (incorporated herein by reference to Exhibit 10.45 to ArchCoal’s Annual Report on Form 10-K for the period ended December 31, 2012).Exhibit 10.14Sixth Amendment to Amended and Restated Receivables Purchase Agreement dated October 4, 2013, among Arch ReceivableCompany, LLC, Arch Coal Sales Company, Inc., and the other parties thereto (incorporated herein by reference to Exhibit 10.51 to ArchCoal’s Annual Report on Form 10-K for the year ended December 31, 2013).Exhibit 10.15Seventh Amendment to Amended and Restated Receiveables Purchase Agreement dated December 10, 2013, among Arch ReceivableCompany, LLC, Arch Coal Sales Company, Inc., and the other parties thereto (incorporated herein by reference to Exhibit 10.52 to ArchCoal’s Annual Report on Form 10-K for the year ended December 31, 2013).Exhibit 10.16Eighth Amendment to Amended and Restated Receivables Purchase Agreement dated October 28, 2014, among Arch ReceivablesCompany, LLC, Arch Coal Sales Company, Inc., and the other parties thereto (incorporated by reference to Exhibit 10.54 to Arch Coal’sAnnual Report on Form 10-K for the year ended December 31, 2014).Exhibit 10.17Ninth Amendment to Amended and Restated Receivables Purchase Agreement, dated December 29, 2014, among Arch ReceivablesCompany, LLC, Arch Coal Sales Company, Inc., and the other parties thereto (incorporated herein by reference to Exhibit 10.55 to ArchCoal’s Annual Report on Form 10-K for the year ended December 31, 2014).Exhibit 10.18Second Amended and Restated Purchase and Sale Agreement among Arch Coal, Inc. and certain subsidiaries of Arch Coal, Inc., asoriginators (incorporated by reference to Exhibit 10.3 of Arch Coal’s Current Report on Form 8-K filed on October 11, 2016).Exhibit 10.19Third Amended and Restated Receivables Purchase Agreement among Arch Receivable Company, LLC, as seller, Arch Coal SalesCompany, Inc., as initial servicer, PNC Bank, National Association as administrator and issuer of letters of credit thereunder and theother parties party thereto, as securitization purchasers (incorporated by reference to Exhibit 10.2 of Arch Coal’s Current Report onForm 8-K filed on October 11, 2016).Exhibit 10.20Second Amended and Restated Sale and Contribution Agreement between Arch Coal, Inc., as the transferor, and Arch ReceivableCompany, LLC (incorporated by reference to Exhibit 10.4 of Arch Coal’s Current Report on Form 8-K filed on October 11, 2016).Exhibit 10.21Warrant Agreement, dated as of October 5, 2016, between Arch Coal, Inc. and American Stock Transfer & Trust Company, LLC, asWarrant Agent (incorporated by reference to Exhibit 10.5 of Arch Coal’s Current Report on Form 8-K filed on October 11, 2016).Exhibit 10.22Indemnification Agreement between Arch Coal and the directors and officers of Arch Coal and its subsidiaries (form) (incorporated byreference to Exhibit 10.6 of Arch Coal’s Current Report on Form 8-K filed on October 11, 2016).Exhibit 10.23Registration Rights Agreement between Arch Coal and Monarch Alternative Capital LP and certain other affiliated funds (incorporatedby reference to Exhibit 10.1 of Arch Coal’s Current Report on Form 8-K filed on November 21, 2016)Exhibit 10.24Coal Lease Agreement dated as of March 31, 1992, among Allegheny Land Company, as lessee, and UAC and Phoenix CoalCorporation, as lessors, and related guarantee (incorporated herein by reference to the Current Report on Form 8-K filed by AshlandCoal, Inc. on April 6, 1992).Exhibit 10.25Federal Coal Lease dated as of January 24, 1996 between the U.S. Department of the Interior and the Thunder Basin Coal Company(incorporated herein by reference to Exhibit 10.20 to the registrant’s Annual Report on Form 10-K for the year ended December 31,1998).81Table of ContentsExhibit 10.26Federal Coal Lease Readjustment dated as of November 1, 1967 between the U.S. Department of the Interior and the Thunder BasinCoal Company (incorporated herein by reference to Exhibit 10.21 to the registrant’s Annual Report on Form 10-K for the year endedDecember 31, 1998).Exhibit 10.27Federal Coal Lease effective as of May 1, 1995 between the U.S. Department of the Interior and Mountain Coal Company (incorporatedherein by reference to Exhibit 10.22 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 1998).Exhibit 10.28Federal Coal Lease dated as of January 1, 1999 between the Department of the Interior and Ark Land Company (incorporated herein byreference to Exhibit 10.23 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 1998).Exhibit 10.29Federal Coal Lease effective as of March 1, 2005 by and between the United States of America and Ark Land LT, Inc. covering the tractof land known as “Little Thunder” in Campbell County, Wyoming (incorporated by reference to Exhibit 99.1 to the Current Report onForm 8-K filed by the registrant on February 10, 2005).Exhibit 10.30Modified Coal Lease (WYW71692) executed January 1, 2003 by and between the United States of America, through the Bureau ofLand Management, as lessor, and Triton Coal Company, LLC, as lessee, covering a tract of land known as “North Rochelle” inCampbell County, Wyoming (incorporated by reference to Exhibit 10.24 to the registrant’s Annual Report on Form 10-K for the yearended December 31, 2004).Exhibit 10.31Coal Lease (WYW127221) executed January 1, 1998 by and between the United States of America, through the Bureau of LandManagement, as lessor, and Triton Coal Company, LLC, as lessee, covering a tract of land known as “North Roundup” in CampbellCounty, Wyoming (incorporated by reference to Exhibit 10.24 to the registrant’s Annual Report on Form 10-K for the year endedDecember 31, 2004).Exhibit 10.32Form of Employment Agreement for Executive Officers of Arch Coal, Inc. (incorporated herein by reference to Exhibit 10.4 to ArchCoal’s Annual Report on Form 10-K for the year ended December 31, 2011).Exhibit 10.33Arch Coal, Inc. Incentive Compensation Plan For Executive Officers (incorporated herein by reference to Appendix B to the proxystatement on Schedule 14A filed by the registrant on March 22, 2010).Exhibit 10.34Arch Coal, Inc. Deferred Compensation Plan (incorporated herein by reference to Exhibit 10.26 to Arch Coal’s Annual Report on Form10-K for the year ended December 31, 2014).Exhibit 10.35Arch Coal, Inc. Outside Directors' Deferred Compensation Plan (incorporated herein by reference to Exhibit 10.4 of Arch Coal’s CurrentReport on Form 8-K filed on December 11, 2008).Exhibit 10.36Arch Coal, Inc. Supplemental Retirement Plan (as amended on December 5, 2008) (incorporated herein by reference to Exhibit 10.2 toArch Coal’s Current Report on Form 8-K filed on December 11, 2008).Exhibit 10.37Arch Coal, Inc. 2016 Omnibus Incentive Plan (incorporated herein by reference to Exhibit 99.1 to Arch Coal’s Registration Statementon Form S-8 filed on November 1, 2016).Exhibit 10.38Form of Restricted Stock Unit Contract (Time-Based Vesting) (incorporated herein by reference to Exhibit 10.1 to Arch Coal’s CurrentReport on Form 8-K filed on November 30, 2016).Exhibit 10.39Form of Restricted Stock Unit Contract (Performance-Based Vesting) (incorporated herein by reference to Exhibit 10.2 to Arch Coal’sCurrent Report on Form 8-k filed on November 30, 2016).Exhibit 10.40Form of Performance Unit Contract (incorporated herein by reference to Exhibit 10.2 to Arch Coal’s Quarterly Report on Form 10-Q forthe period ended March 31, 2013).Exhibit 10.41Form of 2011 Performance Unit Contract (incorporated herein by reference to Exhibit 10.4 to Arch Coal’s Quarterly Report on Form 10-Q for the period ended March 31, 2012).Exhibit 10.42Form of Director Indemnity Agreement (incorporated herein by reference to Exhibit 10.40 to Arch Coal’s Annual Report on Form 10-Kfor the period ended December 31, 2010).Exhibit 10.43Superpriority Senior Secured Debtor in Possession Credit Agreement, dated as of January 21, 2016, by and among Arch Coal, Inc.,subsidiaries of Arch Coal, Inc. from time to time party thereto as guarantors, the lenders from time to time party thereto and the Agent(as defined therein) (incorporated herein by reference to Exhibit 10.53 to Arch Coal’s Annual Report on Form 10-K for the year endedDecember 31, 2015).Exhibit 10.44Amendment No. 2, dated as of March 25, 2016, to the Superpriority Secured Debtor-in-Possession Credit Agreement dated January 21,2016 (incorporated herein by reference to Exhibit 10.1 to Arch Coal’s Quarterly Report on Form 10-Q filed on May 10, 2016).Exhibit 10.45Amendment No. 3, dated as of April 26, 2016, to the Superpriority Secured Debtor-in-Possession Credit Agreement dated January 21,2016 (incorporated herein by reference to Exhibit 10.1 to Arch Coal’s Quarterly Report on Form 10-Q filed on August 9, 2016).Exhibit 10.46Amendment No. 4, dated as of June 10, 2016, to the Superpriority Secured Debtor-in-Possession Credit Agreement dated January 21,2016 (incorporated herein by reference to Exhibit 10.2 to Arch Coal’s Quarterly Report on Form 10-Q filed on August 9, 2016).Exhibit 10.47Amendment No. 5, dated as of June 23, 2016, to the Superpriority Secured Debtor-in-Possession Credit Agreement dated January 21,2016 (incorporated herein by reference to Exhibit 10.3 to Arch Coal’s Quarterly Report on Form 10-Q filed on August 9, 2016).82Table of ContentsExhibit 10.48Amendment No. 6, dated as of July 20, 2016, to that certain Superpriority Secured Debtor-in-Possession Credit Agreement dated as ofJanuary 21, 2016 (incorporated by reference to Exhibit 10.2 of Arch Coal’s Current Report on Quarterly Report 10-Q filed on November9, 2016).Exhibit 10.49Amendment No. 7, dated as of September 28, 2016, to the Superpriority Secured Debtor-in-Possession Credit Agreement dated as ofJanuary 21, 2016 (incorporated by reference to Exhibit 10.3 of Arch Coal’s Current Report on Quarterly Report 10-Q filed on November9, 2016).Exhibit 10.50Restructuring Support Agreement, dated as of January 10, 2016, by and among the Debtors (as defined therein) and the ConsentingLenders (as defined therein) (incorporated herein by reference to Exhibit 10.55 to Arch Coal’s Annual Report on Form 10-K for the yearended December 31, 2015).Exhibit 10.51Amendment No. 2, dated as of March 28, 2016, to the Restructuring Support Agreement dated January 10, 2016 (incorporated herein byreference to Exhibit 10.2 to Arch Coal’s Quarterly Report on Form 10-Q filed on May 10, 2016).Exhibit 10.52Amendment No. 3, dated as of April 26, 2016, to the Restructuring Support Agreement dated January 10, 2016 (incorporated herein byreference to Exhibit 10.4 to Arch Coal’s Quarterly Report on Form 10-Q filed on August 9, 2016).Exhibit 10.53Amendment No. 4, dated as of June 10, 2016, to the Restructuring Support Agreement dated January 10, 2016 (incorporated herein byreference to Exhibit 10.5 to Arch Coal’s Quarterly Report on Form 10-Q filed on August 9, 2016).Exhibit 10.54Amendment No. 5, dated as of June 23, 2016, to the Restructuring Support Agreement dated January 10, 2016 (incorporated herein byreference to Exhibit 10.6 to Arch Coal’s Quarterly Report on Form 10-Q filed on August 9, 2016).Exhibit 10.55Amended and Restated Restructuring Support Agreement, dated as of July 5, 2016 (incorporated by reference to Exhibit 10.1 of ArchCoal’s Current Report on Quarterly Report 10-Q filed on November 9, 2016).Exhibit 21.1Subsidiaries of the registrant.Exhibit 23.1Consent of Ernst & Young LLP.Exhibit 23.2Consent of Weir International, Inc.Exhibit 24.1Power of AttorneyExhibit 31.1Rule 13a-14(a)/15d-14(a) Certification of John W. Eaves.Exhibit 31.2Rule 13a-14(a)/15d-14(a) Certification of John T. Drexler.Exhibit 32.1Section 1350 Certification of John W. Eaves.Exhibit 32.2Section 1350 Certification of John T. Drexler.Exhibit 95.1Mine Safety Disclosure ExhibitExhibit 95.2Order to Mingo Logan Coal Company, a subsidiary of Arch Coal, Inc. under section 107(a) of the Federal Mine Safety and Health Actof 1977 for excessive measurable limits of methane air mixture (incorporated by reference to Arch Coal’s Current Report on Form 8-Kfiled on September 8, 2016)Exhibit 101Interactive Data File (Form 10-K for the year ended December 31, 2016 filed in XBRL). The financial information contained in theXBRL-related documents is ''unaudited" and "unreviewed." 83Table of ContentsFINANCIAL STATEMENTS AND SUPPLEMENTARY DATAIndex to Consolidated Financial StatementsReport of Independent Registered Public Accounting FirmF- 2Report of ManagementF- 3 Consolidated Statements of Operations: For the period October 2, 2016 through December 31, 2016 (Successor); January 1, 2016 through October 1, 2016 and for the years endedDecember 31, 2015 and 2014 (Predecessor)F- 4 Consolidated Statements of Comprehensive Income (loss): For the period October 2, 2016 through December 31, 2016 (Successor); January 1, 2016 through October 1, 2016 and for the years endedDecember 31, 2015 and 2014 (Predecessor)F- 5 Consolidated Balance Sheets at December 31, 2016 (Successor) and 2015 (Predecessor)F- 6 Consolidated Statements of Cash Flows: For the period October 2, 2016 through December 31, 2016 (Successor); January 1, 2016 through October 1, 2016 and for the years endedDecember 31, 2015 and 2014 (Predecessor)F- 7 Consolidated Statements of Stockholders’ Equity (Deficit): For the period October 2, 2016 through December 31, 2016 (Successor); January 1, 2016 through October 1, 2016 and for the years endedDecember 31, 2015 and 2014 (Predecessor)F- 8 Notes to Consolidated Financial StatementsF- 9Financial Statement ScheduleF- 61 F- 1Table of ContentsReport of Independent Registered Public Accounting FirmThe Board of Directors and Shareholders of Arch Coal, Inc.We have audited the accompanying consolidated balance sheets of Arch Coal, Inc. and subsidiaries (the Company) as ofDecember 31, 2016 (Successor) and 2015 (Predecessor), and the related consolidated statements of operations, comprehensive income(loss), stockholders’ equity (deficit) and cash flows for the period from October 2, 2016 through December 31, 2016 (Successor), theperiod from January 1, 2016 through October 1, 2016 (Predecessor), and for each of the two years in the period ended December 31,2015 (Predecessor). Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statementsare the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based onour audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (UnitedStates). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financialstatements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financialreporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures thatare appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internalcontrol over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimatesmade by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basisfor our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidatedfinancial position of Arch Coal, Inc. and subsidiaries at December 31, 2016 (Successor) and 2015 (Predecessor), and the consolidatedresults of their operations and their cash flows for the period from October 2, 2016 through December 31, 2016 (Successor), the periodfrom January 1, 2016 through October 1, 2016 (Predecessor), and for each of the two years in the period ended December 31, 2015(Predecessor), in conformity with U.S. generally accepted accounting principles.As discussed in Notes 1 and 3 to the consolidated financial statements, on September 13, 2016, the Bankruptcy Court enteredan order confirming the Plan of Reorganization, which became effective on October 5, 2016. Accordingly, the accompanyingconsolidated financial statements have been prepared in conformity with Accounting Standards Codification 852-10, Reorganizations,for the Successor Company as a new entity with assets, liabilities and a capital structure having carrying amounts not comparable withprior periods (Predecessor) as described in Notes 1 and 3./s/ Ernst & Young, LLPSt. Louis, MissouriFebruary 24, 2017F- 2Table of ContentsREPORT OF MANAGEMENT The management of Arch Coal, Inc. (the “Company”) is responsible for the preparation of the consolidated financial statements and related financialinformation in this annual report. The financial statements are prepared in accordance with accounting principles generally accepted in the United States andnecessarily include some amounts that are based on management’s informed estimates and judgments, with appropriate consideration given to materiality. The Company maintains a system of internal accounting controls designed to provide reasonable assurance that financial records are reliable forpurposes of preparing financial statements and that assets are properly accounted for and safeguarded. The concept of reasonable assurance is based on therecognition that the cost of a system of internal accounting controls should not exceed the value of the benefits derived. The Company has a professionalstaff of internal auditors who monitor compliance with and assess the effectiveness of the system of internal accounting controls. The Audit Committee of the Board of Directors, comprised of independent directors, meets regularly with management, the internal auditors, and theindependent auditors to discuss matters relating to financial reporting, internal accounting control, and the nature, extent and results of the audit effort. Theindependent auditors and internal auditors have full and free access to the Audit Committee, with and without management present.MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING The management of Arch Coal, Inc. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting,as defined in Securities Exchange Act Rule 13a-15(f). Our internal control over financial reporting is a process designed under the supervision of ourprincipal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparationof consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation ofthe effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree ofcompliance with the policies or processes may deteriorate.Under the supervision and with the participation of the Company’s management, including its principal executive officer and principal financialofficer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting as of December 31, 2016 based on thecriteria set forth in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.Based on its evaluation, management concluded that the Company’s internal control over financial reporting is effective as of December 31, 2016. F- 3Table of ContentsArch Coal, Inc. and SubsidiariesConsolidated Statements of Operations(in thousands, except per share data) SuccessorPredecessorOctober 2throughDecember 31,2016January 1through October1, 2016Year EndedDecember 31,2015 Year EndedDecember 31,2014 Revenues $575,688$1,398,709 $2,573,260 $2,937,119Costs, expenses and other operating Cost of sales (exclusive of items shown separately below) 470,6441,264,464 2,172,753 2,533,284Depreciation, depletion and amortization 32,604191,581 379,345 418,748Accretion on asset retirement obligations 7,63424,321 33,680 32,909Amortization of sales contracts, net 796(728) (8,811) (13,187)Change in fair value of coal derivatives and coal trading activities, net 3962,856 (1,583) (3,686)Asset impairment and mine closure costs —129,267 2,628,303 24,113Losses from disposed operations resulting from Patriot Coal bankruptcy —— 116,343 —Selling, general and administrative expenses 22,83659,343 98,783 114,223Other operating expense (income), net (5,340)(15,257) 19,510 (19,754) 529,5701,655,847 5,438,323 3,086,650Income (loss) from operations46,118(257,138)(2,865,063) (149,531) Interest expense, net Interest expense(11,241)(135,888) (397,979) (390,946)Interest and investment income4872,653 4,430 7,758 (10,754)(133,235) (393,549) (383,188) Income (loss) before nonoperating expenses 35,364(390,373) (3,258,612) (532,719) Nonoperating expense Net loss resulting from early retirement of debt and debt restructuring—(2,213) (27,910) —Reorganization income (loss), net (759)1,630,041 — — (759)1,627,828 (27,910) — Income (loss) before income taxes34,6051,237,455(3,286,522) (532,719)Provision for (benefit from) income taxes 1,156(4,626) (373,380) 25,634Net income (loss)33,4491,242,081(2,913,142) (558,353) Earnings per common share Basic earnings per common share $1.34$58.33 $(136.86) $(26.31) Diluted earnings per common share $1.31$58.28 $(136.86) $(26.31) Weighted average shares outstanding Basic weighted average shares outstanding 25,00221,293 21,285 21,222 Diluted weighted average shares outstanding 25,46921,313 21,285 21,222The accompanying notes are an integral part of the consolidated financial statements.F- 4Table of ContentsArch Coal, Inc. and SubsidiariesConsolidated Statements of Comprehensive Income (Loss)(in thousands) SuccessorPredecessor October 2 throughDecember 31,2016January 1 throughOctober 1, 2016 Year EndedDecember 31, 2015 Year EndedDecember 31, 2014 Net income (loss) $33,449$1,242,081 $(2,913,142) $(558,353) Derivative instruments Comprehensive income (loss) before tax —(532) (3,477) 3,102Income tax benefit (provision) —80 1,252 (1,117) —(452) (2,225) 1,985Pension, postretirement and other post-employment benefits Comprehensive income (loss) before tax 24,067(1,848) (5,592) (44,143)Income tax benefit (provision) —483 2,011 15,891 24,067(1,365) (3,581) (28,252)Available-for-sale securities Comprehensive income (loss) before tax 3872,968 1,185 (12,788)Income tax benefit (provision) —(1,042) (435) 4,604 3871,926 750 (8,184) Total other comprehensive income (loss) 24,454109 (5,056) (34,451)Total comprehensive income (loss) $57,903$1,242,190 $(2,918,198) $(592,804) The accompanying notes are an integral part of the consolidated financial statements.F- 5Table of ContentsArch Coal, Inc. and SubsidiariesConsolidated Balance Sheets(in thousands, except per share data) SuccessorPredecessor December 31, 2016December 31, 2015Assets Current assetsCash and cash equivalents$305,372$450,781Short term investments88,072200,192Restricted cash71,05097,542Trade accounts receivable (net of allowance for doubtful accounts of $0.0 million and$7.8 million, respectively)184,483117,405Other receivables19,87718,362Inventories113,462196,720Prepaid royalties2,28110,022Deferred income taxes——Coal derivative assets2628,035Other current assets93,76339,866Total current assets878,6221,138,925 Property, plant and equipment Coal lands and mineral rights387,5913,713,639Plant and equipment418,1822,359,674Deferred mine development280,323553,286 1,086,0966,626,599Less accumulated depreciation, depletion and amortization(32,493)(3,007,570)Property, plant and equipment, net1,053,6033,619,029Other assetsPrepaid royalties—23,671Equity investments96,074201,877Other noncurrent assets108,29858,379Total other assets204,372283,927Total assets$2,136,597$5,041,881Liabilities and Stockholders' Equity (Deficit) Current liabilitiesAccounts payable$95,953$128,131Accrued expenses and other current liabilities205,240329,450Current maturities of debt11,0385,042,353Total current liabilities312,2315,499,934Long-term debt351,84130,953Asset retirement obligations337,227396,659Accrued pension benefits38,88427,373Accrued postretirement benefits other than pension101,44599,810Accrued workers’ compensation184,568112,270Other noncurrent liabilities63,824119,171Total liabilities1,390,0206,286,170Stockholders' equity (deficit)Successor Common stock, $0.01 par value, authorized 300,000 shares, issued 25,002shares at December 31, 2016250—Predecessor Common stock, $0.01 par value, authorized 26,000 shares, issued 21,446shares at December 31, 2015—2,145Paid-in capital688,4243,054,211Treasury stock, at cost—(53,863)Retained earnings (accumulated deficit)33,449(4,244,967)Accumulated other comprehensive income (loss)24,454(1,815)Total stockholders’ equity (deficit)746,577(1,244,289)Total liabilities and stockholders’ equity (deficit)$2,136,597$5,041,881The accompanying notes are an integral part of the consolidated financial statements.F- 6Table of ContentsArch Coal, Inc. and SubsidiariesConsolidated Statements of Cash Flows(in thousands) SuccessorPredecessorOctober 2through December31, 2016January 1through October1, 2016 Year EndedDecember 31,2015 Year EndedDecember 31,2014 Operating activities Net income (loss)$33,449$1,242,081 $(2,913,142) $(558,353)Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities: Depreciation, depletion and amortization32,604191,581 379,345 418,748Accretion on asset retirement obligations7,63424,321 33,680 32,909Amortization of sales contracts, net796(728) (8,811) (13,187)Prepaid royalties expensed2,5874,791 8,109 9,698Deferred income taxes3(419) (367,210) 25,152Employee stock-based compensation expense1,0322,096 5,760 9,847Gains on disposals and divestitures(485)(6,628) (2,270) (27,512)Asset impairment and noncash mine closure costs—119,194 2,613,345 16,868Losses from disposed operations resulting from Patriot Coal bankruptcy—— 116,343 —Amortization relating to financing activities46712,800 25,241 17,363Net loss resulting from early retirement of debt and debt restructuring—2,213 27,910 —Non-cash bankruptcy reorganization items—(1,775,910) — —Changes in: Receivables(22,196)(42,786) 98,212 (8,991)Inventories24,87034,440 (6,534) 41,548Coal derivative assets and liabilities1,6625,678 973 5,449Accounts payable, accrued expenses and other current liabilities34,12915,316 (15,532) 41,680Asset retirement obligations(4,535)(12,041) (17,040) (14,621)Pension, postretirement and other postemployment benefits(5,625)(15,692) 4,800 (25,347)Other(22,200)(28,525) (27,546) (4,833)Cash provided by (used in) operating activities84,192(228,218)(44,367) (33,582)Investing activities Capital expenditures(15,214)(82,434) (119,024) (147,286)Minimum royalty payments(63)(305) (5,871) (7,317)Proceeds from disposals and divestitures572(2,921) 2,191 62,358Purchases of short term investments—(98,750) (246,735) (211,929)Proceeds from sales of short term investments23,000185,859 290,205 205,611Proceeds from sale of investments in equity investments and securities—1,147 2,259 9,464Investments in and advances to affiliates, net(823)(3,441) (11,502) (16,657)Withdrawals (deposits) of restricted cash10,51215,979 (91,864) (5,678)Cash provided by (used in) investing activities17,98415,134(180,341) (111,434)Financing activities Payments to retire debt—— — (300)Payments on term loan(816)— (19,500) (19,500)Net receipts (payments) on other debt3,374(11,986) (11,332) (5,395)Debt financing costs—(23,011) — (4,519)Dividends paid—— — (2,123)Expenses related to debt restructuring—(2,213) (27,910) —Other151— — (15)Cash provided by (used in) financing activities2,709(37,210) (58,742) (31,852)Increase (decrease) in cash and cash equivalents104,885(250,294) (283,450) (176,868)Cash and cash equivalents, beginning of period200,487450,781 734,231 911,099Cash and cash equivalents, end of period$305,372$200,487 $450,781 $734,231SUPPLEMENTAL CASH FLOW INFORMATION Cash paid during the period for interest$39,620$79,979 $283,337 $361,727Cash refunded during the period for income taxes, net$287$49 $4,138 $4,896The accompanying notes are an integral part of the consolidated financial statements.F- 7Table of ContentsArch Coal, Inc. and SubsidiariesConsolidated Statements of Stockholders’ Equity (Deficit)Three Years Ended December 31, 2016 Accumulated Treasury RetainedEarnings Other Common Paid-In Stock, at (Accumulated Comprehensive Stock Capital Cost Deficit) Income (Loss) Total (In thousands, except per share data)Predecessor Company BALANCE AT JANUARY 1, 2014$2,141 $3,038,613 $(53,848) $(771,349) $37,692 $2,253,249Total comprehensive loss— — — (558,353) (34,451) (592,804)Dividends on common shares ($0.01 per share)0 0 — (2,123) — (2,123)Treasury shares purchased— — (15) — — (15)Employee stock-based compensation expense— 9,847 — — — 9,847BALANCE AT DECEMBER 31, 2014$2,141 $3,048,460 $(53,863) $(1,331,825) $3,241 $1,668,154Total comprehensive loss0 0 — (2,913,142) (5,056) (2,918,198)Issuance of 64 shares of common stock under the stockincentive plan-restricted stock and restricted stock units,net of forfeitures4 (9) — — — (5)Employee stock-based compensation expense— 5,760 — — — 5,760BALANCE AT DECEMBER 31, 2015$2,145 $3,054,211 $(53,863) $(4,244,967) $(1,815) $(1,244,289)Total comprehensive income— — — 1,242,081 109 1,242,190Employee stock-based compensation— 2,099 — — — 2,099Elimination of predecessor equity(2,145) (3,056,310) 53,863 3,002,886 1,706 —BALANCE AT OCTOBER 1, 2016$— $— $— $— $— $—Successor Company Issuance of successor equity$250 $687,233 $— $— $— $687,483Employee stock-based compensation— 1,032 — — — 1,032Warrants exercised— 159 — — — 159Total comprehensive income— — — 33,449 24,454 57,903 BALANCE AT DECEMBER 31, 2016$250 $688,424 $— $33,449 $24,454 $746,577F- 8Table of ContentsArch Coal, Inc. and SubsidiariesNotes to Consolidated Financial Statements1. Basis of PresentationThe accompanying consolidated financial statements include the accounts of Arch Coal, Inc. and its subsidiaries and controlled entities (the “Company”).Unless the context indicates otherwise, the terms “Arch” and the “Company” are used interchangeably in this Annual Report on Form 10-K refer to both thePredecessor and Successor Company. The Company’s primary business is the production of thermal and metallurgical coal from surface and undergroundmines located throughout the United States, for sale to utility, industrial and steel producers both in the United States and around the world. The Companycurrently operates mining complexes in West Virginia, Kentucky, Virginia, Illinois, Wyoming and Colorado. All subsidiaries are wholly-owned.Intercompany transactions and accounts have been eliminated in consolidation.Chapter 11 Filing and Emergence from BankruptcyOn January 11, 2016 (the “Petition Date”), Arch and substantially all of its wholly owned domestic subsidiaries (the “Filing Subsidiaries” and, togetherwith 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 thebankruptcy proceedings, each Debtor operated its business as a “debtor in possession” under the jurisdiction of the Court and in accordance with theapplicable provisions of the Bankruptcy Code and the orders of the Court.For periods subsequent to filing the Bankruptcy Petitions, the Company applied the Financial Accounting Standards Board (“FASB”) AccountingStandards Codification (“ASC”) 852, “Reorganizations”, in preparing its consolidated financial statements. ASC 852 requires that financial statementsdistinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certainrevenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings have been recorded in areorganization line item on the Consolidated Statement of Operations. In addition, the pre-petition obligations that may be impacted by the bankruptcyreorganization process were classified on the balance sheet as liabilities subject to compromise. On September 13, 2016, the Bankruptcy Court entered an order, Docket No. 1324, confirming the Debtors’ Fourth Amended Joint Plan of Reorganizationunder 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, the Company applied fresh start accounting which requires the Company to allocate its reorganization value to the fair valueof assets and liabilities in conformity with the guidance for the acquisition method of accounting for business combinations. In addition to fresh startaccounting, the Company’s consolidated financial statements reflect all impacts of the transactions contemplated by the Plan. Under the provisions of freshstart accounting, a new entity has been created for financial reporting purposes. The Company selected an accounting convenience date of October 1, 2016for purposes of applying fresh start accounting as the activity between the convenience date and the Effective Date does not result in a material difference inthe 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 whichincludes the impact of the Plan provisions and the application of fresh start accounting. As such, the Company’s financial statements for the Successor willnot 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 theeffects of the Plan. For further information on fresh start accounting, please see Note 3 to the Consolidated Financial Statements, “Emergence fromBankruptcy and Fresh Start Accounting.”F- 9Table of Contents2. Accounting PoliciesThe accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the UnitedStates for financial reporting and U.S. Securities and Exchange Commission regulations.Accounting EstimatesThe preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to makeestimates and assumptions that affect the reported amounts of assets and liabilities and revenues and expenses in the accompanying consolidated financialstatements and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.Cash and Cash EquivalentsCash and cash equivalents are stated at cost. Cash equivalents consist of highly-liquid investments with an original maturity of three months or lesswhen purchased.Restricted cashRestricted cash represents cash collateral supporting letters of credit issued under the Company’s accounts receivable securitization program.Accounts ReceivableAccounts receivable are recorded at amounts that are expected to be collected, based on past collection history, the economic environment and specifiedrisks identified in the receivables portfolio.InventoriesCoal and supplies inventories are valued at the lower of average cost or market. Coal inventory costs include labor, supplies, equipment costs,transportation costs incurred prior to the transfer of title to customers and operating overhead. The costs of removing overburden, called stripping costs,incurred during the production phase of the mine are considered variable production costs and are included in the cost of the coal extracted during the periodthe stripping costs are incurred.Investments and Membership Interests in Joint VenturesInvestments and membership interests in joint ventures are accounted for under the equity method of accounting if the Company has the ability toexercise significant influence, but not control, over the entity. The Company’s share of the entity’s income or loss is reflected in “Other operating expense(income), net” in the consolidated statements of operations. Information about investment activity is provided in Note 9 to the Consolidated FinancialStatements, “Equity Method Investments and Membership Interests in Joint Ventures.”Investments in debt securities and marketable equity securities that do not qualify for equity method accounting are classified as available-for-sale andare recorded at their fair values. Unrealized gains and losses on these investments are recorded in other comprehensive income or loss. A decline in the valueof an investment that is considered other-than-temporary would be recognized in operating expenses.Sales ContractsCoal supply agreements (sales contracts) valued during fresh start accounting or acquired in a business combination are capitalized at their fair value andamortized over the tons of coal shipped during the term of the contract. The fair value of a sales contract is determined by discounting the cash flowsattributable to the difference between the contract price and the prevailing forward prices for the tons under contract at the date of acquisition. See Note 10 tothe Consolidated Financial Statements, “Sales Contracts” for further information related to the Company’s sales contracts.Exploration CostsCosts to acquire permits for exploration activities are capitalized. Drilling and other costs related to locating coal deposits and evaluating the economicviability of such deposits are expensed as incurred.Prepaid RoyaltiesLeased mineral rights are often acquired through royalty payments. When royalty payments represent prepayments recoupable against royalties owed onfuture revenues from the underlying coal, they are recorded as a prepaid asset, with amounts expected to be recouped within one year classified as current.When coal from these leases is sold, the royalties owed are recouped against the prepayment and charged to cost of sales. An impairment charge is recognizedfor prepaid royalties that are not expected to be recouped.F- 10Table of ContentsProperty, Plant and EquipmentPlant and EquipmentPlant and equipment were fair valued at emergence during fresh start accounting; subsequent purchases of property, plant and equipment have beenrecorded at cost. Interest costs incurred during the construction period for major asset additions are capitalized. The Company did not capitalize any interestcosts during the periods October 2 through December 31, 2016, January 1 through October 1, 2016 or for the year ended December 31, 2015, respectively.Expenditures that extend the useful lives of existing plant and equipment or increase the productivity of the asset are capitalized. The cost of maintenanceand repairs that do not extend the useful life or increase the productivity of the asset is expensed as incurred.Preparation plants and loadouts are depreciated using the units-of-production method over the estimated recoverable reserves, subject to a minimumlevel of depreciation. Other plant and equipment are depreciated principally using the straight-line method over the estimated useful lives of the assets,limited by the remaining life of the mine. The useful lives of mining equipment, including longwalls, draglines and shovels, range from 7 to 18 years. Theuseful lives of buildings and leasehold improvements generally range from 1 to 18 years.Deferred Mine DevelopmentCosts of developing new mines or significantly expanding the capacity of existing mines are capitalized and amortized using the units-of-productionmethod over the estimated recoverable reserves that are associated with the property being benefited. Costs may include construction permits and licenses;mine design; construction of access roads, shafts, slopes and main entries; and removing overburden to access reserves in a new pit. Additionally, deferredmine development includes the asset cost associated with asset retirement obligations.Coal Lands and Mineral RightsRights to coal reserves may be acquired directly through governmental or private entities. A significant portion of the Company’s coal reserves arecontrolled through leasing arrangements. Lease agreements are generally long-term in nature (original terms range from 10 to 50 years), and substantially allof the leases contain provisions that allow for automatic extension of the lease term providing certain requirements are met.The net book value of the Company’s coal interests was $0.4 billion and $2.4 billion at December 31, 2016 and 2015, respectively. Payments to acquireroyalty lease agreements and lease bonus payments are capitalized as a cost of the underlying mineral reserves and depleted over the life of proven andprobable reserves. Coal lease rights are depleted using the units-of-production method, and the rights are assumed to have no residual value.The Company currently does not have any future lease bonus payments.Depreciation, depletion and amortizationThe depreciation, depletion and amortization related to long-lived assets is reflected in the statement of operations as a separate line item. Nodepreciation, depletion or amortization is included in any other operating cost categories.ImpairmentIf facts and circumstances suggest that the carrying value of a long-lived asset or asset group may not be recoverable, the asset or asset group is reviewedfor potential impairment. If this review indicates that the carrying amount of the asset will not be recoverable through projected undiscounted cash flowsgenerated by the asset and its related asset group over its remaining life, then an impairment loss is recognized by reducing the carrying value of the asset toits fair value. The Company may, under certain circumstances, idle mining operations in response to market conditions or other factors. Because an idling isnot a permanent closure, it is not considered an automatic indicator of impairment. See additional discussion in Note 5 to the Consolidated FinancialStatements, “Impairment Charges and Mine Closure Costs.”Deferred Financing CostsThe Company capitalizes costs incurred in connection with new borrowings, the establishment or enhancement of credit facilities and the issuance ofdebt securities. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using the interestmethod. Debt issuance costs related to a recognized liability are presented in the balance sheet as a direct reduction from the carrying amount of that liabilitywhereas debt issuance costs related to a credit facility with no balance outstanding are shown as an asset. The unamortized balance of deferred financing costswas $5.2 million at December 31, 2016, with $1.9 million classified as current. As these amounts relate to a credit facility with no outstanding borrowings,these current amounts are classified within “Other current assets” and the noncurrent amounts are classified within “Other noncurrent assets.” Theunamortized balance of deferred financing costs at December 31, 2015 was $66.3 million with $65.6 million classified as current. As these debt issuance costsprimarily related to a recognized liability, the current amounts are recorded in “Current maturities of debt” and the noncurrent amounts are recorded in“Long-term debt” in the accompanying consolidated balance sheets.F- 11Table of ContentsRevenue RecognitionRevenues include sales to customers of coal produced at Company operations and coal purchased from third parties. The Company recognizes revenueat the time risk of loss passes to the customer at contracted amounts. Transportation costs are included in cost of sales and amounts billed by the Company toits customers for transportation are included in revenues.Other Operating Expense (Income), netOther operating expense (income), net in the accompanying consolidated statements of operations reflects income and expense from sources other thanphysical coal sales, including: bookouts, or the practice of offsetting purchase and sale contracts for shipping convenience purposes; contract settlements;liquidated damage charges related to unused terminal and port capacity; royalties earned from properties leased to third parties; income from equityinvestments (Note 9); gains and losses from divestitures and dispositions of assets; and realized gains and losses on derivatives that do not qualify for hedgeaccounting and are not held for trading purposes (Note 11).Asset Retirement ObligationsThe Company’s legal obligations associated with the retirement of long-lived assets are recognized at fair value at the time the obligations are incurred.Accretion expense is recognized through the expected settlement date of the obligation. Obligations are incurred at the time development of a minecommences for underground and surface mines or construction begins for support facilities, refuse areas and slurry ponds. The obligation’s fair value isdetermined using a discounted cash flow technique and is based upon permit requirements and various estimates and assumptions that would be used bymarket participants, including estimates of disturbed acreage, reclamation costs and assumptions regarding equipment productivity. Upon initial recognitionof a liability, a corresponding amount is capitalized as part of the carrying value of the related long-lived asset.The Company reviews its asset retirement obligation at least annually and makes necessary adjustments for permit changes as granted by state authoritiesand for revisions of estimates of the amount and timing of costs. For ongoing operations, adjustments to the liability result in an adjustment to thecorresponding asset. For idle operations, adjustments to the liability are recognized as income or expense in the period the adjustment is recorded. Anydifference between the recorded obligation and the actual cost of reclamation is recorded in profit or loss in the period the obligation is settled. Seeadditional discussion in Note 15, “Asset Retirement Obligations.”Loss ContingenciesThe Company accrues for cost related to contingencies when a loss is probable and the amount is reasonably determinable. Disclosure of contingenciesis included in the financial statements when it is at least reasonably possible that a material loss or an additional material loss in excess of amounts alreadyaccrued may be incurred. The amount accrued represents the Company’s best estimate of the loss, or, if no best estimate within a range of outcomes exists, theminimum amount in the range.Derivative InstrumentsThe Company generally utilizes derivative instruments to manage exposures to commodity prices. Additionally, the Company may hold certain coalderivative instruments for trading purposes. Derivative financial instruments are recognized in the balance sheet at fair value. Certain coal contracts may meetthe definition of a derivative instrument, but because they provide for the physical purchase or sale of coal in quantities expected to be used or sold by theCompany over a reasonable period in the normal course of business, they are not recognized on the balance sheet.Certain derivative instruments are designated as the hedge instrument in a hedging relationship. In a fair value hedge, the Company hedges the risk ofchanges in the fair value of a firm commitment, typically a fixed-price coal sales contract. Changes in both the hedged firm commitment and the fair value ofa derivative used as a hedge instrument in a fair value hedge are recorded in earnings. In a cash flow hedge, the Company hedges the risk of changes in futurecash flows related to a forecasted purchase or sale. Changes in the fair value of the derivative instrument used as a hedge instrument in a cash flow hedge arerecorded in other comprehensive income or loss. Amounts in other comprehensive income or loss are reclassified to earnings when the hedged transactionaffects earnings and are classified in a manner consistent with the transaction being hedged. The Company formally documents the relationships betweenhedging instruments and the respective hedged items, as well as its risk management objectives for hedge transactions.The Company evaluates the effectiveness of its hedging relationships both at the hedge’s inception and on an ongoing basis. Any ineffective portion ofthe change in fair value of a derivative instrument used as a hedge instrument in a fair value or cash flow hedge is recognized immediately in earnings. Theineffective portion is based on the extent to which exact offset is not achieved between the change in fair value of the hedge instrument and the cumulativechange in expected future cash flows on the hedged transaction from inception of the hedge in a cash flow hedge or the change in the fair value.Ineffectiveness was insignificant for the periods disclosed within.F- 12Table of ContentsSee Note 11, “Derivatives” for further disclosures related to the Company’s derivative instruments.Fair ValueFair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly hypothetical transaction betweenmarket participants at a given measurement date. Valuation techniques used must maximize the use of observable inputs and minimize the use ofunobservable inputs. See Note 16, “Fair Value Measurements” for further disclosures related to the Company’s recurring fair value estimates.Income TaxesDeferred income taxes are provided for temporary differences arising from differences between the financial statement and tax basis of assets andliabilities existing at each balance sheet date using enacted tax rates anticipated to be in effect when the related taxes are expected to be paid or recovered. Avaluation allowance is established if it is more likely than not that a deferred tax asset will not be realized. Management reassesses the ability to realize itsdeferred tax assets annually in the fourth quarter or when circumstances indicate that the ability to realize deferred tax assets has changed. In determining theneed for a valuation allowance, the Company considers projected realization of tax benefits based on expected levels of future taxable income, available taxplanning strategies and the reversal of temporary differences.Benefits from tax positions that are uncertain are not recognized unless the Company concludes that it is more likely than not that the position would besustained in a dispute with taxing authorities, should the dispute be taken to the court of last resort. The Company would measure any such benefit at thelargest amount of benefit that is greater than 50 percent likely of being realized upon settlement with taxing authorities.See Note 14, “Taxes” for further disclosures about income taxes.Benefit PlansThe Company has non-contributory defined benefit pension plans covering most of its salaried and hourly employees. On January 1, 2015 theCompany’s cash balance and excess pension plans were amended to freeze new service credits for any new or active employee. The Company also currentlyprovides certain postretirement medical and life insurance coverage for eligible employees. The cost of providing these benefits are determined on anactuarial basis and accrued over the employee’s period of active service.The Company recognizes the overfunded or underfunded status of these plans as determined on an actuarial basis on the balance sheet and the changesin the funded status are recognized in other comprehensive income. The Company amortizes actuarial gains and losses over the remaining service attributionperiods of the employees using the corridor method. See Note 20, “Employee Benefit Plans” for additional disclosures relating to these obligations.Stock-Based CompensationThe compensation cost of all stock-based awards is determined based on the grant-date fair value of the award, and is recognized over the requisiteservice period. The grant-date fair value of option awards and restricted stock awards with a market condition is determined using a Monte Carlo simulation.Compensation cost for an award with performance conditions is accrued if it is probable that the conditions will be met. See further discussion in Note 18,“Stock-Based Compensation and Other Incentive Plans.” F- 13Table of ContentsRecently Adopted Accounting GuidanceIn April 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-03 (“ASU 2015-03”),Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 required debt issuance costs related to a recognized liability to be presented in thebalance sheet as a direct reduction from the carrying amount of that liability, consistent with debt discounts. The Company adopted ASU 2015-03 in the firstquarter of 2016 as mandated by the standard. The following reflects the retrospective application: December 31, 2015 (in thousands)Other current assets, prior to revision $104,723Revision of debt issuance costs (64,857) Other current assets, as revised $39,866 Current maturities of debt, prior to revision $5,107,210Revision of debt issuance costs (64,857) Current maturities of debt, as revised $5,042,353Effective December 31, 2016, the Company adopted ASU No. 2014-15 (“ASU 2014-15”), Disclosures of Uncertainties about an Entity’s Ability toContinue as a Going Concern. ASU 2014-15 requires management to evaluate for each annual and interim reporting period whether conditions or events giverise to substantial doubt that an entity has the ability to continue as a going concern within one year following issuance of the financial statements andrequires specific disclosures regarding the conditions or events leading to substantial doubt. The adoption of ASU 2014-15 did not have any impact on theCompany’s financial position or results of operations.Effective December 31, 2016, the Company adopted the Accounting Standards Update No. 2015-17 (“ASU 2015-17”), Balance Sheet Classification ofDeferred Taxes which requires that all deferred tax assets and liabilities, along with any related valuation allowance be classified as noncurrent on thebalance sheet. The standard has been applied on a retrospective basis. The adoption of ASU 2015-17 did not have any impact on the Company’s financialposition or results of operations.Investments at fair value include investments in funds, including certain money market funds, that are measured at net asset value (“NAV”). TheCompany uses NAV to measure the fair value of its fund investments when (i) the fund investment does not have a readily determinable fair value and (ii) theNAV of the investment fund is calculated in a manner consistent with the measurement principles of investment company accounting, includingmeasurement of the underlying investments at fair value. The Company adopted ASU No. 2015-07 in January 2016, and, as required, disclosures in theparagraphs and tables below are limited to only those investments in funds that are measured at NAV. In accordance with ASU No. 2015-07, previouslyreported amounts have been conformed to the current presentation.Recent Accounting Guidance Issued Not Yet EffectiveIn May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 is a comprehensive revenue recognitionstandard that will supersede nearly all existing revenue recognition guidance under current U.S. GAAP and replace it with a principle based approach fordetermining revenue recognition. ASU 2014-09 will require that companies recognize revenue based on the value of transferred goods or services as theyoccur in the contract. The ASU also will require additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arisingfrom customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract.ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted only in annual reporting periodsbeginning after December 15, 2016, including interim periods therein. Entities will be able to transition to the standard either retrospectively or as acumulative-effect adjustment as of the date of adoption. The Company’s primary source of revenue is from the sale of coal through both short-term and long-term contracts with utilities, industrial customers and steel producers whereby revenue is currently recognized when risk of loss has passed to the customer.Upon adoption of this new standard, the Company believes that the timing of revenue recognition related to our coal sales will remain consistent with ourcurrent practice. The Company is currently evaluating other revenue streams to determine the potentialF- 14Table of Contentsimpact related to the adoption of the standard, as well as potential disclosures required by the standard. The Company will be adopting the standard under themodified retrospective approach.In February 2016, the FASB issued ASU No. 2016-02, “Leases” which, for operating leases, requires a lessee to recognize a right-of-use asset and a leaseliability, initially measured at the present value of the lease payments, in its balance sheet. The standard also requires a lessee to recognize a single lease cost,calculated so that the cost of the lease is allocated over the term of the lease, on a generally straight line basis. The ASU is effective for public companies forfiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early adoption is permitted. The Company has bothoperating and capital leases. We expect the adoption of this standard to result in the recognition of right-of-use assets and lease liabilities not currentlyrecorded on the Company’s financial statements. The Company is currently in the process of accumulating all contractual lease arrangements in order todetermine the impact on its financial statements.In October 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows-Restricted Cash.” The amendment requires that a statement of cashflows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cashequivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalentswhen reconciling the beginning period and end of period total amounts shown on the statement of cash flows. ASU 2016-18 is effective for fiscal yearsbeginning after December 15, 2018, including interim periods within those fiscal years; early adoption is permitted.F- 15Table of Contents3. Emergence from Bankruptcy and Fresh Start AccountingOn January 11, 2016 (the “Petition Date”), Arch and substantially all of its wholly owned domestic subsidiaries (the “Filing Subsidiaries” and, togetherwith 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 thebankruptcy proceedings, each Debtor operated its business as a “debtor in possession” under the jurisdiction of the Court and in accordance with theapplicable provisions of the Bankruptcy Code and the orders of the Court.For periods subsequent to filing the Bankruptcy Petitions, the Company applied the FASB Accounting Standards Codification (“ASC”) 852,“Reorganizations”, in preparing its consolidated financial statements. ASC 852 requires that financial statements distinguish transactions and events that aredirectly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and lossesand provisions for losses that are realized or incurred in the bankruptcy proceedings have been recorded in a reorganization line item on the ConsolidatedStatement of Operations. In addition, the pre-petition obligations that may be impacted by the bankruptcy reorganization process were classified on thebalance sheet as liabilities subject to compromise.On September 13, 2016, the Bankruptcy Court entered an order, Docket No. 1324, confirming the Debtors’ Fourth Amended Joint Plan of Reorganizationunder 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, the Company applied fresh start accounting which requires the Company to allocate its reorganization value to the fair valueof assets and liabilities in conformity with the guidance for the acquisition method of accounting for business combinations. In addition to fresh startaccounting, the Company’s consolidated financial statements reflect all impacts of the transactions contemplated by the Plan. Under the provisions of freshstart accounting, a new entity has been created for financial reporting purposes. The Company selected an accounting convenience date of October 1, 2016for purposes of applying fresh start accounting as the activity between the convenience date and the Effective Date does not result in a material difference inthe 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 whichincludes the impact of the Plan provisions and the application of fresh start accounting. As such, the Company’s financial statements for the Successor willnot 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 theeffects of the Plan.The following is a summary of certain provisions of the Plan, as confirmed by the Bankruptcy Court pursuant to the Confirmation Order, and is notintended to be a complete description of the Plan.Treatment of ClaimsThe Plan contemplates that:•Holders of allowed administrative expense claims, priority claims (other than administrative expense claims and priority tax claims) andsecured claims (other than claims arising under priority claims, the prepetition first lien credit facility and prepetition second lien notes)will be paid in full.•Holders of allowed claims arising under the Debtors’ prepetition first lien credit facility (“First Lien Credit Facility”) will receive their prorata distribution of (i) total cash payments equal to the greater of (A) $144.8 million less the amount of the adequate protection paymentsand (B) $30 million; (ii) $326.5 million in principal amount of New First Lien Debt Facility; and (iii) 94% of the common stock ofReorganized Arch Coal (the “New Common Stock”), subject to dilution on account of (a) any Class A Common Stock (as defined below)issued upon exercise of the warrants (the “New Warrants”) issued pursuant to the Plan to purchase up to 12% of the fully diluted Class ACommon Stock as of the Effective Date and exercisable at any time for a period of 7 years from the Effective Date at a strike price calculatedbased on a total equity capitalization of $1.425 billion ($57 per share) and (b) the issuance of New CommonF- 16Table of ContentsStock in an amount of up to 10% of the New Common Stock, on a fully diluted basis, pursuant to a management incentive plan (the“Management Incentive Plan”).•Holders of allowed claims on account of prepetition second lien or unsecured notes (the “Prepetition Notes”) will receive their pro ratadistribution of (i) $22.636 million in cash, (ii) at such holder’s election, either (A) such holder’s pro rata share of the New Warrants or (B)such holder’s pro rata share of $25 million in cash and (iii) 6% of the New Common Stock (subject to dilution on account of any exercise ofthe New Warrants and pursuant to the Management Incentive Plan).•Holders of allowed general unsecured claims against Debtors (other than claims on account of the First Lien Credit Facility or PrepetitionNotes) will receive their pro rata distribution of $7.364 million cash, less fees and expenses incurred by any professionals retained by aclaims oversight committee up to $200,000.•The Reorganized Debtors will waive and release any claims or causes of action that they have, had, or may have that are based on sections502(d), 544, 545, 547, 548, 549, 550, 551, 553(b) and 724(a) of the Bankruptcy Code and analogous non-bankruptcy law for all purposesagainst (i) prepetition trade creditors and (ii) officers, directors, employees or representatives of the Debtors or the Reorganized Debtors andall agents and representatives of all of the foregoing. However, the Reorganized Debtors will retain the right to assert any said claims asdefenses or counterclaims in any cause of action brought by any creditor.New First Lien Debt FacilityFor information related to the New First Lien Debt Facility, see Note 13, “Debt and Financing Arrangements.”Securitization FacilityFor information related to the Securitization Facility, see Note 13, “Debt and Financing Arrangements.”Warrant AgreementOn the Effective Date, the Company entered into a warrant agreement (the “Warrant Agreement”) with American Stock Transfer & Trust Company, LLCas warrant agent and, pursuant to the terms of the Plan, issued warrants (“Warrants”) to purchase up to an aggregate of 1,914,856 shares of Class A CommonStock, par value $0.01 per share, of Arch Coal (the “Class A Common Stock”) to holders of claims arising under the Cancelled Notes (as defined below). EachWarrant expires on October 5, 2023, and is initially exercisable for one share of Class A Common Stock at an initial exercise price of $57.00 per share. TheWarrants are exercisable by a holder paying the exercise price in cash or on a cashless basis, at the election of the holder. The Warrants contain anti-dilutionadjustments for stock splits, reverse stock splits, stock dividends, dividends and distributions of cash, other securities or other property, spin-offs and tenderand exchange offers by Arch Coal or its subsidiaries to purchase Class A Common Stock at above-market prices.If, in connection with a merger, recapitalization, business combination, transfer to a third party of substantially all of Arch Coal’s consolidated assets orother transaction that results in a change to the Class A Common Stock (each, a “Transaction”), (i) the Transaction is consummated prior to the fifthanniversary of the Effective Date and the Transaction consideration to holders of Class A Common Stock is 90% or more listed common stock or commonstock of a company that provides publicly available financial reporting, and holds management calls regarding the same, no less than quarterly (“ReportingStock”) or (ii) regardless of the consideration, the Transaction is consummated on or after the fifth anniversary of the Effective Date, the Warrants will beassumed by the surviving company and will become exercisable for the consideration that the holders of Class A Common Stock receive in such Transaction;provided that if the consideration such holders receive consists solely of cash, then upon the consummation of such Transaction, Arch Coal will pay for eachWarrant an amount of cash equal to the greater of (i) (x) the amount of cash payable with respect to the number of shares of Class A Common Stockunderlying the Warrant minus (y) the exercise price per share then in effect multiplied by the number of shares of Class A Common Stock underlying theWarrant and (ii) $0.If a Transaction is consummated prior to the fifth anniversary of the Effective Date in which the Transaction consideration is less than 90% ReportingStock, a portion of the Warrants corresponding to the portion of the Transaction consideration that is Reporting Stock will be assumed by the survivingcompany and will become exercisable for the Reporting Stock consideration that the holders of Class A Common Stock receive in such Transaction, and theportion of the Warrants corresponding to the portion of the Transaction consideration that is not Reporting Stock will, at the option of each holder, (i) beassumed by the surviving company and will become exercisable for the consideration that the holders of Class A Common Stock receive inF- 17Table of Contentssuch Transaction or (ii) be redeemed by Arch Coal for cash in an amount equal to the Black Scholes Payment (as defined in the Warrant Agreement).Termination of Material Definitive AgreementsOn the Effective Date, by operation of the Plan, all outstanding obligations under the following notes issued by Arch Coal and guaranteed by certainsubsidiary guarantors, (collectively, the “Cancelled Notes”) were cancelled and the indentures governing such obligations were cancelled except asnecessary to (a) enforce the rights, claims and interests of the applicable trustee vis-a-vis any parties other than the Debtors, (b) allow each trustee to receivedistributions under the Plan and to distribute them to the holders of the Cancelled Notes in accordance with the terms of the applicable indenture, (c) preserveany rights of the applicable trustee to compensation, reimbursement and indemnification under each of the applicable indentures solely as against any moneyor property distributable to holders of Cancelled Notes, (iv) permit each of the trustees to enforce any obligation owed to them under the Plan and (v) permiteach of the trustees to appear in the Chapter 11 cases or in any proceeding in the Bankruptcy Court or any other court:•7.000% Senior Notes due 2019, issued pursuant to an indenture dated as of June 14, 2011, by and among Arch Coal, as issuer, UMB Bank NationalAssociation, as trustee, and the guarantors named therein, as amended, supplemented or revised thereafter;•7.250% Senior Notes due 2020, issued pursuant to an indenture dated as of August 9, 2010, by and among Arch Coal, as issuer, U.S. Bank NationalAssociation, as trustee, and the guarantors named therein, as amended, supplemented or revised thereafter;•7.250% Senior Notes due 2021, issued pursuant to an indenture dated as of June 14, 2011, by and among Arch Coal, as issuer, UMB Bank NationalAssociation, as trustee, and the guarantors named therein, as amended, supplemented or revised thereafter;•9.875% Senior Notes due 2019, issued pursuant to an indenture dated as of November 21, 2012, by and among Arch Coal, as issuer, UMB BankNational Association, as trustee, and the guarantors named therein, as amended, supplemented or revised thereafter; and•8.000% Second Lien notes due 2019, issued pursuant to an indenture dated as of December 17, 2013, by and among Arch Coal, as issuer,Wilmington Savings Fund Society, as trustee and collateral agent as successor to UMB Bank National Association, and the guarantors namedtherein, as amended, supplemented or revised thereafter.On the Effective Date, by operation of the Plan, all outstanding obligations under the following credit agreement (the “Prepetition Credit Agreement”)entered into by Arch Coal and guaranteed by certain of Arch Coal’s subsidiaries and the related collateral, guaranty and other definitive agreements relatingto the Prepetition Credit Agreement were cancelled and the Prepetition Credit Agreement was cancelled except as necessary to (i) enforce the rights, claimsand interests of the Prepetition Agent (as defined below) and any predecessor thereof vis-a-vis the Lenders and any parties other than the Debtors, (ii) to allowthe Prepetition Agent to receive distributions under the Plan and to distribute them to the lenders under the Prepetition Credit Agreement and (iii) preserveany rights of the Prepetition Agent and any predecessor thereof as against any money or property distributable to holders of claims arising out of thePrepetition Credit Agreement or any related transaction documents, including any priority in respect of payment and the right to exercise any charging lien:•Amended and Restated Credit Agreement, dated as of June 14, 2011 (as amended by the First Amendment, dated as of May 16, 2012, the SecondAmendment, dated as of November 20, 2012, the Third Amendment, dated as of November 21, 2012 and the Fourth Amendment, dated as ofDecember 17, 2013), among Arch Coal, Inc., as borrower, the lenders from time to time party thereto, Wilmington Trust, National Association, in itscapacities as term loan facility administrative agent (as successor to Bank of America, N.A. in such capacity) and collateral agent (as successor toPNC Bank, National Association in such capacity) (in such capacities, the “Prepetition Agent”)On the Effective Date, all outstanding obligations under the following credit agreement (the “DIP Credit Agreement”) other than contingent and/orunliquidated obligations were paid in cash in full, all commitments under the DIP Credit Agreement and the related transaction documents referred to thereinas the “Loan Documents” were terminated, all liens on property of the Debtors arising out of or related to the DIP Facility terminated and the LoanDocuments were cancelled except with respect to (a) contingent and and/or unliquidated obligations under the Loan Documents which survive the EffectiveDate and continue to be governed by the Loan Documents and (b) the relationships among the DIP Agent (as defined below) and the lenders under the DIPCredit Agreement, as applicable, including but not limited to, those provisions relating to the rights of theF- 18Table of ContentsDIP Agent and the lenders to expense reimbursement, indemnification and other similar amounts, certain reinstatement obligations set forth in the DIP CreditAgreement and any provisions that may survive termination or maturity of the credit facility governed by the DIP Credit Agreement in accordance with theterms thereof:•Superpriority Secured Debtor-In-Possession Credit Agreement, dated as of January 21, 2016 (as amended by the Waiver and Consent andAmendment No. 1, dated as of March 4, 2016, Amendment No. 2, dated as of March 28, 2016, Amendment No. 3, dated as of April 26, 2016,Amendment No. 4, dated as of June 10, 2016, Amendment No. 5, dated as of June 23, 2016, Amendment No. 6, dated as of July 20, 2016, andAmendment No. 7, dated as of September 28, 2016) among Arch Coal, Inc., as borrower, certain subsidiaries of Arch Coal, Inc., as guarantors, thelenders from time to time party there and Wilmington Trust, National Association, in its capacity as administrative agent and as collateral agent (insuch capacities, the “DIP Agent”).Equity SecuritiesUnder the Plan, 24,589,834 shares of Class A Common Stock and 410,166 shares of Class B Common Stock, par value $.01 per share, (“Class B CommonStock” and together with Class A Common Stock, “Common Stock”) were distributed to the secured lenders and to certain holders of general unsecuredclaims under the Plan on the Effective Date. In addition, on the Effective Date, Arch Coal issued Warrants to purchase up to an aggregate of 1,914,856 sharesof 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 thesecured 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 andsale of securities under a plan ofreorganization 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 planof 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.Reorganization ValueFresh start accounting provides, among other things, for a determination of the value to be assigned to the equity of the emerging company as of a dateselected for financial reporting purposes. In conjunction with the bankruptcy proceedings, a third party financial advisor provided an enterprise value of theCompany of approximately $650 million to $950 million. The final equity value of $687.5 million was based upon the approximate high end of theenterprise value established by the third party valuation plus excess cash of $64 million less the fair value of debt related to the New First Lien Debt Facilityof $326.5 million. The high end of the enterprise value assumed a minimum cash balance at emergence of $250 million.The enterprise value of the Company was estimated using various valuation methods including: (i) comparable public company analysis, (ii) discountedcash flow analysis (“DCF”) and (iii) sum-of-the-parts analysis. The comparable public company analysis is based on the enterprise value of selected publiclytraded companies that have operating and financial characteristics comparable in certain respects to the Company, for example, operational requirements andrisk and profitability characteristics. Selected companies are comprised of coal mining companies with primary operations in the United States. Under thismethodology, certain financial multiples and ratios that measure financial performance and value are calculated for each selected company and then appliedto the Company’s financials to imply an enterprise value for the Company.The DCF analysis is a forward-looking enterprise valuation methodology that estimates the value of an assets or business by calculating the presentvalue of expected future cash flows by that asset or business. The basis of the DCF analysis was the Company’s prepared projections which included a varietyof estimates and assumptions, such as pricing and demand for coal. The Company’s pricing was based on its view of the market taking into account thirdparty forward pricing curves adjusted for the quality of products sold by the Company. While the Company considers such estimates and assumptionsreasonable, they are inherently subject to significant business, economic and competitive uncertainties, many of which are beyond the Company’s controland, therefore, may not be realized. Changes in these estimates and assumptions may have a significantF- 19Table of Contentseffect on the determination of the Company’s enterprise value. The assumptions used in the calculations for the DCF analysis included projected revenue,cost and cash flows for the years ending December 31, 2016 through each respective mine life and represented the Company’s best estimates at the time theanalysis was prepared. The DCF analysis was completed using discount rates at a range of estimated weighted average costs of capital ranging from 13.25%to 15.25% . The DCF analysis involves complex considerations and judgments concerning appropriate discount rates. Due to the unobservable inputs to thevaluation, the fair value would be considered Level 3 in the fair value hierarchy.The sum-of-the-parts analysis is a more detailed market multiples approach the values each part of a company’s business separately based upon theenterprise values of selected publicly traded companies that have operating and financial characteristics comparable in certain respects to each part of thereorganized Company. Under this methodology, certain financial multiples and ratios that measure financial performance and value are calculated for eachselected comparable company and then applied to the relevant segment of the Company’s financials to imply an enterprise value for the Company.Accounting Impact of EmergenceUpon emergence in accordance with ASC 852, the Company applied fresh start accounting to its consolidated financial statements as of October 1, 2016because (i) the reorganization value of the assets of the emerging entity immediately before the date of confirmation was less than the total of all postpetitionliabilities and allowed claims and (ii) the holders of the existing voting shares immediately before confirmation received less than 50 percent of the votingshares of the emerging entity. Upon adoption of fresh start accounting, the Company became a new entity for financial reporting purposes reflecting theSuccessor capital structure. As such, a new accounting basis in the identifiable assets and liabilities assumed was established with no retained earnings oraccumulated other comprehensive income (loss) (“OCI”).The following balance sheet illustrates the impacts of the implementation of the Plan and the application of fresh start accounting, which results in theopening balance sheet of the Successor company.F- 20Table of ContentsAs of October 1, 2016 (In thousands)Predecessor (a) Effect of Plan (b) Fresh StartAdjustments (c) SuccessorAssets Current assets Cash and cash equivalents$400,205 $(199,718)(d)$— $200,487Short term investments111,451 — — 111,451Restricted cash81,563 — — 81,563Trade accounts receivable165,522 — — 165,522Other receivables17,227 — 779(j)18,006Inventories159,410 — (21,078)(k)138,332Prepaid royalties4,805 — — 4,805Deferred income taxes— — — —Coal derivative assets2,180 — — 2,180Other current assets36,960 6,367 53,851(l)97,178Total current assets979,323 (193,351) 33,552 819,524 Property, plant and equipment, net3,434,941 — (2,363,829)(m)1,071,112Other assets Prepaid royalties20,997 — (20,997)(n)—Equity investments164,232 — (61,606)(o)102,626Other noncurrent assets58,569 34,495(e)37,503(p)130,567Total other assets243,798 34,495 (45,100) 233,193Total assets$4,658,062 $(158,856) $(2,375,377) $2,123,829 Liabilities and Stockholders’ Equity (Deficit) Liabilities not subject to compromise Accounts payable$74,595 $— $(250)(q)$74,345Accrued expenses and other current liabilities225,739 (36,331)(f)26,644(r)216,052Current maturities of debt3,397 3,265(g)— 6,662Total current liabilities303,731 (33,066) 26,394 297,059Long-term debt30,037 323,235(g)— 353,272Asset retirement obligations394,699 — (60,570)(s)334,129Accrued pension benefits23,716 — 24,565(t)48,281Accrued other postretirement benefits87,123 — 24,836(t)111,959Accrued workers’ compensation119,828 — 74,520(u)194,348Deferred income taxes— — — —Other noncurrent liabilities96,410 — 888(v)97,298Total liabilities not subject to compromise1,055,544 290,169 90,633 1,436,346 Liabilities subject to compromise5,278,612 (5,278,612)(h)— — Total liabilities6,334,156 (4,988,443) 90,633 1,436,346 Stockholders’ equity (deficit) Common stock, predecessor2,145 (2,145)(i)— —Common stock, successor— 250(b)— 250Paid-in capital, predecessor3,056,307 (3,056,307)(i)— —Paid-in capital, successor— 687,233(b)— 687,233Treasury stock, at cost(53,863) 53,863(i)— —Accumulated earnings (deficit)(4,678,977) 7,146,693(i)(2,467,716) —Accumulated other comprehensive income (loss)(1,706) — 1,706 —Total stockholders’ equity (deficit)(1,676,094) 4,829,587 (2,466,010) 687,483Total liabilities and stockholders’ equity (deficit)$4,658,062 $(158,856) $(2,375,377) $2,123,829F- 21Table of Contents(a)Represents the Predecessor consolidated balance sheet as of October 1, 2016.(b)Represents amounts recorded for the implementation of the Plan on the Effective Date. This includes the settlement of liabilities subject tocompromise through a combination of cash payments, the issuance of new common stock and warrants and the issuance of new debt. The followingis the calculation of the total pre-tax gain on the settlement of the liabilities subject to compromise: In thousandsLiabilities subject to compromise $5,278,612Less amounts issued to settle claims: Common stock (at par) Successor (250)Warrants Successor (14,822)Paid-in capital Successor (672,411)Issuance of Term Loan Successor (326,500)Cash payment to settle claims and professional fees (122,525) Total pre-tax gain on plan effects $4,142,104(c)Represents the fresh start accounting adjustments required to record the assets and liabilities of the Company at fair value.(d)The following table reflects the use of cash at emergence: In thousandsPayment to secured lenders $43,496Payments to unsecured creditors 42,399Final adequate protection payment 36,331Collateral requirements 31,665Professional fees 31,630Other 14,197 Total cash outflow at emergence $199,718(e)Represents amounts paid for required collateral deposits.(f)Represents the final adequate protection payments made to the secured lenders.(g)Represents the fair value of the $326.5 million new term loan of which $3.3 million is shown within current maturities of debt.(h)Liabilities subject to compromise include unsecured or under-secured liabilities incurred prior to the Chapter 11 filing; and consists of thefollowing:Previously Reported Balance Sheet Line In thousandsDebt $5,026,806Accrued expenses and other current liabilities 136,295Accounts payable 106,297Other noncurrent liabilities 9,214 Total liabilities subject to compromise $5,278,612 F- 22Table of Contents(i)Reflects the impacts of the reorganization adjustments: In thousandsTotal pre-tax gain on settlement of claims $4,142,104Cancellation of predecessor common stock 2,145Cancellation of predecessor paid-in capital 3,056,307Cancellation of predecessor treasury stock (53,863) Net impact on accumulated earnings (deficit) $7,146,693(j)Represents adjustments to record other receivables at fair value which includes an $0.8 million short-term receivable related to insurance coveragefor self-insured workers’ compensation obligations. (k)Represents the following fair value adjustments: a $7.3 million increase related to coal inventory which was fair valued at estimated selling pricesless the sum of selling costs, shipping costs and a reasonable profit allowance for the selling effort offset by a $28.4 million reduction in criticalspare parts inventory. During fresh start accounting, the Company changed its accounting policy with respect to critical spare parts with long leadtimes; previously these items were valued within inventory, but prospectively, these items will be capitalized within property, plant and equipmentwhen purchased and depreciated over the life of the related equipment.(l)Represents the short-term portion of above market coal sales contracts of $71.1 million offset by $11.3 million in reductions related to prepaidbalances. The fair value of sales contracts was estimated using a discounted cash flow model and will be amortized into earnings as the coal isshipped throughout the term of the associated contracts.(m)Represents a $2.4 billion reduction in property, plant and equipment to estimated fair value as discussed below: PredecessorFresh StartAdjustmentsSuccessor(in thousands) Net Coal Properties$2,358,779$(1,971,314)$387,465Net Plant & Equipment812,888(405,259)407,629Net Deferred Charges263,27412,744276,018 $3,434,941$(2,363,829)$1,071,112The fair value of coal properties was established at $387.5 million utilizing a discounted cash flow model and the market approach. The marketapproach was used to provide a starting value of the coal mineral reserves without consideration for economic obsolescence. The DCF model wasbased on assumptions market participants would use in the pricing of these assets as well as projections of revenues and expenditures that would beincurred to mine or maintain these coal reserves through the life of mine. The basis of the DCF analysis was the Company’s prepared projectionswhich included a variety of estimates and assumptions, such as pricing and demand for coal. The Company’s pricing was based on its view of themarket taking into account third party forward pricing curves adjusted for the quality of products sold by the Company.The fair value of plant and equipment was set at $407.6 million utilizing both market and cost approaches. The market approach was used toestimate the value of assets where detailed information for the asset was available and an active market was identified with a sufficient number ofsales of comparable property that could be independently verified through reliable sources. The cost approach was utilized where there werelimitations in the secondary equipment market to derive values from. The first step in the cost approach is the estimation of the cost required toreplace the asset via construction or purchasing a new asset with similar utility adjusting for depreciation due to physical deterioration, functionalobsolescence due to technology changes and economic obsolescence due to external factors such as regulatory changes. Useful lives were assignedto all assets based on remaining future economic benefit of each asset.F- 23Table of ContentsThe fair value of deferred charges represents the corresponding asset related to the asset retirement obligation discussed in item (q) below.(n)Represents a fair value adjustment to a long-term prepaid royalty balance that the Company has concluded should not be assigned value based onmarket conditions and after considering economic obsolescence.(o)Represents a fair value adjustment to the Company’s equity investments in Knight Hawk Holdings, LLC, a coal producer in the Illinois Basin; andDominion Terminal Associates which operates a ground storage-to-vessel coal trans-loading facility in Newport News, Virginia. Equity investmentswere fair valued in a manner similar to the Company’s wholly-owned subsidiaries using a discounted cash flow model and comparable companyapproach. The discount rate selected was 14% and due to the unobservable nature of the inputs, the fair values are considered Level 3 in the fairvalue hierarchy.(p)Represents the long-term portion of above market coal sales contracts of $26.0 million and $18.6 million related to a long-term insurance receivablerelated to insurance coverage for self-insured workers’ compensation obligations partially offset by $13.2 million in reductions related to prepaidbalances. The fair value of sales contracts was estimated using a discounted cash flow model and will be amortized into earnings as the coal isshipped throughout the term of the associated contracts.(q)Represents a fair value adjustment to miscellaneous accounts payable.(r)Represents fair value adjustments for the following: a $27.8 million increase related to the short-term portion of below market sales contracts offsetby fair value adjustments to establish the current portion of pension, postretirement and workers’ compensation liabilities. The fair value of salescontracts was estimated using a discounted cash flow model and will be amortized into earnings as the coal is shipped throughout the term of theassociated contracts.(s)Represents the fair value adjustment related to the Company’s asset retirement obligations which was calculated using discounted cash flow modelsbased on current mine plans using the guidance provided within Accounting Standard Codification 410-20, “Asset Retirement Obligations.” Thediscount rates ranged from 7.06% to 9.08%.(t)Pension and postretirement benefits were fair valued based on plan assets and employee benefit obligations at October 1, 2016. The benefitobligations were computed using the applicable October 1, 2016 discount rates. In conjunction with fresh start accounting, the Company updated itsmortality rate table assumptions and corridor assumption.(u)Represents fair value adjustments for workers’ compensation benefits, including occupational disease benefits, that were actuarially determinedusing the guidance provided within Accounting Standard Codification 712, “Non-retirement Post-employment Benefits.” Upon emergence, theCompany’s accounting policy is to actuarially calculate this liability. Prior to emergence, the Company had accounted for its liability based onoutstanding reserves calculated per third party administrators.(v)Represents the following fair value adjustments: $3.9 million increase related to the long-term portion of below market sales contracts partiallyoffset by $3.1 million reduction in miscellaneous noncurrent liabilities. The fair value of sales contracts was estimated using a discounted cash flowmodel and will be amortized into earnings as the coal is shipped throughout the term of the associated contracts.F- 24Table of ContentsReorganization Items, NetIn accordance with ASC 852, the statement of operations shall portray the results of operations of the reporting entity while it is in Chapter 11. Revenues,expenses (including professional fees), realized gains and losses, and provisions for losses resulting from reorganization and restructuring of the businessshall be reported separately as reorganization items.The Company’s reorganization items, net for the respective periods are as follows: SuccessorPredecessor October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016Year EndedDecember 31, 2015Year EndedDecember 31, 2014(In thousands) Gain on settlement of claims (per above)$—$4,142,104$—$—Fresh start adjustments, net (per above)—(2,466,010)——Professional fees(759)(46,053)—— $(759)$1,630,041$—$—Professional fees directly related to the reorganization include fees associated with advisors to the Company, certain secured creditors and the Creditors’Committee. During the Successor period ended December 31, 2016, the Company continued to incur costs related to professional fees that are directlyattributable to the reorganization.Contractual Interest Expense During BankruptcyUpon the filing of bankruptcy, the Company discontinued recording interest expense on unsecured debt that was classified as a liability subject tocompromise. Actual interest expense recorded on the Predecessor debt subsequent to the Petition Date was $135.9 million for the period January 1 throughOctober 1, 2016; contractual interest during this time was $300.9 million.F- 25Table of Contents4. Accumulated Other Comprehensive Income (Loss)The following items are included in accumulated other comprehensive income (loss): Pension, Postretirement Accumulated and Other Post- Other Derivative Employment Available-for- Comprehensive Instruments Benefits Sale Securities Income (Loss) (In thousands)Predecessor Company January 1, 2015$2,550 $2,860 $(2,169) $3,241Unrealized gains (losses)3,903 (8,723) (3,333) (8,153)Amounts reclassified from accumulated other comprehensive income(loss)(6,128) 5,142 4,083 3,097December 31, 2015325 (721) (1,419) (1,815)Unrealized gains (losses)(138) — 701 563Amounts reclassified from accumulated other comprehensive income(loss)(316) (1,363) 1,225 (454)Fresh start accounting adjustment129 2,084 (507) 1,706October 1, 2016$— $— $— $—Successor Company Unrealized gains— 24,067 387 24,454Amounts reclassified from accumulated other comprehensive income(loss)— — — —December 31, 2016$— $24,067 $387 $24,454The unrealized gain in the successor period is the result of changes in the discount rates used to calculate our pension, postretirement health andoccupational disease obligations.F- 26Table of ContentsThe following amounts were reclassified out of accumulated other comprehensive income (loss) during the respective periods:Details about accumulatedother comprehensive income components SuccessorPredecessor Line Item in the Consolidated Statement of Operations October 2throughDecember 31,2016January 1throughOctober 1,2016 Year EndedDecember 31,2015 (in thousands)(in thousands) Derivative instruments $—$397 $9,575 Revenues —(81) (3,447) Provision for (benefit from) income taxes $—$316 $6,128 Net of tax Pension, postretirement and other post-employment benefits Amortization of prior service credits 1 $—$7,854 $8,335 Amortization of net actuarial gains(losses) 1 —(6,010) (16,369) —1,844 (8,034) Total before tax —(481) 2,892 Provision for (benefit from) income taxes $—$1,363 $(5,142) Net of tax Available-for-sale securities 2 $—$(2,263) $(6,391) Interest and investment income —1,038 2,308 Provision for (benefit from) income taxes $—$(1,225) $(4,083) Net of tax1 Production-related benefits and workers’ compensation costs are included in costs to produce coal.2 The gains and losses on sales of available-for-sale-securities are determined on a specific identification basis.F- 27Table of Contents5. Impairment Charges and Mine Closure CostsThe following table summarizes the amounts reflected on the line “Asset impairment and mine closure costs” in the consolidated statements ofoperations: SuccessorPredecessorDescriptionOctober 2 ThroughDecember 31, 2016January 1 ThroughOctober 1, 2016 Year Ended December31, 2015 Year EndedDecember 31, 2014 (In thousands)Coal lands and mineral rights$—$74,144 $2,210,488 $—Plant and equipment—— 199,107 1,512Deferred development—— 159,474 —Prepaid royalties—3,406 41,990 15,356Equity investments—40,920 21,325 —Inventories—— 66 —Other—10,797 (4,147) 7,245Total$—$129,267 $2,628,303 $24,113January 1 Through October 1, 2016 Impairment ChargesDuring the period January 1 through October 1, 2016, the Company recorded the following to “Asset impairment and mine closure costs” in theConsolidated Statements of Operations: $74.1 million recorded in the first quarter related to the impairment of coal reserves and surface land in Kentuckythat are being leased to a mining company that idled its mining operations; $3.4 million recorded in the first quarter related to the impairment on the portionof an advance royalty balance on a reserve base mined at the Company’s Mountain Laurel operation that will not be recouped; $2.9 million recorded in thefirst quarter related to an other-than-temporary-impairment charge on an available-for-sale security; a $38.0 million impairment recorded in the secondquarter related to the Company’s equity investment in a brownfield bulk commodity terminal on the Columbia River in Longview, Washington as theCompany relinquished its ownership rights in exchange for future throughput rights; $7.2 million of severance expense related to headcount reductionsduring the first half of the year; a $3.6 million curtailment charge related to the Company’s pension, postretirement health and black lung actuarial liabilitiesdue to headcount reductions in the first half of the year.2015 Impairment ChargesIn 2015, as a result of the continued deterioration in thermal and metallurgical coal markets and projections for a muted pricing recovery, certain of theCompany’s mine complexes have incurred and are expected to continue to incur operating losses. The Company determined that the further weakening of thepricing environment in the last half of the year and the projected operating losses represented indicators of impairment with respect to certain of its long-lived assets or assets groups. Using current pricing expectations which reflected marketplace participant assumptions, life of mine cash flows were used todetermine if the undiscounted cash flows exceeded the current asset values for certain operating complexes in the Company’s Appalachia segment. Formultiple operating complexes, the undiscounted cash flows did not exceed the carrying value of the long-lived assets. Discounted cash flows were utilized toreduce the carrying value of those assets to fair value. The discount rate used reflected the then current financial difficulties present in the commodities sectorin general and coal mining specifically; the perceived risk of financing coal mining in light of industry defaults; and the lack of an active market for buyingor selling coal mining assets. Additionally, the Company determined that the then current market conditions represented an indicator of impairment forcertain undeveloped coal properties that were acquired in times of significantly higher coal prices. The then current prices and the significant capital outlaythat would have been required to develop these reserves indicated that the carrying value was not recoverable. As a result the Company recorded a $2.6billion asset impairment charge in the last two quarters of 2015 of which $2.1 billion was recorded during the third quarter and the remaining $0.5 billion wasrecorded in the fourth quarter. Of the total charge. $2.2 billion was recorded to the Company’s Appalachia segment, with the remaining $0.4 billion recordedto the Company’s Other operating segment. There is no fair value remaining related to the impaired assets.During the second quarter of 2015, the Company recorded $19.1 million to “Asset impairment and mine closure costs” in the Consolidated Statements ofOperations. An impairment charge of $12.2 million related to the portion of an advance royaltyF- 28Table of Contentsbalance on a reserve base mined at the Company’s Mountain Laurel, Spruce and Briar Branch operations that was determined would not be recouped basedon estimates of sales volume and pricing through the March 2017 recoupment period. Additionally, the Company recorded a $5.6 million impairment chargerelated to the closure of a higher-cost mining complex serving the metallurgical coal markets.2014 Impairment ChargesDuring the Company’s annual budgeting process for 2015 (performed in the fall of 2014), a review of forecasted revenues indicated that the remainingbalance of advance royalty payments made on a reserve base supplying the Company’s Mountain Laurel, Spruce Mine and Briar Branch operations wouldnot be recoupable against future royalties payments. Under the lease, any unrecouped advance payment balance at March 31, 2017 will be forfeited by theCompany. Based on estimates of sales volumes and pricing through the end of the recoupment period, an impairment charge was recorded during the fourthquarter of 2014 for $15.4 million of the remaining $48.0 million balance that was determined would not be recouped.In response to weak metallurgical coal markets the Company idled a higher-cost mining complex in the third quarter of 2014 in order to concentrateon metallurgical coal production from its lowest-cost and highest-margin operations. Closure charges of $5.1 million were recognized during the third quarterof 2014 relating to the idling.6. Losses from disposed operations resulting from Patriot Coal bankruptcyOn December 31, 2005, Arch entered into a purchase and sale agreement with Magnum to sell certain operations. On July 23, 2008, Patriot acquiredMagnum. On May 12, 2015, Patriot and certain of its wholly owned subsidiaries (“Debtors”), including Magnum, filed voluntary petitions for reorganizationunder Chapter 11 of the U.S. Code in the U.S. Bankruptcy Court for the Eastern District of Virginia. Subsequently, on October 28, 2015, Patriot’s Plan ofReorganization was approved, including an authorization to reject their collective bargaining agreements and modify certain union-related retiree benefits.As a result of the Plan of Reorganization, the Company became statutorily responsible for retiree medical benefits pursuant to Section 9711 of the CoalIndustry Retiree Health Benefit Act of 1992 for certain retirees of Magnum who retired prior to October 1, 1994. In addition, the Company has providedsurety bonds to Patriot related to permits that were sold to an affiliate of Virginia Conservation Legacy Fund, Inc. (“VCLF”). Should VCLF not performrequired reclamation, the Company would incur losses under the bonds and related indemnity agreements. The Company recognized $116.3 million in lossesin 2015 related to the previously disposed operations as a result of the Patriot Coal bankruptcy.On November 22, 2016, Arch entered into a”Collateral Use Agreement” which caused the replacement, substitution and discharge of reclamation suretybonds related to the former Magnum properties placed by Arch in exchange for a collateral release of $20 million held by the bonding company to VCLF.7. Inventories Inventories consist of the following: SuccessorPredecessor December 31, 2016December 31, 2015(In thousands) Coal $37,268$85,043Repair parts and supplies 76,194111,677 $113,462$196,720 The repair parts and supplies are stated net of an allowance for slow-moving and obsolete inventories of $0.0 million at December 31, 2016 and $6.0million at December 31, 2015. F- 29Table of Contents8. Investments in Available-for-Sale SecuritiesThe Company has invested primarily in highly liquid investment-grade corporate bonds. These investments are held in the custody of a major financialinstitution. These securities, along with the Company’s investments in marketable equity securities, are classified as available-for-sale securities and,accordingly, the unrealized gains and losses are recorded through other comprehensive income.The Company’s investments in available-for-sale marketable securities are as follows: Successor December 31, 2016 Balance Sheet Gross Gross Classification Unrealized Unrealized Fair Short-Term Other Cost Basis Gains Losses Value Investments Assets (In thousands)Available-for-sale: Corporate notes and bonds$88,161 $— $(89) $88,072 $88,072 $—Equity securities1,749 388 — 2,137 — 2,137Total Investments$89,910 $388 $(89) $90,209 $88,072 $2,137 Predecessor December 31, 2015 Balance Sheet Gross Gross Classification Unrealized Unrealized Fair Short-Term Other Cost Basis Gains Losses Value Investments Assets (In thousands)Available-for-sale: U.S. government and agency securities$10,007 $— $(12) $9,995 $9,995 $—Corporate notes and bonds190,496 — (299) 190,197 190,197 —Equity securities3,938 668 (2,888) 1,718 — 1,718Total Investments$204,441 $668 $(3,199) $201,910 $200,192 $1,718The aggregate fair value of investments with unrealized losses that had been owned for less than a year was $47.6 million and $184.6 million atDecember 31, 2016 and 2015, respectively. The aggregate fair value of investments with unrealized losses that have been owned for over a year was $40.4million and $15.8 million at December 31, 2016 and 2015, respectively.The debt securities outstanding at December 31, 2016 have maturity dates ranging from the first quarter of 2017through the fourth quarter of 2017. The Company classifies its investments as current based on the nature of the investments and their availability to providecash for use in current operations, if needed.F- 30Table of Contents9. Equity Method Investments and Membership Interests in Joint Ventures The Company accounts for its investments and membership interests in joint ventures under the equity method of accounting if the Company has theability to exercise significant influence, but not control, over the entity. Equity method investments are reviewed for impairment whenever events or changesin circumstances indicate that the carrying amount of the investments may not be recoverable.Below are the equity method investments reflected in the consolidated balance sheets: (In thousands) Knight Hawk DTA Millennium Tongue River Other TotalPredecessor Company January 1, 2014 $152,806 $14,137 $35,894 $18,419 $200 $221,456Advances to (distributions from) affiliates, net (12,603) 3,774 6,742 2,541 3,600 4,054Equity in comprehensive income (loss) 18,274 (4,173) (2,413) (220) (1,136) 10,332December 31, 2014 158,477 13,738 40,223 20,740 2,664 235,842Advances to (distributions from) affiliates, net (29,862) 3,207 7,052 913 330 (18,360)Equity in comprehensive income (loss) 22,977 (3,706) (9,686) (328) (1,278) 7,979Impairment of equity investment — — — (21,325) (21,325)Sale of equity investment — — — — (2,259) (2,259)December 31, 2015 151,592 13,239 37,589 — (543) 201,877Advances to (distributions from) affiliates, net (8,374) 1,474 1,966 — — (4,934)Equity in comprehensive income (loss) 9,033 (2,095) (1,530) — (94) 5,314Impairment of equity investment — — (38,025) — — (38,025)Fresh start accounting adjustment (58,251) (4,018) — — 662 (61,607)October 1, 2016 $94,000 $8,600 $— $— $25 $102,625Successor Company Advances to (distributions from) affiliates, net (9,076) 822 — — — (8,254)Equity in comprehensive income (loss) 2,569 (841) — — (25) 1,703 December 31, 2016 $87,493 $8,581 $— $— $— $96,074 The Company holds a 49% equity interest in Knight Hawk Holdings, LLC (“Knight Hawk”), a coal producer in the Illinois Basin.The Company holds a general partnership interest of 21.875% in Dominion Terminal Associates (“DTA”), which is accounted for under the equitymethod. DTA operates a ground storage-to-vessel coal transloading facility in Newport News, Virginia for use by the partners. Under the terms of athroughput and handling agreement with DTA, each partner is charged its share of cash operating and debt-service costs in exchange for the right to use thefacility’s loading capacity and is required to make periodic cash advances to DTA to fund such costs.The Company previously held a 38% ownership interest in Millennium Bulk Terminals-Longview, LLC (“Millennium”), the owner of a brownfield bulkcommodity terminal on the Columbia River near Longview, Washington. Millennium continues to work on obtaining the required approvals and necessarypermits to complete dredging and other upgrades to ship coal, alumina and cementitious material from the terminal. During the second quarter of 2016, theCompany recorded an impairment charge of $38.0 million representing the entire value of its equity investment as the Company relinquished its ownershiprights in exchange for future throughput rights through the facility when completed.The Company holds a 35% membership interest in the Tongue River Holding Company, LLC (“Tongue River”) joint venture. Tongue River willdevelop and construct a railway line near Miles City, Montana and the Company’s Otter Creek reserves. The Company had the right, upon the receipt ofpermits and approval for construction or under other prescribed circumstances, to require the other investors to purchase all of the Company’s units in theventure at an amount equal to the capital contributions made by the Company at that time, less any distributions received. During the third quarter of 2015,the Company recorded an impairment charge of $21.3 million representing the entire value of the Company’s investment in the project; the impairmentcharge is included on the line “Asset impairment and mine closure costs.”The Company is not required to make any future contingent payments related to development financing for any of its equity investees.F- 31Table of Contents10. Sales ContractsThe sales contracts reflected in the consolidated balance sheets are as follows: Successor Predecessor December 31, 2016 December 31, 2015 Assets Liabilities Net Total Assets Liabilities Net Total (In thousands) (In thousands) Original fair value$97,196 $31,742 $131,299 $166,697 Accumulated amortization(25,625) (24,829) (130,839) (151,354) Total$71,571 $6,913 $64,658 $460 $15,343 $(14,883)Balance Sheet classification: Other current$59,702 $5,114 $460 $3,852 Other noncurrent$11,869 $1,799 $— $11,491 The Company anticipates amortization of sales contracts, based upon expected shipments in the next five years, to be expense of approximately $54.3million in 2017, $10.7 million in 2018, $1.1 million in 2019, and income of $0.6 million in 2020 and $0.1 million in 2021.11. Derivatives Diesel fuel price risk management The Company is exposed to price risk with respect to diesel fuel purchased for use in its operations. The Company anticipates purchasing approximately45 to 50 million gallons of diesel fuel for use in its operations during 2017. To protect the Company’s cash flows from increases in the price of diesel fuel forits operations, the Company may use forward physical diesel purchase contracts and purchase out-of-the-money heating oil call options to protect againstsubstantial increases in pricing. At December 31, 2016, the Company had heating oil call options for approximately 30.7 million gallons at an average strikeprice of $1.72.Coal risk management positions The Company may sell or purchase forward contracts, swaps and options in the over-the-counter coal market in order to manage its exposure to coalprices. The Company has exposure to the risk of fluctuating coal prices related to forecasted sales or purchases of coal or to the risk of changes in the fairvalue of a fixed price physical sales contract. Certain derivative contracts may be designated as hedges of these risks. At December 31, 2016, the Company held derivatives for risk management purposes that are expected to settle in the following years: (Tons in thousands) 2017 2018 TotalCoal sales 540 — 540Coal purchases 480 — 480Coal trading positions The Company may sell or purchase forward contracts, swaps and options in the over-the-counter coal market for trading purposes. The Company isexposed to the risk of changes in coal prices on the value of its coal trading portfolio. The unrecognized gains of $0.2 million in the trading portfolio areexpected to be realized in 2017.F- 32Table of ContentsTabular derivatives disclosures The Company has master netting agreements with all of its counterparties which allow for the settlement of contracts in an asset position with contracts ina liability position in the event of default or termination. Such netting arrangements reduce the Company’s credit exposure related to these counterparties.For classification purposes, the Company records the net fair value of all the positions with a given counterparty as a net asset or liability in the consolidatedbalance sheets. The amounts shown in the table below represent the fair value position of individual contracts, and not the net position presented in theaccompanying consolidated balance sheets. The fair value and location of derivatives reflected in the accompanying consolidated balance sheets are as follows: Successor Predecessor December 31, 2016 December 31, 2015 Fair Value of Derivatives Asset Liability Asset Liability (In thousands) Derivative Derivative Derivative Derivative Derivatives Designated as HedgingInstruments Coal $— $(15) $4 $(20) Derivatives Not Designated as HedgingInstruments Heating oil -- diesel purchases 4,646 — 1,017 — Coal held for trading purposes,exchange traded swaps and futures 68,948 (68,740) 110,653 (104,814) Coal -- risk management 475 (580) 3,912 (1,947) Natural gas 86 (13) 494 (247) Total 74,155 (69,333) 116,076 (107,008) Total derivatives 74,155 (69,348) 116,080 (107,028) Effect of counterparty netting (69,247) 69,247 (107,028) 107,028 Net derivatives as classified in thebalance sheets $4,908 $(101) $4,807 $9,052 $— $9,052 SuccessorPredecessor December 31, 2016December 31, 2015Net derivatives as reflected on the balance sheets Heating oil Other current assets $4,646$1,017Coal Coal derivative assets 2628,035 Accrued expenses and othercurrent liabilities (101)— $4,807$9,052 The Company had a current asset for the right to reclaim cash collateral of $2.8 million and $1.7 million at December 31, 2016 and 2015, respectively.These amounts are not included with the derivatives presented in the table above and are included in “other current assets” in the accompanyingconsolidated balance sheets.F- 33Table of ContentsThe effects of derivatives on measures of financial performance are as follows: Derivatives used in Cash Flow Hedging Relationships (in thousands)For the noted periods, Gain (Loss) Recognized in Other Comprehensive Income(Effective Portion) SuccessorPredecessor October 2 throughDecember 31,2016January 1throughOctober 1, 2016 Year EndedDecember 31,2015 Year EndedDecember 31,2014Coal sales(1) $—$(672) $12,816 10,842Coal purchases(2) —536 (6,718) (5,097) $—$(136) $6,098 $5,745 Gains (Losses) Reclassified from Other Comprehensive Income intoIncome(Effective Portion) SuccessorPredecessor October 2 throughDecember 31,2016January 1throughOctober 1, 2016 Year EndedDecember 31,2015 Year EndedDecember 31,2014Coal sales $—$1,634 $18,635 $5,336Coal purchases —(1,237) (9,060) (2,693) $—$397 $9,575 $2,643 No ineffectiveness or amounts excluded from effectiveness testing relating to the Company’s cash flow hedging relationships were recognized in theresults of operations in the Successor period from October 2 through December 31, 2016, the Predecessor period from January 1 through October 1, 2016, andfor the Predecessor years ended December 31, 2015, and 2014. Derivatives Not Designated as Hedging Instruments (in thousands)For the noted periods, Gain (Loss) Recognized SuccessorPredecessor October 2throughDecember 31,2016January 1throughOctober 1, 2016 Year EndedDecember 31,2015 Year EndedDecember 31,2014Coal — unrealized(3) $(408)$(1,662) $(3,883) $430Coal — realized(4) $116$(476) $3,236 $5,956Heating oil — diesel purchases(4) $827$826 $(8,294) $(7,848)Heating oil — fuel surcharges(4) $—$— $— $(405)Natural gas $(91)$(463) $878 $—Foreign currency $(9)$(451) $(887) $—F- 34Table of ContentsLocation in statement of operations:(1) — Revenues(2) — Cost of sales(3) — Change in fair value of coal derivatives and coal trading activities, net(4) — Other operating income, netThe Company recognized net unrealized and realized losses of an immaterial amount for the period October 2 through December 31, 2016 and $0.9 millionfor the period January 1 through October 1, 2016; and net unrealized and realized gains of $5.7 million, and $3.2 million during the years endedDecember 31, 2015 and 2014, respectively, related to its trading portfolio, which are included in the caption “Change in fair value of coal derivatives andcoal trading activities, net” in the accompanying consolidated statements of operations, and are not included in the previous tables reflecting the effects ofderivatives on measures of financial performance. Based on fair values at December 31, 2016, amounts on derivative contracts designated as hedge instruments in cash flow hedges expected to bereclassified from other comprehensive income into earnings during the next twelve months are immaterial. 12. Accrued Expenses and Other Current LiabilitiesAccrued expenses and other current liabilities consist of the following: SuccessorPredecessor December 31, 2016December 31, 2015(In thousands) Payroll and employee benefits $58,468$58,423Taxes other than income taxes 92,733104,755Interest 8,032119,785Sales contracts 5,1143,852Workers’ compensation 15,18416,875Asset retirement obligations 19,51513,795Other 6,19411,965 $205,240$329,45013. Debt and Financing Arrangements SuccessorPredecessor December 31, 2016December 31, 2015(In thousands) Term loan due 2021 ($325.7 million face value) $325,684$—Term loan due 2018 ($1.9 billion and $1.93 billion face value, respectively) —1,875,4297.00% senior notes due 2019 at par —1,000,0008.00% senior secured notes due 2019 at par —350,0009.875% senior notes ($375.0 million face value) due 2019 —365,6007.25% senior notes due 2020 at par —500,0007.25% senior notes due 2021 at par —1,000,000Other 37,19547,134Debt issuance costs —(64,857) 362,8795,073,306Less current maturities of debt 11,0385,042,353Long-term debt $351,841$30,953F- 35Table of ContentsSuccessor Company DebtNew First Lien Debt FacilityBorrowings under the New First Lien Debt Facility bear interest at a per annum rate equal to, at the option of Arch Coal, either (i) a London interbankoffered rate plus an applicable margin of 9%, subject to a 1% LIBOR floor (the “LIBOR Rate”), or (ii) a base rate plus an applicable margin of 8%. Interestpayments will be payable in cash, unless Arch Coal’s liquidity (as defined therein) after giving effect to the applicable interest payment would not exceed$300 million, in which case interest may be payable in kind (any such interest that is paid in kind, the “PIK Interest”). The term loans provided under the NewFirst Lien Debt Facility (the “Term Loans”) are subject to quarterly principal amortization payments in an amount equal $816,250. To the extent any interestis paid as PIK Interest on any interest payment date, the amount of the Term Loans in respect of which such PIK Interest is payable will be deemed to haveaccrued additional interest over the preceding interest period at 1.00%, which additional interest will be capitalized and added to the principal amount ofoutstanding Term Loans. The New First Lien Debt Facility is guaranteed by all existing and future wholly owned domestic subsidiaries of Arch Coal(collectively, the “Subsidiary Guarantors” and, together with Arch Coal, the “Exit Loan Parties”), subject to customary exceptions, and is secured by firstpriority security interests on substantially all assets of the Exit Loan Parties, including 100% of the voting equity interests of directly owned domesticsubsidiaries and 65% of the voting equity interests of directly owned foreign subsidiaries, subject to customary exceptions. Arch Coal has the right to prepayTerm Loans at any time and from time to time in whole or in part without premium or penalty, upon written notice, except that any prepayment of TermLoans that bear interest at the LIBOR Rate other than at the end of the applicable interest periods therefor shall be made with reimbursement for any fundinglosses and redeployment costs of the Lenders resulting therefrom. The New First Lien Debt Facility is subject to certain usual and customary mandatoryprepayment events, including 100% of net cash proceeds of (i) debt issuances (other than debt permitted to be incurred under the terms of the New First LienDebt Facility) and (ii) non-ordinary course asset sales or dispositions, subject to customary thresholds, exceptions and reinvestment rights. The New FirstLien Debt Facility contains customary affirmative covenants and representations. The New First Lien Debt Facility also contains customary negativecovenants, which, among other things, and subject to certain exceptions, include restrictions on (i) indebtedness, (ii) liens and guaranties, (iii) liquidations,mergers, consolidations, acquisitions, (iv) disposition of assets or subsidiaries, (v) affiliate transactions, (vi) creation or ownership of certain subsidiaries,partnerships and joint ventures, (vii) continuation of or change in business, (viii) restricted payments, (ix) prepayment of subordinated indebtedness, (x)restrictions in agreements on dividends, intercompany loans and granting liens on the collateral, (xi) loans and investments, (xii) changes in organizationaldocuments, (xiii) transactions with respect to bonding subsidiaries and (xiv) hedging transactions. The New First Lien Debt Facility does not contain anyfinancial maintenance covenant. The New First Lien Debt Facility contains customary events of default, subject to customary thresholds and exceptions,including, among other things, (i) non-payment of principal and non-payment of interest and fees, (ii) a material inaccuracy of a representation or warranty atthe time made, (iii) a failure to comply with any covenant, subject to customary grace periods in the case of certain affirmative covenants, (iv) cross-events ofdefault to indebtedness of at least $35 million, (v) cross-events of default to surety, reclamation or similar bonds securing obligations with an aggregate faceamount of at least $50 million, (vi) uninsured judgments in excess of $35 million, (vii) any loan document shall cease to be a legal, valid and bindingagreement, (viii) uninsured losses or proceedings against assets with a value in excess of $35 million, (ix) ERISA events, (x) a change of control or (xi)bankruptcy or insolvency proceedings relating to Arch Coal or any material subsidiary of Arch Coal. The New First Lien Debt Facility will mature on the datethat is five years after the Effective Date.Securitization FacilityOn the Effective Date, Arch Coal extended and amended its existing $200 million trade accounts receivable securitization facility provided to ArchReceivable Company, LLC, a non-Debtor special-purpose entity that is a wholly owned subsidiary of Arch Coal (“Arch Receivable”) (the “ExtendedSecuritization Facility”), which continues to support the issuance of letters of credit and reinstates Arch Receivable’s ability to request cash advances, asexisted prior to the filing of the voluntary petitions for relief under the Bankruptcy Code. Pursuant to the Extended Securitization Facility, the Debtorsagreed to a revised schedule of fees payable to the administrator and the providers of the Extended Securitization Facility. The Extended SecuritizationFacility will terminate at the earliest of (i) three years from the Effective Date, (ii) if the Liquidity (defined in the ExtendedSecuritization Facility and consistent with the definition in the New First Lien Debt Facility) is less than $175 million for a period of 60 consecutive days,the date that is the 364th day after the first day of such 60 consecutive day period and (iii) the occurrence of certain predefined events substantiallyconsistent with the existing transaction documents. Under the Extended Securitization Facility, Arch Receivable and certain of the Reorganized Debtors (asdefined above) party to the Extended Securitization Facility have granted to the administrator of the Extended Securitization Facility a first priority securityinterest in eligible trade accounts receivable generated by such Debtors from the sale of coal and all proceeds thereof. As of December 31, 2016, letters ofcredit totaling $154.4 million were outstanding under the Extended Securitization Facility and theF- 36Table of Contentsborrowing base was $83.4 million. As a result, cash collateral of $71.0 million has been placed in the Extended Securitization Facility at December 31, 2016and there is no availability for borrowings.Predecessor Company DebtThe following debt instruments were fully discharged by the Bankruptcy Court:•7.00% Senior Notes due 2019;•7.25% Senior Notes due 2020;•7.25% Senior Notes due 2021;•9.875% Senior Notes due 2019;•8.00% Second Lien Notes due 2019;•Term loan due 2018;For additional information see Note 3, “Emergence from Bankruptcy and Fresh Start Accounting.”Debt MaturitiesThe contractual maturities of debt as of December 31, 2016 are as follows:Year (In thousands)2017 $11,0382018 10,3242019 11,4792020 11,7612021 317,987Thereafter 290 $362,879Financing CostsThe Company paid financing costs of $23.0 million during the period January 1 through October 1, 2016; and zero and $4.5 million during the yearsended December 31, 2015 and 2014, respectively, in conjunction with its financing activities.The Company incurred $2.2 million of legal fees and financial advisory fees associated with debt restructuring activities in during the period January 1through October 1, 2016. Additionally, the Company incurred $24.2 million of legal fees and financial advisory fees associated with debt restructuringactivities during 2015. During the year ended December 31, 2015, the Company wrote off $3.7 million of deferred financing costs related to the terminationof the revolver facility. All amounts have been reflected in the line, “Net loss resulting from early retirement and refinancing of debt” in the ConsolidatedStatement of Operations.F- 37Table of Contents14. TaxesUnder the Plan, the Company’s pre-petition equity, bank related debt and certain other obligations were cancelled and extinguished. Absent anexception, a debtor recognizes cancellation of debt income (CODI) upon discharge of its outstanding indebtedness for an amount of consideration that is lessthan its adjusted issue price. In accordance with Internal Revenue Code (IRC) Section 108, the Company excluded the amount of discharged indebtednessfrom taxable income since the IRC provides that a debtor in a bankruptcy case may exclude CODI from income but must reduce certain tax attributes by theamount of CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price ofany indebtedness discharged less than the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued, and (iii) the fair market valuethe fair market value of any other consideration, including equity, issued.CODI from the discharge of indebtedness was $3,353 million. As a result of the CODI and in accordance with IRC rules, the Company reduced its grossfederal net operating loss (NOL) carryovers $3,015 million, its alternative minimum tax (AMT) credits $92 million, its capital loss carryforwards $59.2million and the tax basis in certain assets $3.2 million. The Company was able to retain $931.1 million of gross federal NOLs, $22.8 million of AMT creditand $5.9 million of capital loss carryforwards following the bankruptcy.Due to changes in ownership that occurred in connection with the Company’s emergence from bankruptcy, there was a change in ownership for purposesof IRC Section 382. Section 382 provides a combined annual limitation with respect to the ability of a corporation to use its NOLs, AMT credits and capitalloss carryforwards generated before the ownership change against future taxable income. The Company’s annual limit under IRC section 382 is estimated tobe $29.8 million. The Company had a net unrealized built-in gain at the time of the ownership change, therefore, certain built-in gains recognized within fiveyears after the ownership change will increase the annual IRC section 382 limit for the five year recognition period beginning October 1, 2016 throughSeptember 30, 2021. There is significant uncertainty surrounding which assets with built-in gain will be realized within the five year period following theCompany’s emergence from bankruptcy and allow the Company to realize the incremental net operating losses and credit in excess of the base 382limitation. The Company is reflecting a deferred tax asset for the full amount of the net operating losses and credit carryforwards. If at some point in time itbecomes evident that some portion of the deferred tax assets will not be realizable, the deferred tax asset, and offsetting valuation allowance will be reduced.The Company is subject to U.S. federal income tax as well as income tax in multiple state jurisdictions. The tax years 2002 through 2016 remain open toexamination for U.S. federal income tax matters and 2004 through 2016 remain open to examination for various state income tax matters.Significant components of the provision for (benefit from) income taxes are as follows: SuccessorPredecessor October 2throughDecember 31,2016January 1through October1, 2016 Year EndedDecember 31,2015 Year EndedDecember 31,2014(In thousands) Current: Federal$—$— $— $—State(252)7 3 25Total current(252)7 3 25Deferred: Federal1,352(4,720) (329,393) 18,535State5687 (43,990) 7,074Total deferred1,408(4,633) (373,383) 25,609 $1,156$(4,626) $(373,380) $25,634F- 38Table of ContentsA reconciliation of the statutory federal income tax provision (benefit) at the statutory rate to the actual provision for (benefit from) income taxesfollows: SuccessorPredecessor October 2throughDecember 31,2016January 1through October1, 2016 Year EndedDecember 31,2015 Year EndedDecember 31,2014(In thousands) Income tax provision (benefit) at statutory rate$12,112$433,109 $(1,150,283) $(186,452)Percentage depletion allowance(4,292)(3,681) (19,035) (12,692)State taxes, net of effect of federal taxes633(46,122) (76,445) (3,903)Reversal of cancellation of indebtedness income—(1,493,162) — —Worthless stock deduction—(80,077) — —Change in valuation allowance(7,655)1,185,326 865,146 226,929Other, net358(19) 7,237 1,752 $1,156$(4,626) $(373,380) $25,634Significant components of the Company’s deferred tax assets and liabilities that result from carryforwards and temporary differences between thefinancial statement basis and tax basis of assets and liabilities are summarized as follows: SuccessorPredecessor December 31,2016December 31,2015(In thousands) Deferred tax assets: Net operating loss carryforwards$376,293$1,086,332Alternative minimum tax credit carryforwards22,798120,994Investment in tax partnerships & corporations604,914—Reclamation and mine closure—121,276Goodwill5,13538,671Workers’ compensation—42,835Share based compensation—22,612Sales contracts—17,466Retiree benefit plans4,01316,996Advance royalties—18,751Losses from disposed operations resulting from Patriot Coal bankruptcy—39,287Other, primarily accrued liabilities30,10345,303Gross deferred tax assets1,043,2561,570,523Valuation allowance(1,021,553)(1,135,399)Total deferred tax assets21,703435,124Deferred tax liabilities: Plant and equipment7,332389,169Deferred development—41,047Sales contracts12,658—Other1,6004,706Total deferred tax liabilities21,590434,922Net deferred (asset) liability(113)(202)F- 39Table of ContentsThe Company has gross federal net operating loss carryforwards for regular income tax purposes of $931.1 million at December 31, 2016 that will expirebetween 2022 and 2036. The Company has an alternative minimum tax credit carryforward of $22.8 million at December 31, 2016, which has no expirationdate and can be used to offset future regular tax in excess of the alternative minimum tax. The future annual usage of NOLs and AMT credit will be limitedunder IRC section 382.As part of our efforts to create operational efficiency leading up to and through the bankruptcy process, we have consolidated our mining operations andland management into a partnership structure to match our legal form with the Company’s streamlined operations during 2016. As such, deferred taxes relatedto those operations are now reported based upon the book and tax outside basis difference in the partnership interests as provided in ASC 740-30-25-7, whichresults in a different basis of presentation that was used in 2015 under our prior legal structure.As recent cumulative losses constitute significant negative evidence with regards to future taxable income, the Company has relied solely on theexpected reversal of taxable temporary differences to support the future realization of its deferred tax assets. The Company performs a detailed schedulingprocess of its net taxable temporary differences.At December 31, 2014, all deductible temporary differences were expected to be realized as there were sufficient deferred tax liabilities within the samejurisdiction and of the same character that are available to offset them. Valuation allowances were established for federal and state net operating losses andtax credits that were not offset by the reversal of other net taxable temporary differences before the expiration of the attribute.At December 31, 2015, additional losses were realized relating primarily to financial conditions and asset impairment charges. As a result, the expectedreversal of taxable temporary differences were not sufficient to support the future realization of the deferred tax assets and an additional $865.1 millionvaluation allowance was recorded. Net deferred tax assets of $1,135 million were completely offset by a valuation allowance.At December 31, 2016, additional tax losses were realized primarily as a result of the non-recognition of CODI under section 108 of the IRC by thePredecessor entity. As a result, the expected reversal of taxable temporary differences were not sufficient to support the future realization of the deferred taxassets and an additional $1,185 million valuation allowance was recorded to the provision. Offsetting this increase was a net reduction in the valuationallowance of $1,289 million which did not impact the provision. This reduction was primarily the result of a decrease in NOLs and AMT credits due to theIRC section 108 offset rules. Net deferred tax assets of $1,022 million are completely offset by a valuation allowance.A reconciliation of the beginning and ending amounts of gross unrecognized tax benefits follows: (In thousands)Balance atJanuary 1, 2014$31,789Additions based on tax positions related to the current year2,920Balance atDecember 31, 201434,709Additions based on tax positions related to the current year4,168Balance atDecember 31, 201538,877Additions for tax positions of prior years2,979Additions for tax positions related to the current year2,709Reductions as a result of bankruptcy(37,110)Balance atDecember 31, 2016$7,455If recognized, the entire amount of the gross unrecognized tax benefits at December 31, 2016 would affect the effective tax rate.As a result of the bankruptcy, federal and state governments are precluded from assessing additional tax in audits of tax periods ending prior tobankruptcy. As a result, the Company has released $37.1 million of gross unrecognized tax benefits for years 2015 and prior. These gross unrecognized taxbenefits are fully offset by a corresponding release in valuation allowance.The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. The Company had accrued interest andpenalties of $0.5 million and $1.7 million at December 31, 2016 and 2015, respectively. In the next 12 months, no gross unrecognized tax benefits areexpected to be reduced due to the expiration of the statute of limitations.F- 40Table of Contents15. Asset Retirement ObligationsThe Company’s asset retirement obligations arise from the Federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, whichrequire that mine property be restored in accordance with specified standards and an approved reclamation plan. The required reclamation activities to beperformed are outlined in the Company’s mining permits. These activities include reclaiming the pit and support acreage at surface mines, sealing portals atunderground mines, and reclaiming refuse areas and slurry ponds.The following table describes the changes to the Company’s asset retirement obligation liability: SuccessorPredecessor October 2throughDecember 31,2016January 1throughOctober 1, 2016Year EndedDecember 31,2015(In thousands) Balance at beginning of period (including current portion)$354,326$410,454$418,118Accretion expense7,63424,32133,680Obligations of divested operations—(14,702)(334)Adjustments to the liability from changes in estimates—3,003(28,570)Liabilities settled(5,218)(11,087)(12,440)Fresh start accounting adjustment—(57,663)—Balance at period end$356,742$354,326$410,454Current portion included in accrued expenses(19,515)(17,290)(13,795)Noncurrent liability$337,227$337,036$396,659As of December 31, 2016, the Company had $528.3 million in surety bonds outstanding and $21.3 million in letters of credit to secure reclamationbonding obligations. Additionally, the Company has posted $33.4 million in cash as collateral related to reclamation surety bonds; this amount is recordedwithin “Noncurrent assets” on the Consolidated Balance Sheet.F- 41Table of Contents16. Fair Value Measurements The hierarchy of fair value measurements assigns a level to fair value measurements based on the inputs used in the respective valuation techniques. Thelevels of the hierarchy, as defined below, give the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and thelowest priority to unobservable inputs. · Level 1 is defined as observable inputs such as quoted prices in active markets for identical assets. Level 1 assets include available-for-sale equitysecurities, U.S. Treasury securities, and coal swaps and futures that are submitted for clearing on the New York Mercantile Exchange. · Level 2 is defined as observable inputs other than Level 1 prices. These include quoted prices for similar assets or liabilities in an active market,quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable marketdata for substantially the full term of the assets or liabilities. The Company’s level 2 assets and liabilities include U.S. government agency securities and coalcommodity contracts with fair values derived from quoted prices in over-the-counter markets or from prices received from direct broker quotes. · Level 3 is defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.These include the Company’s commodity option contracts (coal and heating oil) valued using modeling techniques, such as Black-Scholes, that require theuse of inputs, particularly volatility, that are rarely observable. Changes in the unobservable inputs would not have had a significant impact on the reportedLevel 3 fair values at December 31, 2016 and 2015. The table below sets forth, by level, the Company’s financial assets and liabilities that are recorded at fair value in the accompanying consolidatedbalance sheet: Successor Fair Value at December 31, 2016 Total Level 1 Level 2 Level 3 (In thousands)Assets: Investments in marketable securities $90,209 $2,137 $88,072 $—Derivatives 4,908 262 — 4,646Total assets $95,117 $2,399 $88,072 $4,646Liabilities: Derivatives $101 $(8) $— $109 Predecessor Fair Value at December 31, 2015 Total Level 1 Level 2 Level 3 (In thousands)Assets: Investments in marketable securities $201,910 $11,713 $190,197 $—Derivatives 9,052 5,597 1,023 2,432Total assets $210,962 $17,310 $191,220 $2,432Liabilities: Derivatives $— $— $— $—The Company’s contracts with its counterparties allow for the settlement of contracts in an asset position with contracts in a liability position in the eventof default or termination. For classification purposes, the Company records the net fair value of all the positions with these counterparties as a net asset orliability. Each level in the table above displays the underlying contracts according to their classification in the accompanying consolidated balance sheet,based on this counterparty netting. F- 42Table of ContentsThe following table summarizes the change in the fair values of financial instruments categorized as level 3. SuccessorPredecessor October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016 Year Ended December31, 2015 (In thousands)(In thousands)Balance, beginning of period $3,842$2,432 $3,040Realized and unrealized losses recognized in earnings, net 926(1,686) (8,602)Included in other comprehensive income —— (1,341)Purchases 1,2255,021 13,541Issuances (34)(488) (4,046)Settlements (1,422)(1,437) (160)Ending balance $4,537$3,842 $2,432 Net unrealized gains of $0.4 million were recognized during the period October 2 through December 31, 2016 related to level 3 financial instrumentsheld on December 31, 2016. Cash and Cash EquivalentsAt December 31, 2016 and 2015, the carrying amounts of cash and cash equivalents approximate their fair value.Fair Value of Long-Term Debt At December 31, 2016 and 2015, the fair value of the Company’s debt, including amounts classified as current, was $362.9 million and $937.1 million,respectively. Fair values are based upon observed prices in an active market, when available, or from valuation models using market information, which fallinto Level 2 in the fair value hierarchy. 17. Capital StockSuccessor CompanyEquity SecuritiesUnder the Plan, 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 tothe secured lenders and to certain holders of general unsecured claims under the Plan on the Effective Date. The Class A Common Stock and Class BCommon stock are identical in all respects except that Class B Common Stock shall not be listed by the Company on any national securities exchangeregistered under Section 6 of the Securities Exchange Act of 1934, as amended. In addition, on the Effective Date, Arch Coal issued Warrants to purchase upto 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, onSection 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 saleof 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 underthe 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 BankruptcyCode 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 threeprincipal 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 planof 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.See Note 3, “Emergence from Bankruptcy and Fresh Start Accounting” for additional information.F- 43Table of ContentsOutstanding WarrantsAs of December 31, 2016, holders of warrants had exercised 2,871 of the warrants.As provided in ASC 825-20, “Financial Instruments,” the warrants are considered equity because they can only be physically settled in Company shares,can be settled in unregistered shares, the Company has adequate authorized shares to settle the outstanding warrants and each warrant is fixed in terms ofsettlement to one share of Company stock subject only to remote contingency adjustment factors designed to assure the relative value in terms of sharesremains fixed.Predecessor CompanyReverse Stock SplitOn August 4, 2015, the Company effected a 1-for-10 reverse stock split of our common stock. Each stockholder’s percentage ownership and proportionalvoting power remain unchanged as a result of the reverse stock split. All applicable share data, per share amounts and related information in the ConsolidatedFinancial Statements and notes thereto have been adjusted retroactively to give effect to the 1-for-10 reverse stock split.18. Stock-Based Compensation and Other Incentive PlansSuccessor CompanyUnder the Company’s 2016 Omnibus Incentive Plan (the “Incentive Plan”), 3.0 million shares of the Company’s common stock were reserved for awardsto officers and other selected key management employees of the Company. The Incentive Plan provides the Board of Directors with the flexibility to grantstock options, stock appreciation rights, restricted stock awards, restricted stock units, performance stock or units, phantom stock awards and rights to acquirestock through purchase under a stock purchase program (“Awards”). Awards the Board of Directors elects to pay out in cash do not impact the sharesauthorized in the Incentive Plan. Shares available for award under the plan were 2.6 million at December 31, 2016.Restricted Stock Unit AwardsThe Company may issue restricted stock and restricted stock units, which require no payment from the employee. Restricted stock cliff-vests at variousdates and restricted stock units either vest ratably over or vest at the end of the award’s stated vesting period. Compensation expense is based on the fairvalue on the grant date and is recorded ratably over the vesting period utilizing the straight-line recognition method. The employee receives cashcompensation equal to the amount of dividends that would have been paid on the underlying shares.Three restricted stock unit awards were granted in the Successor period: two time based awards vesting over one and three years: and one performancebased award vesting over a three year period. The time based awards’ grant date fair value was determined based on the stock price at the date of grant. Theperformance award’s grant date fair value was determined using a Monte Carlo simulation. A volatility of 58% was selected based on comparator companies,and the three year risk free rate was derived from yields on U.S. Government bonds. Information regarding the restricted stock units activity and weightedaverage grant-date fair value follows: Common SharesWeighted Average Grant-Date Fair Value(Shares in thousands) Outstanding at October 2, 2016——Granted384$72.00Forfeited——Canceled——Unvested outstanding at December 31, 2016384$72.00The Company recognized expense related to restricted stock units for the period October 2, 2016 through December 31, 2016 of $1.0 million.Long-Term Incentive CompensationThe Company has a long-term incentive program that allows for the award of performance units. The total number of units earned by a participant isbased on financial and operational performance measures, and may be paid out in cash or in shares of the Company’s common stock. The Companyrecognizes compensation expense over the three year term of the grant. TheF- 44Table of Contentsliabilities are remeasured quarterly. The Company recognized expense of $1.6 million for the period October 2 through December 31, 2016, $7.2 million forthe period January 1 through October 1, 2016, and $7.9 million and $10.1 million for the years ended December 31, 2015 and 2014, respectively. Theexpense is included primarily in “Selling, general and administrative expenses” in the accompanying consolidated statements of operations.As part of the plan of reorganization, the Company’s Executive Officers agreed to a $6.0 million reduction in scheduled compensation payouts in 2017.The long term incentive compensation liability was reduced $3.7 million as a fresh start accounting adjustment and is reflected in the Successor periodending December 31, 2016 balance. Amounts accrued and unpaid for all grants under the plan totaled $13.9 million and $17.8 million as of December 31,2016 and 2015, respectively.Predecessor CompanyOn the Effective Date, all shares of our old common stock, including any vested and unvested stock options, restricted stock and restricted stock unitswere canceled.Common StockStock options are granted at a strike price equal to the closing market price of the Company’s common stock on the date of grant and are generallysubject to vesting provisions of a least one year from the date of grant. Compensation expense related to stock options for the period January 1, 2016 throughOctober 1, 2016, and for the years ended 2015 and 2014 were $0.2 million, $1.4 million and $3.2 million, respectively. The majority of the cost relating tothe stock-based compensation plans is included in “Selling, general and administrative expenses” in the accompanying consolidated statements ofoperations.Restricted stock unitsThe company may issue restricted stock and restricted stock units, which require no payment from the employee. Restricted stock cliff-vests at variousdates and restricted stock units either vest ratably over or vest at the end of three years. Compensation expense is based on the fair value on the grant date andis recorded ratably over the vesting period. Compensation expense related to restricted stock and restricted stock units for the period January 1, 2016 throughOctober 1, 2016, and for the years ended 2015 and 2014 were $1.9 million, $5.9 million and $5.6 million, respectively. The majority of the cost relating tothe stock-based compensation plans is included in “Selling, general and administrative expenses” in the accompanying consolidated statements ofoperations.F- 45Table of Contents19. Workers’ Compensation Expense The Company is liable under the Federal Mine Safety and Health Act of 1969, as subsequently amended, to provide for pneumoconiosis (occupationaldisease) benefits to eligible employees, former employees and dependents. The Company currently provides for federal claims principally through a self-insurance program. The Company is also liable under various state workers’ compensation statutes for occupational disease benefits. The occupationaldisease benefit obligation represents the present value of the of the actuarially computed present and future liabilities for such benefits over the employees’applicable years of service.In addition, the Company is liable for workers’ compensation benefits for traumatic injuries which are calculated using actuarially-based loss rates, lossdevelopment factors and discounted based on a risk free rate of 1.74%. Traumatic workers’ compensation claims are insured with varyingretentions/deductibles, or through state-sponsored workers’ compensation programs.Workers’ compensation expense consists of the following components: SuccessorPredecessor October 2throughDecember 31,2016January 1throughOctober 1, 2016 Year EndedDecember 31,2015 Year EndedDecember 31,2014(In thousands) Self-insured occupational disease benefits: Service cost $1,583$3,465 $4,282 $1,734Interest cost 1,1263,184 3,944 2,914Net amortization —4,325 6,973 (216)Total occupational disease $2,709$10,974 $15,199 $4,432Traumatic injury claims and assessments 3,1626,628 16,781 19,924Total workers’ compensation expense $5,871$17,602 $31,980 $24,356The table below reconciles changes in the occupational disease liability for the respective period. SuccessorPredecessor(In thousands)October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016Year Ended December31, 2015Beginning of period$119,710$90,836$72,749Service cost1,5833,4654,282Interest cost1,1263,1843,944Curtailments—4,156 Actuarial (gain) loss(9,675)—14,284Benefit and administrative payments(1,585)(3,728)(4,423)Fresh start accounting adjustment—21,797— $111,159$119,710$90,836F- 46Table of ContentsThe following table provides the assumptions used to determine the projected occupational disease obligation: SuccessorPredecessor October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016 Year Ended December31, 2015(Percentages) Occupational Disease Benefit Discount rate4.313.80 4.76Cost escalation rateN/AN/A N/ASummarized below is information about the amounts recognized in the accompanying consolidated balance sheets for workers’ compensation benefits: SuccessorPredecessor Year EndedDecember 31,2016Year EndedDecember 31,2015(In thousands) Occupational disease costs$111,159$90,836Traumatic and other workers’ compensation claims88,59338,309Total obligations199,752129,145Less amount included in accrued expenses15,18416,875Noncurrent obligations$184,568$112,270As of December 31, 2016, the Company had $146.2 million in surety bonds and letters of credit outstanding to secure workers’ compensationobligations.The Company’s recorded liabilities include $19.4 million of obligations that are reimbursable under various insurance policies purchased by thecompany. These insurance receivables are recorded in the balance sheet line items “Other receivables” and “Other noncurrent assets” for $0.8 million and$18.6 million.F- 47Table of Contents20. Employee Benefit Plans Defined Benefit Pension and Other Postretirement Benefit PlansThe Company provides funded and unfunded non-contributory defined benefit pension plans covering certain of its salaried and hourly employees.Benefits are generally based on the employee’s age and compensation. The Company funds the plans in an amount not less than the minimum statutoryfunding requirements or more than the maximum amount that can be deducted for U.S. federal income tax purposes.The Company also currently provides certain postretirement medical and life insurance coverage for eligible employees. Generally, covered employeeswho terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The salariedemployee postretirement benefit plans are contributory, with retiree contributions adjusted annually, and contain other cost-sharing features such asdeductibles and coinsurance. The Company’s current funding policy is to fund the cost of all postretirement benefits as they are paid.The idling of the Cumberland River mining operations in Appalachia in the third quarter of 2014 reduced the estimated years of future service for theCRCC Scotia Employee Association Pension Plan. On January 1, 2015, the Company’s cash balance and excess plans were amended to freeze new servicecredits for any new or active employee. These two events triggered curtailment accounting, resulting in an immediate recognition of any unamortized gain orloss and the reduction in the projected benefit obligation which were recorded in the third and fourth quarter of 2014, respectively.Obligations and Funded Status.Summaries of the changes in the benefit obligations, plan assets and funded status of the plans are as follows:F- 48Table of Contents Pension Benefits Other Postretirement Benefits SuccessorPredecessor SuccessorPredecessor October 2throughDecember 31,2016January 1throughOctober 1,2016 Year EndedDecember 31,2015 October 2throughDecember 31,2016January 1throughOctober 1,2016 Year EndedDecember 31,2015(In thousands) CHANGE IN BENEFIT OBLIGATIONS Benefit obligations at beginning of period$341,427$301,292 $353,736 $120,311$103,460 $36,098Service cost—— 9 180393 866Interest cost2,7689,338 14,604 9783,223 1,904Re-entry of former Magnum employees—— — —— 85,843Settlements(135)— — —— —Curtailments—454 — —714 —Benefits paid(11,009)(8,699) (61,955) (1,962)(8,273) (3,646)Other-primarily actuarial gain(19,422)— (5,102) (7,640)— (17,605)Fresh start accounting adjustments—39,042 — —20,794 Benefit obligations at end of period$313,629$341,427 $301,292 $111,867$120,311 $103,460CHANGE IN PLAN ASSETS Value of plan assets at beginning of period$292,726$273,499 $336,709 $—$— $—Actual return on plan assets(7,899)27,811 (1,679) — —Employer contributions407115 424 1,9628,273 3,646Benefits paid(11,009)(8,699) (61,955) (1,962)(8,273) (3,646)Value of plan assets at end of period$274,225$292,726 $273,499 $—$— $—Accrued benefit cost$(39,404)$(48,701) $(27,793) $(111,867)$(120,311) $(103,460)ITEMS NOT YET RECOGNIZED AS A COMPONENT OF NETPERIODIC BENEFIT COST Prior service credit (cost)$—$— $— $—$— $26,944Accumulated gain (loss)6,751— (16,769) 7,640— 11,313 $6,751$— $(16,769) $7,640$— $38,257BALANCE SHEET AMOUNTS Current liability$(520)$(420) $(420) $(10,422)$(8,352) $(3,650)Noncurrent liability(38,884)(48,281) $(27,373) (101,445)(111,959) (99,810) $(39,404)$(48,701) $(27,793) $(111,867)$(120,311) $(103,460)Pension BenefitsThe accumulated benefit obligation for all pension plans was $313.6 million and $301.3 million at December 31, 2016 and 2015, respectively.Due to the Company adopting the corridor method of amortizing actuarial gains (losses) during fresh start accounting, it is anticipated there will be noamortization recorded into net periodic benefit cost during 2017.Other Postretirement BenefitsDue to the Company adopting the corridor method of amortizing actuarial gains (losses) during fresh start accounting, it is anticipated there will be noamortization recorded into net periodic benefit cost during 2017.F- 49Table of ContentsComponents of Net Periodic Benefit Cost. The following table details the components of pension and postretirement benefit costs (credits): Pension Benefits Other Postretirement BenefitsSuccessorPredecessor SuccessorPredecessor October 2throughDecember 31,2016January 1throughOctober 1,2016 Year EndedDecember 31,2015 Year EndedDecember 31,2014 October 2throughDecember 31,2016January 1throughOctober 1,2016 Year EndedDecember 31,2015 Year EndedDecember 31,2014(In thousands) Service cost$—$— $9 $21,478 $180$393 $866 $1,649Interest cost2,7689,338 14,604 17,070 9783,223 1,904 1,841Curtailments—454 — (25,368) —(970) — —Settlements(135)— 2,656 646 —— — —Expected return on plan assets(4,770)(13,623) (20,367) (23,756) —— — —Amortization of prior servicecredits—— — (257) —(7,854) (8,335) (10,003)Amortization of other actuariallosses (gains)—3,973 8,850 3,128 —(849) (2,109) (761)Net benefit cost (credit)$(2,137)$142 $5,752 $(7,059) $1,158$(6,057) $(7,674) $(7,274)The differences generated from changes in assumed discount rates and returns on plan assets are amortized into earnings over the remaining serviceattribution periods of the employees using the corridor method.Assumptions. The following table provides the weighted average assumptions used to determine the actuarial present value of projected benefitobligations for the respective periods. SuccessorPredecessor October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016 Year Ended December31, 2015(Percentages) Pension Benefits Discount rate3.953.39 4.59Rate of compensation increaseN/AN/A N/A Other Postretirement Benefits Discount rate3.933.37 4.57Rate of compensation increaseN/AN/A N/AF- 50Table of ContentsThe following table provides the weighted average assumptions used to determine net periodic benefit cost for the respective periods. SuccessorPredecessor October 2throughDecember 31,2016January 1throughOctober 1,2016 Year Ended December 31, 2015 Year Ended December31, 2014(Percentages) Pension Benefits Discount rate3.39/3.954.59/3.80 4.15/4.61/4.41/4.60 5.08/4.23/4.14Rate of compensation increaseN/AN/A N/A N/AExpected return on plan assets6.856.85 7.00 7.75 Other Postretirement Benefits Discount rate3.374.57/3.80 3.91 4.58Rate of compensation increaseN/AN/A N/A N/AExpected return on plan assetsN/AN/A N/A N/AThe discount rates used in 2016, 2015 and 2014 were reevaluated during the year for settlements and curtailments. The obligations are remeasured at anupdated discount rate that impacts the benefit cost recognized subsequent to the remeasurement.The Company establishes the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns onthe underlying mix of invested assets. The Company utilizes modern portfolio theory modeling techniques in the development of its return assumptions. Thistechnique projects rates of return that can be generated through various asset allocations that lie within the risk tolerance set forth by members of theCompany’s pension committee (the “Pension Committee”). The risk assessment provides a link between a pension plan’s risk capacity, management’swillingness to accept investment risk and the asset allocation process, which ultimately leads to the return generated by the invested assets.The health care cost trend rate assumed for 2017 is 6.7% and is expected to reach an ultimate trend rate of 4.5% by 2038. A one-percentage-pointincrease in the health care cost trend rate would increase the postretirement benefit obligation at December 31, 2016 by $11.1 million and the net periodicpostretirement benefit cost for the year ended December 31, 2016 by $0.1 million.Plan AssetsThe Pension Committee is responsible for overseeing the investment of pension plan assets. The Pension Committee is responsible for determining andmonitoring appropriate asset allocations and for selecting or replacing investment managers, trustees and custodians. The pension plan’s current investmenttargets are 55% equity and 45% fixed income securities. The Pension Committee reviews the actual asset allocation in light of these targets on a periodicbasis and rebalances among investments as necessary. The Pension Committee evaluates the performance of investment managers as compared to theperformance of specified benchmarks and peers and monitors the investment managers to ensure adherence to their stated investment style and to the plan’sinvestment guidelines.F- 51Table of ContentsThe Company’s pension plan assets at December 31, 2016 and 2015, respectively, are categorized below according to the fair value hierarchy as definedin Note 16, “Fair Value Measurements”: Total Level 1 Level 2 Level 3 2016 2015 2016 2015 2016 2015 2016 2015 (In thousands)Equity Securities:(A) U.S. small-cap$13,520 $11,640 $13,520 $11,640 $— $— $— $—U.S. mid-cap29,687 28,524 9,422 10,979 20,265 17,545 — —U.S. large-cap70,226 67,244 34,107 33,249 36,119 33,995 — —Non-U.S.18,937 18,785 — — 18,937 18,785 — —Fixed income securities: —U.S. government securities(B)26,519 18,844 19,973 18,183 6,546 661 — —Non-U.S. government securities(C)1,567 766 — — 1,567 766 — —U.S. government asset and mortgagebacked securities(D)1,074 1,056 — — 1,074 1,056 — —Corporate fixed income(E)58,191 39,939 — — 58,191 39,939 — —State and local governmentsecurities(F)6,406 5,725 — — 6,406 5,725 — —Other investments(I)26,151 19,869 — — 6,910 1,234 19,241 18,635Total$252,278 $212,392 $77,022 $74,051 $156,015 $119,706 $19,241 $18,635Other fixed income(G)35,519 Short-term investments(H)8,598 Other liabilities(J)(22,170) $274,225 (A) Equity securities includes investments in 1) common stock, 2) preferred stock and 3) mutual funds. Investments in common and preferred stocks arevalued using quoted market prices multiplied by the number of shares owned. Investments in mutual funds are valued at the net asset value per sharemultiplied by the number of shares held as of the measurement date and are traded on listed exchanges.(B) U.S. government securities includes agency and treasury debt. These investments are valued using dealer quotes in an active market.(C) Non-U.S. government securities includes debt securities issued by foreign governments and are valued utilizing a price spread basis valuation techniquewith observable sources from investment dealers and research vendors.(D) U.S. government asset and mortgage backed securities includes government-backed mortgage funds which are valued utilizing an income approach thatincludes various valuation techniques and sources such as discounted cash flows models, benchmark yields and securities, reported trades, issuer tradesand/or other applicable data.(E) Corporate fixed income is primarily comprised of corporate bonds and certain corporate asset-backed securities that are denominated in the U.S. dollar andare investment-grade securities. These investments are valued using dealer quotes.(F) State and local government securities include different U.S. state and local municipal bonds and asset backed securities, these investments are valuedutilizing a market approach that includes various valuation techniques and sources such as value generation models, broker quotes, benchmark yields andsecurities, reported trades, issuer trades and/or other applicable data.(G) Other fixed income investments are actively managed fixed income vehicles that are valued at the net asset value per share multiplied by the number ofshares held as of the measurement date.(H) Short-term investments include governmental agency funds, government repurchase agreements, commingled funds, and pooled funds and mutual funds.Governmental agency funds are valued utilizing an option adjusted spread valuation technique and sources such as interest rate generation processes,benchmark yields and broker quotes. Investments in governmental repurchase agreements, commingled funds and pooled funds and mutual funds are valuedat the net asset value per share multiplied by the number of shares held as of the measurement date.F- 52Table of Contents(I) Other investments include cash, forward contracts, derivative instruments, credit default swaps, interest rate swaps and mutual funds. Investments in interestrate swaps are valued utilizing a market approach that includes various valuation techniques and sources such as value generation models, broker quotes inactive and non-active markets, benchmark yields and securities, reported trades, issuer trades and/or other applicable data. Forward contracts and derivativeinstruments are valued at their exchange listed price or broker quote in an active market. The mutual funds are valued at the net asset value per sharemultiplied by the number of shares held as of the measurement date and are traded on listed exchanges.(J)Net payable amount due for pending securities purchased and sold due to broker/dealer.Cash Flows. The Company expects to make contributions of $0.4 million to the pension plans in 2017, which is impacted by the Moving Ahead forProgress in the 21st Century Act (MAP-21). MAP-21 does not reduce the Company’s obligations under the plan, but redistributes the timing of requiredpayments by providing near term funding relief for sponsors under the Pension Protection Act.The following represents expected future benefit payments from the plan, which reflect expected future service, as appropriate: Other Pension Postretirement Benefits Benefits (In thousands)2017$19,403 $12,300201821,117 12,716201920,763 13,033202021,209 13,408202121,917 13,763Next 5 years102,619 64,920 $207,028 $130,140Other PlansThe Company sponsors savings plans which were established to assist eligible employees in providing for their future retirement needs. The Company’sexpense, representing its contributions to the plans, was $3.5 million for the period October 2 through December 31, 2016, $13.8 million for the periodJanuary 1 through October 1, 2016 and $20.5 million and $22.9 million for the years ended December 31, 2015 and 2014, respectively.F- 53Table of Contents21. Earnings (Loss) Per Common Share The Company computes basic net income per share using the weighted average number of common shares outstanding during the period. Diluted netincome per share is computed using the weighted average number of common shares and the effect of potentially dilutive securities outstanding during theperiod. Potentially dilutive securities may consist of warrants, restricted stock units or other contingently issuable shares. The dilutive effect of outstandingwarrants, restricted stock units and other contingently issuable shares is reflected in diluted earnings per shares by application of the treasury stock method.The following table provides the basis for basic and diluted EPS by reconciling the numerators and denominators of the computations: SuccessorPredecessor October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016Year EndedDecember 31, 2015Year EndedDecember 31, 2014(In Thousands) Weighted average shares outstanding: Basic weighted average shares outstanding25,00221,29321,28521,222Effect of dilutive securities46720—— Diluted weighted average shares outstanding25,46921,31321,28521,222F- 54Table of Contents22. LeasesThe Company leases equipment, land and various other properties under non-cancelable long-term leases, expiring at various dates. Certain leasescontain options that would allow the Company to extend the lease or purchase the leased asset at the end of the base lease term.In addition, the Company enters into various non-cancelable royalty lease agreements under which future minimum payments are due.Minimum payments due in future years under these agreements in effect at December 31, 2016 are as follows: Operating Leases Royalties (In thousands)2017$14,653 $3,994201814,485 6,02120195,321 6,10520202,260 7,14720211,985 7,809Thereafter10,317 46,499 $49,021 $77,575Obligations for the future minimum payments under capital leases for equipment totaling $0.0 million and $40.0. million at December 31, 2016 and2015, respectively, are included in other long term debt obligations in Note 13, “Debt and Financing Arrangements”.Rental expense, including amounts related to these operating leases and other shorter-term arrangements, amounted to $5.0 million for the periodOctober 2 through December 31, 2016, $19.4 million for the period January 1 through October 1, 2016, $28.4 million in 2015 and $42.1 million in 2014.Royalties are paid to lessors either as a fixed price per ton or as a percentage of the gross selling price of the mined coal. Royalties under the majority ofthe Company’s significant leases are paid on the percentage of gross selling price basis. Royalty expense, including production royalties, was $45.3 millionfor the period October 2 through December 31, 2016, $116.4 million for the period January 1 through October 1, 2016, $227.7 million in 2015 and $242.5million in 2014.As of December 31, 2016, certain of the Company’s lease obligations were secured by outstanding surety bonds totaling $32.6 million.23. Risk ConcentrationsCredit Risk and Major CustomersThe Company has a formal written credit policy that establishes procedures to determine creditworthiness and credit limits for trade customers andcounterparties in the over-the-counter coal market. Generally, credit is extended based on an evaluation of the customer’s financial condition. Collateral isnot generally required, unless credit cannot be established. Credit losses are provided for in the financial statements and historically have been minimal.The Company markets its steam coal principally to domestic and foreign electric utilities and its metallurgical coal to domestic and foreign steelproducers. As of December 31, 2016 and 2015, accounts receivable from electric utilities of $96.0 million and $83.8 million, respectively, represented 52%and 72% of total trade receivables at each date. As of December 31, 2016 and 2015, accounts receivable from sales of metallurgical-quality coal of $88.0million and $32.8 million, respectively, represented 48% and 28% of total trade receivables at each date.The Company uses shipping destination as the basis for attributing revenue to individual countries. Because title may transfer on brokered transactionsat a point that does not reflect the end usage point, they are reflected as exports, and attributed to an end delivery point if that knowledge is known to theCompany. The Company’s foreign revenues by geographicalF- 55Table of Contentslocation are as follows: SuccessorPredecessor October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016 Year EndedDecember 31, 2015 Year EndedDecember 31, 2014 (In thousands)(In thousands)Europe$61,408$113,888 $170,314 $277,565Asia55,63468,536 96,523 156,057North America43,83156,594 40,315 78,445Central and South America13,22441,861 55,323 20,496Brokered Sales—— 32,848 79,354Total$174,097$280,879 $395,323 $611,917The Company is committed under long-term contracts to supply steam coal that meets certain quality requirements at specified prices. These prices aregenerally adjusted based on market indices. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of thecustomer based on their requirements. The Company sold approximately 93.9 million tons of coal in 2016. Approximately 76% of this tonnage (representingapproximately 62% of the Company’s revenues) was sold under long-term contracts (contracts having a term of greater than one year). Long-term contractsrange in remaining life from one to five years.Third-party sources of coalThe Company uses independent contractors to mine coal at certain mining complexes. The Company also purchases coal from third parties that it sells tocustomers. Factors beyond the Company’s control could affect the availability of coal produced for or purchased by the Company. Disruptions in thequantities of coal produced for or purchased by the Company could impair its ability to fill customer orders or require it to purchase coal from other sourcesat prevailing market prices in order to satisfy those orders.TransportationThe Company depends upon barge, rail, truck and belt transportation systems to deliver coal to its customers. Disruption of these transportation servicesdue to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair the Company’s ability tosupply coal to its customers In the past, disruptions in rail service have resulted in missed shipments and production interruptions.24. Commitments and ContingenciesThe Company accrues for cost related to contingencies when a loss is probable and the amount is reasonably determinable. Disclosure of contingencies isincluded in the financial statements when it is at least reasonably possible that a material loss or an additional material loss in excess of amounts alreadyaccrued may be incurred. The Company is a party to numerous claims and lawsuits with respect to various matters. As of December 31, 2016 and 2015, the Company had accrued$2.2 million and $2.8 million, respectively, for all legal matters, including $2.2 million and $2.8 million, respectively, classified as current. The ultimateresolution of any such legal matter could result in outcomes which may be materially different from amounts the Company has accrued for such matters. The Company has unconditional purchase obligations relating to purchases of coal, materials and supplies and capital commitments, other than reserveacquisitions, and is also a party to transportation capacity commitments. The future commitments under these agreements total $48.0 million in 2017, and isimmaterial thereafter. The Company recognized expense relating to transportation capacity agreements of $1.6 million during the period January 1 throughOctober 1, 2016; and $52.9 million and $36.5 million during the years ended December 31, 2015 and 2014, respectively.F- 56Table of Contents25. Segment Information The Company’s reportable business segments are based on two distinct lines of business, metallurgical and thermal, and may include a number of minecomplexes. The Company manages its coal sales by market, not by individual mining complex. Geology, coal transportation routes to customers, andregulatory environments also have a significant impact on the Company’s marketing and operations management. Mining operations are evaluated based onAdjusted EBITDAR, per-ton cash operating costs (defined as including all mining costs except depreciation, depletion, amortization, accretion on assetretirements 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 fromAdjusted EBITDAR are significant in understanding and assessing our financial condition. Therefore, Adjusted EBITDAR should not be considered inisolation, nor as an alternative to net income, income from operations, cash flows from operations or as a measure of our profitability, liquidity or performanceunder generally accepted accounting principles. The Company used Adjusted EBITDAR to measure the operating performance of its segments and allocateresources to the segments. Furthermore, analogous measures are used by industry analysts to evaluate the Company’s operating performance. Investors shouldbe aware that the Company’s presentation of Adjusted EBITDAR may not be comparable to similarly titled measures used by other companies. Uponemergence from bankruptcy, the Company updated its reportable segments to reflect the manner in which its Chief Operating Decision Maker (CODM) viewsthe reorganized Company’s business for purposes of reviewing performance and allocating resources. The Company now reports is results of operationsprimarily through the following reportable segments: Powder River Basin (PRB) segment containing the Company’s primary thermal operations inWyoming; the Metallurgical (MET) segment, containing the Company’s metallurgical operations in West Virginia, Kentucky, and Virginia, and the OtherThermal segment containing the Company’s supplementary thermal operations in Colorado, Illinois, and the Coal Mac thermal operation in West Virginia.Periods presented in this note have been recast for comparability. Operating segment results for the Successor period October 2 through December 31, 2016 and the Predecessor periods January 1 through October 1, 2016and the years ended December 31, 2015 and 2014 are presented below. The Company measures its segments based on “adjusted earnings before interest,taxes, depreciation, depletion, amortization, accretion on asset retirements obligations, and reorganization items, net (Adjusted EBITDAR).” AdjustedEBITDAR does not reflect mine closure or impairment costs, since those are not reflected in the operating income reviewed by management. See Note 5,“Impairment Charges and Mine Closure Costs” for discussion of these costs. The Corporate, Other and Eliminations grouping includes these charges, as wellas the change in fair value of coal derivatives and coal trading activities, net; corporate overhead; land management activities; other support functions; andthe elimination of intercompany transactions. The asset amounts below represent an allocation of assets consistent with the basis used for the Company’s incentive compensation plans. The amounts inCorporate, Other and Eliminations represent primarily corporate assets (cash, receivables, investments, plant, property and equipment) as well as unassignedcoal reserves, above-market sales contracts and other unassigned assets.F- 57Table of Contents(In thousands) PRB MET Other Thermal Corporate,Other andEliminations ConsolidatedSuccessor PeriodOctober 2 through December 31,2016 Revenues $275,703 $200,377 $97,382 $2,226 $575,688Adjusted EBITDAR 55,765 30,819 31,159 (23,246) 94,497Depreciation, depletion and amortization 9,949 18,287 3,911 457 32,604Accretion on asset retirement obligation 5,049 528 540 1,517 7,634Total assets 446,775 576,793 129,602 983,427 2,136,597Capital expenditures 934 13,329 684 267 15,214 Predecessor PeriodJanuary 1 through October 1, 2016 Revenues $726,747 $437,069 $213,052 $21,841 $1,398,709Adjusted EBITDAR 113,185 11,851 31,448 (69,181) 87,303Depreciation, depletion and amortization 100,151 55,311 32,310 3,809 191,581Accretion on asset retirement obligation 16,940 1,765 1,988 3,628 24,321Total assets 456,711 619,154 131,173 916,791 2,123,829Capital expenditures 612 17,296 3,895 60,631 82,434 Predecessor YearEndedDecember 31, 2015 Revenues $1,448,440 $637,941 $428,809 $58,070 $2,573,260Adjusted EBITDAR 281,039 70,450 42,734 (110,426) 283,797Depreciation, depletion and amortization 176,257 133,463 47,786 21,839 379,345Accretion on asset retirement obligation 22,156 2,267 2,658 6,599 33,680Total assets 1,648,916 772,439 366,610 2,253,9165,041,881Capital expenditures 21,228 24,787 11,277 61,732 119,024 Predecessor YearEndedDecember 31, 2014 Revenues $1,490,377 $743,973 $535,783 $166,986 $2,937,119Adjusted EBITDAR 218,731 112,719 78,238 (96,636) 313,052Depreciation, depletion and amortization 168,522 163,644 52,991 33,591 418,748Accretion on asset retirement obligation 20,748 2,089 2,412 7,660 32,909Total assets 1,762,326 2,339,739 406,296 3,838,001 8,346,362Capital expenditures 21,399 46,771 14,843 64,273 147,286F- 58Table of ContentsA reconciliation of segment Adjusted EBITDAR to consolidated income (loss) from continuing operations before income taxes follows: SuccessorPredecessor(In thousands) October 2throughDecember 31,2016January 1 throughOctober 1, 2016 Year EndedDecember 31, 2015 Year EndedDecember 31,2014 Adjusted EBITDAR $94,497$87,303 $283,797 $313,052Depreciation, depletion and amortization (32,604)(191,581) (379,345) (418,748)Accretion on asset retirement obligations (7,634)(24,321) (33,680) (32,909)Amortization of sales contracts, net (796)728 8,811 13,187Asset impairment and mine closure costs —(129,267) (2,628,303) (24,113)Losses from disposed operations resulting from Patriot Coal bankruptcy —— (116,343) —Interest expense, net (10,754)(133,235) (393,549) (383,188)Net loss resulting from early retirement of debt and debt restructuring —(2,213) (27,910) —Reorganization items, net (759)1,630,041 — —Fresh start coal inventory fair value adjustment (7,345)— — —Income (loss) before income taxes $34,605$1,237,455 $(3,286,522) $(532,719)F- 59Table of Contents26. Quarterly Selected Financial Data (unaudited) PredecessorSuccessorYear EndedDecember 31, 2016March 31 June 30 September 30 October 1October 2throughDecember 31,2016 (a) (b) (a) (b) (b) (b) (In thousands, except per share data) Revenues$428,106 $420,298 $550,305 —575,688Gross profit (loss)$(53,325) $(56,469) $31,042 —64,458Asset impairment and mine closure costs$85,520 $43,701 $46 ——Income (loss) from operations$(158,412) $(110,521) $11,795 $—$46,118Reorganization items, net$(3,875) $(21,271) $(20,904) $1,676,091$(759)Net income (loss)$(206,702) $(175,887) $(51,421) $1,676,091$33,449Diluted earnings (loss) per common share$(9.71) $(8.26) $(2.41) $78.66$1.31 PredecessorYear EndedDecember 31, 2015March 31 June 30 September 30 December 31 (a) (a) (a) (In thousands, except per share data) Revenues$677,005 $644,462 $688,544 $563,249Gross profit (loss)$14,256 $(16,507) $47,275 $(44,964)Asset impairment and mine closure costs$— $19,146 $2,120,292 $488,865Loss from operations$(19,712) $(69,546) $(2,236,772) $(539,033)Net loss$(113,195) $(168,103) $(1,999,476) $(632,368)Diluted loss per common share$(5.32) $(7.93) $(93.91) $(29.70)(a) Challenging coal markets resulted in impairment charges relating to mining and other operations, investments in equity method subsidiaries and prepaidmining royalties in 2016 and 2015. See further discussion in Note 5, “Impairment Charges and Mine Closure Costs “ and Note 9, “Equity MethodInvestments and Membership Interests in Joint Ventures.”(b) The Company filed for bankruptcy on January 11, 2016 and subsequently emerged on October 5, 2016. See further discussion in Note 3, “Emergencefrom Bankruptcy and Fresh Start Accounting.”F- 60Table of ContentsSchedule IIArch Coal, Inc. and SubsidiariesValuation and Qualifying Accounts Additions (Reductions) Balance at Charged to Charged to Balance at Beginning of Costs and Other End of Year Expenses Accounts Deductions (a) Year (In thousands)Successor October 2 through December 31, 2016 Reserves deducted from asset accounts: Accounts receivable and other receivables$— $— $— $— $—Current assets — supplies and inventory— — — — —Deferred income taxes1,033,982 (7,655) — — 1,026,327Predecessor January 1 through October 1, 2016 Reserves deducted from asset accounts: Accounts receivable and other receivables$7,842 $— $— $7,842 $—Current assets — supplies and inventory5,991 844 (5,060)(c) 1,775 —Deferred income taxes1,135,399 (101,417) — 1,033,982Year ended December 31, 2015 Reserves deducted from asset accounts: Accounts receivable and other receivables$159 $7,683 $— $— $7,842Current assets — supplies and inventory6,625 431 — 1,065 5,991Deferred income taxes270,251 865,148 — — 1,135,399Year ended December 31, 2014 Reserves deducted from asset accounts: Accounts receivable and other receivables$775 $— $— $616 $159Current assets — supplies and inventory8,446 580 (76)(b) 2,325 $6,625Deferred income taxes43,322 226,929 — — $270,251(a) Reserves utilized, unless otherwise indicated.(b) Disposition of subsidiaries(c) Fresh start accounting adjustmentF- 61Exhibit 21.1Subsidiaries of the CompanyThe following is a complete list of the direct and indirect subsidiaries of Arch Coal, Inc., a Delaware corporation, including their respective states ofincorporation or organization, as of February 24, 2017:Arch Coal Asia-Pacific PTE. LTD. (Singapore) 100%Arch of Australia PTY LTD (Australia) 100%Arch Coal Australia PTY LTD (Australia) 100%Arch Coal Australia Holdings PTY LTD (Australia) 100%Arch Coal Europe Limited (Europe) 100%Arch Coal Operations LLC (Delaware) 42.2%Coal-Mac LLC (Kentucky) 100%Catenary Coal Holdings LLC (Delaware) 100%Cumberland River Coal LLC (Delaware) 100%Lone Mountain Processing LLC (Delaware) 100%Powell Mountain Energy, LLC (Delaware) 100%ICG East Kentucky, LLC (Delaware) 100%ICG Eastern, LLC (Delaware) 100%ICG Illinois, LLC (Delaware) 100%ICG Tygart Valley, LLC (Delaware) 100%Shelby Run Mining Company, LLC (Delaware) 100%Hunter Ridge LLC (Delaware) 100%Bronco Mining Company LLC (West Virginia) 100%Hawthorne Coal Company LLC (West Virginia) 100%Hunter Ridge Coal LLC (Delaware) 100%Juliana Mining Company LLC (West Virginia) 100%King Knob Coal Co. LLC (West Virginia) 100%Marine Coal Sales LLC (Delaware) 100%Melrose Coal Company LLC (West Virginia) 100%Patriot Mining Company LLC (West Virginia) 100%Upshur Property LLC (Delaware) 100%Vindex Energy LLC (West Virginia) 100%White Wolf Energy LLC (Virginia) 100%Wolf Run Mining Company LLC (West Virginia) 100%The Sycamore Group, LLC (West Virginia) 50%Mingo Logan Coal LLC (Delaware) 100%Simba Group LLC (Delaware) 100%Arch Coal Sales Company, Inc. (Delaware) 100%Arch Energy Resources, LLC (Delaware) 100%Arch Land LLC (Delaware) 57.6%Ark Land LLC (Delaware) 100%Western Energy Resources LLC (Delaware) 100%Ark Land KH LLC (Delaware) 100%Ark Land LT LLC (Delaware) 100%Ark Land WR LLC (Delaware) 100%Allegheny Land LLC (Delaware) 100%Arch Coal West, LLC (Delaware) 100%Arch Reclamation Services LLC (Delaware) 100%CoalQuest Development LLC (Delaware) 100%Energy Development LLC (Iowa) 100%Exhibit 21.1ICG Eastern Land, LLC (Delaware) 100%ICG Natural Resources, LLC (Delaware) 100%Mountain Gem Land LLC (West Virginia) 100%Mountain Mining LLC (Delaware) 100%Mountaineer Land LLC (Delaware) 100%Otter Creek Coal, LLC (Delaware) 100%Arch Receivable Company, LLC (Delaware) 100%Arch Western Acquisition Corporation (Delaware) 100%Arch Western Acquisition, LLC (Delaware) 100%Arch Western Resources, LLC (Delaware) 99.5%Arch of Wyoming, LLC (Delaware) 100%Arch Western Bituminous Group, LLC (Delaware) 100%Mountain Coal Company, L.L.C. (Delaware) 100%Thunder Basin Coal Company, L.L.C. (Delaware) 100%Triton Coal Company, LLC (Delaware) 100%ACI Terminal, LLC (Delaware) 100%Ashland Terminal, Inc. (Delaware) 100%International Energy Group, LLC (Delaware) 100%ICG, LLC (Delaware) 100%Arch Coal Group, LLC (Delaware) 100%Arch Coal Operations LLC (Delaware) 56.8%Arch Land LLC (Delaware) 1.4%ICG Beckley, LLC (Delaware) 100%Arch Land LLC (Delaware) 41%Hunter Ridge Holdings, Inc. (Delaware) 100%Arch Coal Operations LLC (Delaware) 1%Meadow Coal Holdings, LLC (Delaware) 100%Prairie Holdings, Inc. (Delaware) 100%Prairie Coal Company, LLC (Delaware) 100%Exhibit 23.1Consent of Independent Registered Public Accounting FirmWe consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-214373) pertaining to the Arch Coal,Inc. Omnibus Incentive Plan of our report dated February 24, 2017, with respect to the consolidated financial statements and scheduleof Arch Coal, Inc. and subsidiaries included in this Annual Report (Form 10-K) for the period from October 2, 2016 throughDecember 31, 2016 (Successor) and the period from January 1, 2016 through October 1, 2016 (Predecessor)./s/ Ernst & Young, LLPSt. Louis, MissouriFebruary 24, 2017Exhibit 23.2CONSENT OF WEIR INTERNATIONAL, INC. We hereby consent to the reference to Weir International, Inc. in the Annual Report on Form 10-K of Arch Coal, Inc. for the year ended December 31, 2016. We further wish to advise that Weir International, Inc. was not employed on a contingent basis and that at the time of preparation of our report, as well as atpresent, neither Weir International, Inc. nor any of its employees had, or now has, a substantial interest in Arch Coal, Inc. or any of its affiliates or subsidiaries.Respectfully submitted, By: /s/ Dennis N. KosticName: Dennis N. KosticTitle: President & CEODate: February 24, 2017Exhibit 24.1Power Of AttorneyKNOW ALL PERSONS BY THESE PRESENTS: That each of the undersigned directors and/or officers of Arch Coal, Inc., a Delaware corporation (“ArchCoal”), hereby constitutes and appoints John W. Eaves, John T. Drexler and Robert G. Jones, and each of them, his or her true and lawful attorneys-in-fact andagents, with full power to act without the other, to sign Arch Coal’s Annual Report on Form 10‑K for the year ended December 31, 2016, to be filed with theSecurities and Exchange Commission under the provisions of the Securities Exchange Act of 1934, as amended; to file such report and the exhibits theretoand any and all other documents in connection therewith, including without limitation, amendments thereto, with the Securities and Exchange Commission;and to do and perform any and all other acts and things requisite and necessary to be done in connection with the foregoing as fully as he or she might orcould do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtuehereof.DATED: February 24, 2017/s/ James N. Chapman James N. ChapmanChairman/s/ Patrick J. Bartels, Jr. Patrick J. Bartels, Jr.Director/s/ John W. Eaves John W. EavesDirector/s/ Sherman Edmiston, III Sherman Edmiston, IIIDirector/s/ Patrick A. Kriegshauser Patrick A. KriegshauserDirector/s/ Richard A. Navarre Richard A. NavarreDirector/s/ Scott D. Vogel Scott D. VogelDirectorExhibit 31.1Certification I, John W. Eaves, certify that: 1.I have reviewed this annual report on Form 10-K of Arch Coal, Inc.;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, inlight of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition,results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange ActRules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that materialinformation relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period inwhich this report is being prepared;(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to providereasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generallyaccepted accounting principles;(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of thedisclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (theregistrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controlover financial reporting; and 5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’sauditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (e)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adverselyaffect the registrant’s ability to record, process, summarize and report financial information; and(f)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financialreporting. /s/ John W. Eaves John W. Eaves Chief Executive Officer, Director February 24, 2017Exhibit 31.2Certification I, John T. Drexler, certify that: 1.I have reviewed this annual report on Form 10-K of Arch Coal, Inc.;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, inlight of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition,results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange ActRules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that materialinformation relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period inwhich this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to providereasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generallyaccepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of thedisclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (theregistrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controlover financial reporting; and 5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’sauditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adverselyaffect the registrant’s ability to record, process, summarize and report financial information; and(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financialreporting. /s/ John T. Drexler John T. Drexler Senior Vice President and Chief Financial Officer February 24, 2017 Exhibit 32.1Certification of Chief Executive Officer of Arch Coal, Inc. Pursuant to 18.U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I, John W. Eaves, Chief Executive Officer of Arch Coal, Inc., certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of2002, that: (1)the Annual Report on Form 10-K for the year ended December 31, 2016 (the “Periodic Report”) which this statement accompanies fully complies with therequirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and(2)information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of Arch Coal, Inc. /s/ John W. Eaves John W. Eaves Chief Executive Officer, Director February 24, 2017 Exhibit 32.2Certification of Chief Financial Officer of Arch Coal, Inc. Pursuant to 18.U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I, John T. Drexler, Senior Vice President and Chief Financial Officer of Arch Coal, Inc., certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 ofthe Sarbanes-Oxley Act of 2002, that: (1)the Annual Report on Form 10-K for the year ended December 31, 2016 (the “Periodic Report”) which this statement accompanies fully complies with therequirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2)information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of Arch Coal, Inc. /s/ John T. Drexler John T. Drexler Senior Vice President and Chief Financial Officer February 24, 2017 Exhibit 95Mine Safety and Health Administration Safety DataWe believe that Arch Coal, Inc. (“Arch Coal”) is one of the safest coal mining companies in the world. Safety is a core value at Arch Coal and at oursubsidiary operations. We have in place a comprehensive safety program that includes extensive health & safety training for all employees, site inspections,emergency response preparedness, crisis communications training, incident investigation, regulatory compliance training and process auditing, as well as anopen dialogue between all levels of employees. The goals of our processes are to eliminate exposure to hazards in the workplace, ensure that we comply withall mine safety regulations, and support regulatory and industry efforts to improve the health and safety of our employees along with the industry as a whole.The operation of our mines is subject to regulation by the Federal Mine Safety and Health Administration (MSHA) under the Federal Mine Safetyand Health Act of 1977 (Mine Act). MSHA inspects our mines on a regular basis and issues various citations, orders and violations when it believes aviolation has occurred under the Mine Act. We present information below regarding certain mining safety and health violations, orders and citations, issuedby MSHA and related assessments and legal actions and mine-related fatalities with respect to our coal mining operations. In evaluating the aboveinformation regarding mine safety and health, investors should take into account factors such as: (i) the number of citations and orders will vary dependingon the size of a coal mine, (ii) the number of citations issued will vary from inspector to inspector and mine to mine, and (iii) citations and orders can becontested and appealed, and in that process are often reduced in severity and amount, and are sometimes dismissed or vacated.The table below sets forth for the twelve months ended December 31, 2016 for each active MSHA identification number of Arch Coal and itssubsidiaries, the total number of: (i) violations of mandatory health or safety standards that could significantly and substantially contribute to the cause andeffect of a coal or other mine safety or health hazard under section 104 of the Mine Act for which the operator received a citation from MSHA; (ii) ordersissued under section 104(b) of the Mine Act; (iii) citations and orders for unwarrantable failure of the mine operator to comply with mandatory health orsafety standards under section 104(d) of the Mine Act; (iv) flagrant violations under section 110(b)(2) of the Mine Act; (v) imminent danger orders issuedunder section 107(a) of the Mine Act; (vi) proposed assessments from MHSA (regardless of whether Arch Coal has challenged or appealed the assessment);(vii) mining-related fatalities; (viii) notices from MSHA of a pattern of violations of mandatory health or safety standards that are of such nature as could havesignificantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under section 104(e) of the Mine Act;(ix) notices from MSHA regarding the potential to have a pattern of violations as referenced in (viii) above; and (x) pending legal actions before the FederalMine Safety and Health Review Commission (as of December 31, 2016) involving such coal or other mine, as well as the aggregate number of legal actionsinstituted and the aggregate number of legal actions resolved during the reporting period.1Exhibit 95Mine or Operating Name / MSHAIdentification NumberSection104 S&SCitations(#)Section104(b)Orders(#)Section104(d)Citationsand Orders(#)Section110(b)(2)Violations(#)Section107(a)Orders(#)Total DollarValue ofMSHAAssessmentsProposed(in thousands)($)TotalNumber ofMiningRelatedFatalities(#)ReceivedNotice ofPattern ofViolationsUnderSection104(e)(Yes/No)ReceivedNotice ofPotential toHave Patternof ViolationsUnderSection104(e)(Yes/No)LegalActionsInitiatedDuringPeriod(#)LegalActionsResolvedDuringPeriod(#)LegalActionsPendingas of LastDay ofPeriod(1)(#)Active OperationsLone Mountain Darby Fork /15‑0226313————12.7—NoNo———Lone Mountain Clover Fork /15‑1864717————33.3—NoNo———Lone Mountain Huff Creek /15‑1723421—3——236.81NoNo343Lone Mountain 6C Mine /44‑067821————1.2—NoNo———Lone Mountain Processing /44‑058983————0.9—NoNo———Lone Mountain Days Creek /15-17971—————1.0—NoNo———Powell Mt. Mine #1 /15‑18734———————NoNo———Powell Mt. Middle Splint /44‑07207———————NoNo———Knott County Raven Prep Plant /15‑17724———————NoNo———Vindex Cabin Run /18‑001331————0.4—NoNo———Vindex Bismarck /46‑093691————0.4—NoNo———Vindex Jackson Mt. /18-00170———————NoNo———Vindex Wolf Den Run /18-00790—————0.4—NoNo———Cumberland River Pardee Plant /44‑05014———————NoNo———Cumberland River Band MillMine /44‑06816———————NoNo———Cumberland River Pine Branch#1 /44‑07224———————NoNo———Cumberland River Trace Fork #1/15‑19533—————0.68—NoNo———2Exhibit 95Beckley Pocahontas Mine /46‑0525254————273.0—NoNo8152Beckley Pocahontas Plant /46‑09216—————1.2—NoNo———Coal Mac Holden #22 Prep Plant/46‑05909—————0.3—NoNo———Lone Mountain Processing /Mayflower Prep Plant /44-05605—————0.1—NoNo———Coal Mac Ragland Loadout /46‑08563—————0.1—NoNo———Coal Mac Holden #22 Surface /46‑089842————3.0—NoNo———Eastern Birch River Mine /46-07945—————0.2—NoNo———Sentinel Mine /46‑0416824————70.0—NoNo1102Sentinel Prep Plant /46‑087772————1.3—NoNo———Mingo Logan Mountaineer II /46‑09029532——1208.3—NoNo1085Mingo Logan Cardinal Prep Plant/46‑09046—————0.5—NoNo———Mingo Logan Daniel Hollow /46‑09047———————NoNo———Leer #1 Mine /46‑0919260————185.31NoNo9174Arch of Wyoming Elk Mountain/48‑01694———————NoNo———Black Thunder /48‑009771————7.4—NoNo———Coal Creek /48‑012153————9.6—NoNo1—1West Elk Mine /05‑0367220————76.7—NoNo—1—Viper Mine /11‑0266421————56.8—NoNo—1—Leer #1 Prep Plant /46-091912————1.0—NoNo———Wolf Run Mining – Sawmill RunPrep Plant / 46-05544———————NoNo———3Exhibit 95(1)See table below for additional details regarding Legal Actions Pending as of December 31, 2016Mine or Operating Name/MSHAIdentification NumberContests ofCitations,Orders (as ofDecember 31,2016)Contests ofProposedPenalties (as ofDecember 31,2016)Complaints forCompensation (asof December 31,2016)Complaints ofDischarge,Discrimination orInterference (as ofDecember 31, 2016)Applications forTemporary Relief(as ofDecember 31,2016)Appeals of Judges’Decisions or Orders(as ofDecember 31,2016)Lone Mountain Huff Creek / 15-17234—3————Beckley Pocahontas Mine / 46-05252—2————Sentinel Mine / 46-04168—1————Mingo Logan Mountaineer II / 46-09029—5————Leer #1 / 46‑09192—4————Thunder Basin Coal Creek / 48-01215—1————4

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