Archer
Annual Report 2017

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, 2017 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 valueNew York Stock ExchangeSecurities 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, smaller reporting company, or an emerging growth company.See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.Large accelerated filer xAccelerated filer ¨Non-accelerated filer ¨(Do not check if a smaller reporting company)Smaller reporting company ¨ Emerging growth company ¨If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financialaccounting standards provided pursuant to Section 13(a) of the Securities Act. ¨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, 2017 was approximately $1.7 billion.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, 2018 there were 20,986,812 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 2018 annualstockholders’ meeting are incorporated by reference into Part III of this Form 10-K. Table of ContentsTABLE OF CONTENTS PagePART I ITEM 1.Business6ITEM 1A.Risk Factors33ITEM 1B.Unresolved Staff Comments44ITEM 2.Properties45ITEM 3.Legal Proceedings48ITEM 4.Mine Safety Disclosures48 PART II ITEM 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities49ITEM 6.Selected Financial Data52ITEM 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations53ITEM 7A.Quantitative and Qualitative Disclosures About Market Risk76ITEM 8.Financial Statements and Supplementary Data77ITEM 9.Changes In and Disagreements with Accountants on Accounting and Financial Disclosure77ITEM 9A.Controls and Procedures77ITEM 9B.Other Information77 PART III ITEM 10.Directors, Executive Officers and Corporate Governance78ITEM 11.Executive Compensation78ITEM 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matter78ITEM 13.Certain Relationships and Related Transactions, and Director Independence78ITEM 14.Principal Accounting Fees and Services78 PART IV ITEM 15.Exhibits and Financial Statement Schedules79ITEM 16.Form 10-K Summary793Table 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, Inventory-Based Revolving CreditFacility, other financing arrangements or any subsequent financing or credit facilities;•the availability and cost of surety bonds;•our ability to manage the market and other risks associated with certain trading and other asset optimization strategies;4Table of Contents•the effects of foreign and domestic trade policies, actions or disputes on the level of trade among the countries and regions in which we operate,the competitiveness of our exports, or our ability to export;•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.5Table of ContentsPART I ITEM 1. BUSINESSIntroductionWe are one of the world’s largest coal producers. For the year ended December 31, 2017, we sold approximately 98 million tons of coal, includingapproximately 1.5 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, 2017, we operated 9 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 24 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. 1334.6Table 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 required 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.7Table 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 in 2017 according to the International Energy Agency (IEA). China is the largestproducer of coal in the world, producing over 3.5 billion metric tons in 2017 according to the Chinese Bureau of Statistics. The United States and Indiafollow China with total coal production of over 650 million metric tons each in 2017 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,Canada, 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, and West Virginia. Subsequent to the sale of our Lone Mountainoperation in the third quarter of 2017, our metallurgical coal is produced at operations in West Virginia. Heat value and sulfur content are the most importantvariables in the economic marketing and transportation of thermal coal. Carbon content, the composition of the non-carbon volatiles and other chemicalconstituents 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 23 countries. During the year, we supplied coal to 93 domestic and 33 foreign customers. In 2017,approximately 93% of our coal sales volume was sold as a thermal product with the remaining 7% as metallurgical.Coal was used to produce approximately 30% of the electric power generated in the U.S. in 2017 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 2017. We also exported 8% ofour production to customers outside the U.S. in 2017.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 2017. Our metallurgical coal was sold to 6 domestic customers and shipped to 18 international destinations in 2017.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 (particularly, natural gas), regulatory limits on using coal, taxes, the weather and economic conditions. For metallurgical coal, the price of coal isaffected by the supply, demand and price of competitive coal, transportation, the price of steel, demand for steel, as well as regulations, taxes, and economicconditions.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 250 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 300 years.8Table 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 increased by an estimated 45 milliontons in 2017, to 773 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 increased from an estimated 404 million short tons in 2016 to 432 million short tons in 2017. 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 8,300 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 increasedfrom 180 million short tons in 2016 to 196 million short tons in 2017. Appalachian coal is located near the prolific eastern shale-gas producing regions.Central Appalachian thermal coal is disadvantaged for power generation because of the depletion of economically attractive reserves, permitting issues andincreasing costs of production. However, virtually all U.S. metallurgical coal is produced in Appalachia and the relative scarcity and high-quality of this coalallows for 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.Northern Appalachia includes Maryland, Ohio, Pennsylvania and northern West Virginia. Coal from this region generally has a high heat valueranging from 10,300 to 13,500 Btu and a sulfur content ranging from 0.8% to 4.0%. Central Appalachia includes eastern Kentucky, Tennessee, Virginia andSouthern West Virginia. Coal mined from this region generally has a high heat value ranging from 11,400 to 13,200 Btu and low sulfur content ranging from0.2% to 2.0%. Southern Appalachia primarily covers Alabama and generally has a heat content ranging from 11,300 to 12,300 Btu and a sulfur contentranging 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 increased from 144 million short tons in 2016 to approximately 145 million short tons in 2017. Coal from theIllinois Basin generally has a heat value ranging from 10,100 to 12,600 Btu and has a sulfur content ranging from 1.0% to 4.3%. Despite its high sulfurcontent, coal from the Illinois Basin can generally be used by electric power generation facilities that have installed emissions control devices, such asscrubbers.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.9Table of ContentsThe following diagram illustrates a typical dragline surface mining operation:10Table 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.11Table 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. All of our mining operations in the Appalachia region use a coal preparationplant located near the mine or connected to the mine by a conveyor. These coal preparation plants allow us to treat the coal we extract from those mines toensure a consistent quality and to enhance its suitability for particular end‑users. In addition, depending on coal quality and customer requirements, we mayblend 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”.12Table of ContentsOur Mining OperationsGeneral. At December 31, 2017, we operated 9 active mines in the United States. The Company’s reportable business segments are based on twodistinct lines of business, metallurgical coal and thermal coal, and may include a number of mine complexes. The Company manages its coal sales by market,not by individual mining complex. Geology, coal transportation routes to customers, and regulatory environments also have a significant impact on ourmarketing and operations management. Our mining operations are evaluated based on Adjusted EBITDAR, per-ton cash operating costs (defined as includingall mining costs except depreciation, depletion, amortization, accretion on asset retirements obligations, and pass-through transportation expenses), and onother non-financial measures, such as safety and environmental performance. Adjusted EBITDAR is defined as net income attributable to the Companybefore the effect of net interest expense, income taxes, depreciation, depletion and amortization, the amortization of sales contracts, the accretion on assetretirement obligations, and reorganization items, net. Adjusted EBITDAR may also be adjusted for items that may not reflect the trend of future results byexcluding transactions that are not indicative of our core operating performance. We use Adjusted EBITDAR to measure the operating performance of oursegments and allocate resources to our segments. Adjusted EBITDAR is not a measure of financial performance in accordance with generally acceptedaccounting principles, and items excluded from Adjusted EBITDAR are significant in understanding and assessing our financial condition. Therefore,Adjusted EBITDAR should not be considered in isolation, nor as an alternative to net income, income from operations, cash flows from operations or as ameasure of our profitability, liquidity or performance under generally accepted accounting principles. Furthermore, analogous measures are used by industryanalysts to evaluate the Company’s operating performance. Investors should be aware that our presentation of Adjusted EBITDAR may not be comparable tosimilarly titled measures used by other companies. The Company’s reportable segments are the Powder River Basin (PRB) segment containing theCompany’s primary thermal operations in Wyoming; the Metallurgical (MET) segment, containing the Company’s metallurgical operations in West Virginiaand the Other Thermal segment containing the Company’s supplementary thermal operations in Colorado, Illinois, and the Coal Mac thermal operation inWest Virginia. For additional information about the operating results of each of our segments for the year ended December 31, 2017, the periods October 2through December 31, 2016, January 1 through October 1, 2016 and the year ended December 31, 2015, see Note 27 of the Consolidated FinancialStatements.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 all of the equipment utilized in our mining operations. We employ sophisticatedpreventative maintenance and rebuild programs and upgrade our equipment to ensure that it is productive, well‑maintained and cost‑competitive.13Table of ContentsThe following table provides a summary of information regarding our active mining complexes as of December 31, 2017, including the total salesassociated with these complexes for the year ended December 31, 2017, the periods October 2 through December 31, 2016, January 1 through October 1,2016 and the year ended December 31, 2015 and the total reserves associated with these complexes at December 31, 2017. The amount disclosed below forthe total cost of property, plant and equipment of each mining complex does not include the costs of the coal reserves that we have assigned to an individualcomplex. Tons Sold(1) Predecessor Successor Mining ComplexCaptiveMinesMiningEquipmentRailroad2015Jan1-Oct1,2016Oct2-Dec31,20162017Total Cost ofProperty, Plantand Equipmentat December 31,2017Total AssignedRecoverableReserves (Million tons)($ millions)(Million tons)Powder River Basin: Black ThunderSD, SUP/BN99.549.018.970.5$266.7896.4Coal CreekSD, SUP/BN7.85.52.79.043.5128.4Metallurgical: Mountain LaurelULW, CMCSX2.01.20.41.525.221.1BeckleyUCMCSX0.90.70.31.038.725.4SentinelUCMCSX0.90.80.31.537.54.7LeerULW, CMCSX2.93.11.03.2217.030.8Other Thermal: West ElkULW, CMUP5.12.41.64.938.653.1ViperUCM—2.11.30.31.725.034.6Coal‑MacSL, ENS/CSX2.41.50.52.430.822.7Totals 123.665.526.095.7$723.01,217.2S = 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)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.14Table 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 896.4million tons of proven and probable reserves at December 31, 2017. 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 four active pit areas and three loadout facilities. We ship all of the coal raw to ourcustomers via the Burlington Northern Santa Fe and Union Pacific railroads. We do not process the coal mined at this complex. Each of the loadout facilitiescan load a 15,000‑ton train in less than two hours.Coal Creek. Coal Creek is a surface mining complex located on approximately 7,400 acres in Campbell County, Wyoming. The Coal Creek 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 approximately 128.4million tons of proven and probable reserves at December 31, 2017. The air quality permit for the Coal Creek mine allows for the mining of coal at a rate of50 million tons per year.The Coal Creek complex currently consists of one active pit area and a loadout facility. We ship all of the coal raw to our customers via theBurlington Northern Santa Fe and Union Pacific railroads. We do not process the coal mined at this complex. The loadout facility can load a 15,000‑ton trainin less than three hours.MetallurgicalMountain Laurel. Mountain Laurel is an underground mining complex located on approximately 38,200 acres in Logan County and Boone County,West Virginia. Underground mining operations at the Mountain Laurel mining complex extract High-vol B metallurgical coal from the Cedar Grove andAlma seams. The Mountain Laurel mining complex has approximately 21.1 million tons of proven and probable reserves at December 31, 2017.We process all of the coal through a 1,400‑ton‑per‑hour preparation plant before shipping the coal to our customers via the CSX railroad. Theloadout facility can load a 15,000‑ton train in less than four hours.Beckley. The Beckley mining complex is located on approximately 19,700 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 25.4 million tons of proven andprobable reserves at December 31, 2017.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 approximately25,700 acres in Barbour County, West Virginia. Mining operations currently extract High-vol A metallurgical coal from the Clarion coal seam. Coal from theSentinel mining complex is processed through the preparation plant and shipped by CSX rail to customers. The Sentinel mining complex had approximately4.7 million tons of proven and probable reserves at December 31, 2017.Leer. The Leer Complex, located in Taylor County, West Virginia, includes approximately 30.8 million tons of coal reserves as of December 31,2017 and has primarily High-vol A metallurgical quality coal in the Lower Kittanning seam, and is part of approximately 82,300 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.15Table of ContentsOther ThermalWest Elk. West Elk is an underground mining complex located on approximately 19,500 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 53.1 milliontons of proven and probable reserves at December 31, 2017.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 39,700 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, 2017, we had approximately 34.6 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 22.7 million tons ofproven and probable reserves at December 31, 2017.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 higher capital costs, including costs for construction of extensive ventilation systems, and higher per unit labor costs due to lower productivityassociated with underground 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 representatives 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, 2017, we derived approximately 17% of our total coal revenues from sales to our three largest customers, UnitedStates Steel Corporation, ArcelorMittal and Southern Company and approximately 41% of our total coal revenues from sales to our 10 largest customers.16Table of ContentsIn 2017, 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 2017 we also exported coal to Europe, Asia, North America (outside the United States), Central and South America and Africa.Exports to foreign countries were $0.8 billion, $0.5 billion and $0.4 billion for the years ended December 31, 2017, 2016 and 2015, respectively. As ofDecember 31, 2017 and 2016, trade receivables related to metallurgical‑quality coal sales totaled $99.4 million and $88.0 million, respectively, or 58% and48% of total trade receivables, respectively. We do not have foreign currency exposure for our international sales as all sales are denominated and settled inU.S. dollars.The Company’s foreign revenues by coal shipment destination for the year ended December 31, 2017, were as follows:(In thousands) Europe$388,926Asia264,503North America88,145Central and South America30,982Africa14,901Brokered Sales6,137Total$793,594Long-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 2017, we sold approximately 66% 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, 2017, the average volume‑weighted remaining term of our long-term contracts was approximately 2.3 years, with remaining termsranging from one to four years. At December 31, 2017, remaining tons under long-term supply agreements, including those subject to price re-opener orextension provisions, were approximately 108 million tons.We typically sell coal to North American customers under long‑term arrangements through a “request‑for‑proposal” process. The terms of our coalsales agreements result from competitive bidding and negotiations with customers. Consequently, the terms of these contracts vary by customer, includingbase price adjustment features, price re‑opener terms, coal quality requirements, quantity parameters, permitted sources of supply, future regulatory changes,extension options, force majeure, termination, damages and assignment provisions. Our long‑term supply contracts typically contain provisions to adjust thebase price due to new statutes, ordinances or regulations. We typically sell our metallurgical coal to non-North American customers based on various indicesor agreements to mutually negotiate the price. These agreements generally are for one year and can reset pricing with each shipment. Additionally, some ofour contracts contain provisions that allow for the recovery of costs affected by modifications or changes in the interpretations or application of anyapplicable statute by local, state or federal government authorities. These provisions only apply to the base price of coal contained in these supply contracts.In some circumstances, a significant adjustment in base price can lead to termination of the contract.Certain of our contracts contain index provisions that change the price based on changes in market based indices or changes in economic indices 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 tosuspend the agreement for the pricing period not agreed to. In addition, certain of our contracts contain clauses that may allow customers to terminate thecontract in the event of certain changes in environmental laws and regulations that impact their operations.17Table of ContentsCoal 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, 2017.Transportation. We ship our coal to domestic customers by means of railcars, barges, or trucks, or a combination of these means of transportation.We generally sell coal used for domestic consumption free on board (f.o.b.) at the mine or nearest loading facility. Our domestic customers normally bear thecosts of transporting coal by rail, barge or truck.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; and our Coal Mac mine is served by both the CSX and Norfolk Souther railroads.. We generallytransport coal produced at our Appalachian mining complexes via the CSX railroad or the Norfolk Southern railroad. Besides rail deliveries, some customersin the eastern United States rely on a river barge system.18Table of ContentsWe 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 35% 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.From time-to-time, we may lease a portion of our port capacity to third parties.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 Blackhawk Mining LLC, Blackjewel LLC, Contura Energy, Coronado Coal LLC, CorsaCoal Corp., Cloud Peak Energy, Peabody Energy Corp. and Ramaco Resources. Some of these coal producers are larger than we are and have greater financialresources and larger reserve bases than we do. We also compete directly with a number of smaller producers in each of the geographic regions in which weoperate, as well as companies that produce coal from one or more foreign countries, such as Australia, Colombia, Indonesia and South Africa.Additionally, coal competes with other fuels, such as natural gas, nuclear energy, hydropower, wind, solar and petroleum, for steam and 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.19Table of ContentsFuture 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 to become a less attractive fuel source, thereby reducing coal’s share of the market for fuels and other energysources 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, 2017.20Table of ContentsSMCRA permit provisions include a complex set of requirements which include, among other things, coal prospecting; mine plan development;topsoil or growth medium removal and replacement; selective handling of overburden materials; mine pit backfilling and grading; disposal of excess spoil;protection of the hydrologic balance; subsidence control for underground mines; surface runoff and drainage control; establishment of suitable post miningland uses; and revegetation. We begin the process of preparing a mining permit application by collecting baseline data to adequately characterize thepre‑mining environmental conditions of the permit area. This work is typically conducted by third‑party consultants with specialized expertise and includessurveys and/or assessments of the following: cultural and historical resources; geology; soils; vegetation; aquatic organisms; wildlife; potential forthreatened, endangered or other special status species; surface and ground water hydrology; climatology; riverine and riparian habitat; and wetlands. Thegeologic data and information derived from the other surveys and/or assessments are used to develop the mining and reclamation plans presented in thepermit application. The mining and reclamation plans address the provisions and performance standards of the state’s equivalent SMCRA regulatoryprogram, and are also used to support applications for other authorizations and/or permits required to conduct coal mining activities. Also included in thepermit application is information used for documenting surface and mineral ownership, variance requests, access roads, bonding information, miningmethods, mining phases, other agreements that may relate to coal, other minerals, oil and gas rights, water rights, permitted areas, and ownership and controlinformation required to determine compliance with OSM’s Applicant Violator System, including the mining and compliance history of officers, directors andprincipal 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 2017, we recorded $24.6 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 widely fluctuated in recent years while the market terms of surety bonds have generally hardened for mine operators.These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. As ofDecember 31, 2017, we posted an aggregate of approximately $531.7 million in surety bonds for reclamation purposes and secured $10.0 million in letters ofcredit and cash for reclamation bonding obligations. In addition, we had approximately $161.6 million of surety bonds, cash and letters of credit outstandingat December 31, 2017 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.21Table of ContentsUnder 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, 1973. The trust fund is funded by an excise tax on production of up to $1.10 perton for coal mined in underground operations and up to $0.55 per ton for coal mined in surface operations. These amounts may not exceed 4.4% of the grosssales price. This excise tax does not apply to coal shipped outside the United States. In 2017, we recorded $48.7 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. A suit challenging the EPA’s 2015 Ozone NAAQS, Murray Energy Corp. v. EPA, is currently pending in theUnited States Court of Appeals for the District of Columbia, which we refer to as the D.C. Circuit. However, on April 11, 2017, the D.C. Circuitgranted the EPA’s motion, which cites President Trump’s March 28, 2017 Energy Independence Executive Order, to indefinitely delay anydecision on the challenges. The EPA did not meet the October 1, 2017 deadline for designating non-attainment areas but, on November 6, 2017,issued final designations for areas in the United States representing approximately 85% of the U.S. counties that would take effect sixty daysafter the notice is22Table of Contentspublished in the Federal Register. For the remaining areas of the United States, the EPA has not yet prepared final designations but plans to doso in a separate future action.•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. Installation of additional emissioncontrol measures has made it more costly to operate coal‑fueled power plants, which could make coal a less attractive fuel.•Interstate Transport. The EPA finalized the Clean Air Interstate Rule, which we refer to as CAIR, in March 2005. CAIR called for power 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 D.C. Circuit disagreed with theEPA’s reading of the Clean Air Act and vacated CAIR in its entirety. In December 2008, the D.C. Circuit revised its remedy and remanded therule to the EPA. The EPA proposed a revised transport rule on August 2, 2010 (75 Fed. Reg. 45209) to address attainment of the 1997 ozoneNAAQS and the 2006 PM2.5 NAAQS. The rule was finalized as the Cross State Air Pollution Rule (CSAPR) on July 6, 2011, with compliancerequired for SO2 reductions beginning January 1, 2012 and compliance with NOx reductions required by May 1, 2012. Numerous appeals of therule were filed and, on August 21, 2012, the D.C. Circuit vacated the rule, leaving the EPA to continue implementation of the CAIR. Controlsrequired under the CAIR, especially in conjunction with other rules may have affected the market for coal inasmuch as multiple existing coalfired 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 D.C. Circuit decision, remanding the case back to the D.C. Circuit. The EPA then requested that the court lift the CSAPR stayand toll the CSAPR compliance deadlines by three years. On October 23, 2014, the D.C. Circuit granted the EPA’s request, and that court laterdismissed all pending challenges to the rule on July 28, 2015 but it remanded some state budgets to EPA for further consideration. CSAPRPhase 1 implementation began in 2015, with Phase 2 beginning in 2017. CSAPR generally requires greater reductions than under CAIR. As aresult, some coal‑fired power plants will be required to install costly pollution controls or shut down which may adversely affect the demand forcoal. Finally, in October 2016, the EPA issued an update to the CSAPR to address interstate transport of air pollution under the more recent2008 ozone NAAQS and the state budgets remanded by the D.C. Circuit. Consolidated judicial challenges to the rule are now pending, but onAugust 10, 2017, the D.C. Circuit suspended briefing in the litigation after industry petitioners challenging the rule requested to delayproceedings so EPA can determine whether to reconsider the revised CSAPR. If the rule is upheld, it is likely the CSAPR update will increasethe pressure to install controls or shut down units, which may further adversely affect the demand for coal.•Mercury. In February 2008, the D.C. Circuit vacated the EPA’s Clean Air Mercury Rule (CAMR), which was promulgated to reduce mercuryemissions from coal-fired power plants and remanded it to the EPA for reconsideration. In response, the EPA announced an Electric GeneratingUnit (EGU) Mercury and Air Toxics Standard (MATS) on December 16, 2011. The MATS was finalized April 16, 2012, and required compliancefor most plants by 2015. In addition, before the court decision vacating the CAMR, some states had either adopted the CAMR or adoptedstate‑specific rules to regulate mercury emissions from power plants that are more stringent than the CAMR. MATS compliance, coupled withstate mercury and air toxics laws and other factors have required many plants to install costly controls, re-fire with natural gas or to retire, whichmay 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 MATS 2016 SupplementalFinding, a final finding that it is appropriate and necessary to set standards for emissions of air toxics from coal- and oil-fired power plants. Thatfinding is now being challenged in court. Therefore, the rule23Table of Contentsremains in effect until further order of the D.C. Circuit. The D.C. Circuit denied petitioners’ motion to temporarily halt the pending litigation toallow the new administration to evaluate whether it can resolve any issues raised in the case. However, in April 2017, the EPA requested a delayin the D.C. Circuit proceedings while EPA is reviewing the determinations of the prior administration. Hence, while MATS will likely continueto impact coal-fueled generation as discussed above for at least the near term, the future course of the Rule is unclear.•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 to reduce emissions and comply with stricter emission limitations. The vast majority of states failed to submit their plans by December 17,2007, and the EPA issued a Finding of Failure to Submit plans on January 15, 2009 (74 Fed. Reg. 2392). The EPA had taken no enforcementaction against states to finalize implementation plans and was slowly dealing with the state Regional Haze SIPs that were submitted, whichresulted in the National Parks Conservation Association commencing litigation in the D.C. Circuit on August 3, 2012, against the EPA forfailure to enforce the rule (National Parks Conservation Act v. EPA, D.C. Cir). Industry groups, including the Utility Air Regulatory Group haveintervened (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 retrofit 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. However, on January 18, 2018, EPA announced that it was revisiting the 2017 Regional HazeRule revisions, and announced an intent to commence a new rulemaking. This proceeding may slow or even roll back certain Regional Hazerequirements.•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 of greenhouse gases. For example, in December 2015,representatives of 195 nations reached a climate accord that will, for the first time, commit participating countries to lowering greenhouse gas emissions.Further, the United States and a number of international development banks, such as the World Bank, the European Investment Bank and European Bank forReconstruction and Development, have announced that they will no longer provide financing for the development of new coal-fueled power plants, subjectto very narrow exceptions.24Table of ContentsAlthough 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 gasemissions 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. In October 2017, EPA commenced rulemaking proceedings to rescind the Clean Power Plan, and inDecember 2017, EPA published an Advanced Notice of Proposed Rulemaking announcing an intent to commence a new rulemaking to replace the CleanPower Plan with an alternative framework for regulating carbon dioxide.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. Inconjunction with EPA’s proposal to rescind the Clean Power Plan, EPA also requested a stay of the NSPS litigation. The D.C. Circuit granted the request, andthe litigation has been held in abeyance since then.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. On June 1, 2017, The Trump Administration announced the United States was withdrawing from 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).25Table of ContentsSeveral 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, may have or adopt in the future rules or policies that cause some users of coal to switch from coal to a lower carbon fuel. There can beno assurance at this time that a carbon dioxide cap-and-trade-program, a carbon tax or other regulatory or policy regime, if implemented by any one or morestates or regions in which our customers operate or at the federal level, will not affect the future market for coal in those states or regions and lower the overalldemand 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.The scope of waters that fall within the Clean Water Act’s jurisdiction is expansive and may include features not commonly understood to be astream or wetland. In June 2015, EPA issued a new rule defining the scope of "waters of the United States" (WOTUS) that are subject to regulation. TheWOTUS rule was challenged by a number of states and private parties in both district and circuit courts. The actions in the circuit courts were consolidated inthe United States Court of Appeals for the Sixth Circuit and in October 2015 that court stayed the WOTUS rule on a nationwide basis. In January 2018, theSupreme Court ruled that challenges to the WOTUS rule must be made to the appropriate federal district courts rather than the Sixth Circuit. The SupremeCourt’s ruling will likely cause the nationwide stay to be lifted, which may result in piecemeal litigation over stays of the rule by the various district courtsin which challenges to the rule have been filed. In December 2017, EPA and the Corps proposed a rule to repeal the WOTUS rule and are scheduled topropose a replacement to the WOTUS rule in May 2018.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.26Table of ContentsThe 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.•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.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 and27Table of Contentswould be enforced primarily through citizen suits. The proposal left intact the so-called Bevill exemption for beneficial uses of CCR. The EPA finalized theCCR rule on December 19, 2014, setting nationwide solid nonhazardous waste standards for CCR disposal. On April 17, 2015, the EPA finalized regulationsunder the solid waste provisions (Subtitle D) of RCRA and not the hazardous waste provisions (Subtitle C) which became effective on October 19, 2015. Thefinal rule establishes national minimum criteria for existing and new CCR landfills, surface impoundments and lateral expansions, and also establishesstructural integrity criteria for new and existing surface impoundments (including establishing requirements for owners and operators to conduct periodicstructural integrity-related assessments). The criteria include location restrictions, design and operating criteria, groundwater monitoring and correctiveaction, closure requirements and post-closure care and recordkeeping, notification and internet posting requirements. While classification of CCR as ahazardous 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. After industry groups filed a suit in the D.C. Circuit, challenging the 2015 rule, EPA AdministratorPruitt issued a letter on September 13, 2017 indicating the agency’s decision to reconsider the rule in response to industry petitions. On September 27, 2017,oral arguments in the litigation were rescheduled for November 20, 2017. The court also ordered EPA file a status report by November 15, 2017 specifyingwhich provisions of the final rule are or are likely to be subject to reconsideration and estimated timeline for reconsideration. The court also ordered theparties to file supplemental briefs addressing the relevance to and the implications for the Water Infrastructure Improvements for the Nation Act, Pub. L. No.114-322. Future regulations resulting from the EPA coal combustion refuse assessments may impact the ability of the Company’s utility customers tocontinue to use coal in their power plants.Comprehensive 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.28Table of ContentsOther 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, 2017, we employed approximately 3,790 full and part‑time employees. We believe that our relations with employees are good.29Table of ContentsExecutive Officers of the RegistrantThe following is a list of our executive officers, their ages as of February 23, 2018 and their positions and offices during the last five years:NameAgePositionKenneth D. Cochran57Mr. 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 theboard of Knight Hawk Holdings, LLC.John T. Drexler48Mr. 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. Eaves60Mr. 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, the National Mining Association and CF IndustriesHoldings, Inc. Mr. Eaves was previously a director of Advanced Emissions Solutions, Inc. and former chairmanof the National Coal Council.Robert G. Jones61Mr. 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. Kelley57Mr. 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. Lang57Mr. 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 Knight Hawk Holdings, LLC.Mr. Lang also served on the development board of the Mining Department of the Missouri University ofScience & Technology, and is the former chairman of the University of Wyoming’s School of Energy ResourcesCouncil.Deck S. Slone54Mr. 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 Vice Chair of theNational Coal Council, the immediate past co-chair of the Carbon Utilization Research Council, and the Chair ofthe National Mining Association’s Energy Policy Task Force.John A. Ziegler, Jr.51Mr. 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.30Table 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.31Table 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.Bituminous coalCoal used primarily to generate electricity and to make coke for the steel industry with a heat value ranging between10,500 and 15,500 Btus per pound.BtuA measure of the energy required to raise the temperature of one pound of water one degree of Fahrenheit.Coking coalCoal used to produce coke, the primary source of carbon used in steelmaking.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.Lignite CoalCoal with the lowest carbon content and a heat value ranging between 4,000 and 8,300 Btus per pound.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.Metallurgical coalCoal used in steel production either as coking coal or pulverized coal injection (PCI).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.Pulverized coal injection coal (PCI)Coal that is introduced directly into the blast furnace as a source of energy and carbon in the steelmaking process.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.Subbituminous coalCoal used primarily to generate electricity with a heat value ranging between 8,300 and 13,000 Btus per pound.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.32Table 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 is 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 allocated our reorganization value to the fair value of assets and liabilities in conformity with the guidance for the acquisition method ofaccounting for business combinations. Adjustments to the carrying amounts were material and will affect prospective results of operations as balance sheetitems are settled, depreciated, amortized or impaired. This will make it difficult for stockholders to assess our performance in relation to prior periods. OurAnnual Report on Form 10-K for the fiscal year ending December 31, 2016 reflects the consummation of the Plan and the adoption of fresh start accountingeffective October 1, 2016.Risks Related to Our OperationsCoal prices are subject to change based on a number of factors and can be volatile. Within the last several years, coal prices have experienced an historiclevel of depression. If there is a decline in prices, it could materially and adversely affect our profitability and the value of our coal reserves.Our profitability and the value of our coal reserves depend upon the prices we receive for our coal. The contract prices we may receive in the 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;•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.Declines in the prices we receive for our future coal sales contracts, could materially and adversely affect us by decreasing our profitability, cashflows, liquidity and the value of our coal reserves.33Table of ContentsUnfavorable 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 at times during thepast several years as the demand for, and price of, coal has been subject to pressure for a variety of reasons, including reductions in domestic and internationaldemand for metallurgical and thermal coal.Global economic downturns have also had and in the future could have a negative impact on us. These conditions have, in the past, led to extremevolatility of prices, severely limited liquidity and credit availability, and resulted in declining valuations of assets. If there are downturns in economicconditions, our customers’ and our businesses, financial conditions or results of operations could be adversely affected. Furthermore, because we typicallyseek to enter into long-term arrangements for the sale of a substantial portion of our coal, the average sales price we receive for our coal may lag behind anygeneral economic recovery. We are focused on cost control and capital discipline, but there can be no assurance that these actions, or any other actions thatwe 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 Asia have at times, and could in the future, materiallyreduce coal prices and therefore materially reduce our revenues and profitability. Potential changes to international trade agreements, trade concessions orother political and economic arrangements may benefit coal producers operating in countries other than the United States. We may not be able to compete onthe basis of price or other factors with companies that in the future benefit from favorable foreign trade policies or other arrangements. In addition, our abilityto ship our coal to international customers depends on port capacity, which is limited. Increased competition within the coal industry for international salescould result in us not being able to obtain throughput capacity at port facilities, or the rates for such throughput capacity to increase to a point where it is noteconomically 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. Consolidation in the coal industry or current orfuture bankruptcy proceedings of our coal competitors could adversely affect our competitive position.In addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas. Natural gas pricing 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.34Table of ContentsAny decrease 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 93% of our coal sales by volume during 2017. 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 (particularly, natural gas) for power generation and governmental regulations which may dictate an alternate source of fuel regardless of economics.Overall economic activity and the associated demands for power by industrial users can have significant effects on overall electricity demand and can becaused by a number of factors. An economic slowdown can significantly slow the growth of electricity demand and could result in reduced demand for coal.For example, declines in the rate of international economic growth in countries such as China, India or other developing countries could further negativelyimpact the demand for U.S. coal and result in a continuing oversupply of coal in the marketplace. Weather patterns can also greatly affect electricity demand.Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increase generating requirements from all sources. Mild temperatures,on the other hand, result in lower electrical demand, which allow generators to choose the source of power generation when deciding which generation sourceto 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 or Leer mining complexes, which accounted for approximately 75% ofthe coal volume we sold and 57% of the revenue we generated in 2017, our coal mining operations may be disrupted and we could experience a delay or haltof production or shipments or our operating costs could increase significantly. In addition, if our insurance coverage is limited or excludes certain of theseconditions or events, then we may not be able to recover any of the losses we may incur as a result of such conditions or events, some of which may besubstantial.35Table 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.In January 2016, the federal government imposed a moratorium on new leases for coal mined from federal lands as part of a review of thegovernment’s management of federally-owned coal. In March 2017, the U.S. Secretary of Interior signed Secretarial Order 3348 lifting that moratorium andhalting the Federal Coal Program Programmatic Environmental Impact Statement that was in process at the time. Litigation is currently pending in the UnitedStates District Court for the District of Montana challenging the lifting of the moratorium as a violation of the National Environmental Policy Act, theMineral Leasing Act and the Federal Land Policy and Management Act. Although the Bureau of Land Management is now working to process coal leaseapplications and modifications expeditiously in accordance with regulations and guidance that existed before Secretarial Order 3338, which imposed themoratorium on new coal leases, any delay in the LBA process, including any delay caused by the now-lifted moratorium could prevent us from obtainingreplacement reserves when we require them. Also, the outcome of the government’s review is uncertain and could have a material and adverse impact on ourbusiness in any number of ways including by limiting our ability to mine reserves under ongoing or future applications, by increasing the costs or timeframeassociated with 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:36Table of Contents•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;•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.Our profitability depends upon the coal supply agreements we have with our customers. Changes in purchasing patterns in the coal industry could make itdifficult for us to extend our existing 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 coal supply agreements or enter intoagreements to purchase fewer tons of coal or on different terms or prices than in the past. In addition,37Table of Contentsuncertainty caused by federal and state regulations, including the U.S. Clean Air Act, could deter our customers from entering into coal supply agreements.Also, the availability and price of competing fuels, such as natural gas, could influence the volume of coal a customer is willing to purchase under contract.Our coal supply agreements typically contain force majeure provisions allowing the parties to temporarily suspend performance during specifiedevents beyond their control. Most of our coal supply agreements also contain provisions requiring us to deliver coal that satisfies certain qualityspecifications, such as heat value, sulfur content, ash content, hardness and ash fusion temperature. These provisions in our coal supply agreements couldresult in negative economic consequences to us, including price adjustments, purchasing replacement coal in a higher-priced open market, the rejection ofdeliveries or, in the extreme, contract termination. Our profitability may be negatively affected if we are unable to seek protection during adverse economicconditions or if we incur financial or other economic penalties as a result of these provisions of our coal supply agreements. For more information about ourlong-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.The 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.38Table of ContentsIn 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, 2017, we derived approximately 17% of our total coal revenues from sales to our three largest customers andapproximately 41% 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 of earnings. In the event that we are unable to effectively manage these new risks, our results of operations, financialposition or cash flow could be adversely affected by these activities.If we sustain cyber attacks or other security breaches that disrupt our operations, or that result in the unauthorized release of proprietary or 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.39Table of ContentsOur 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. 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. Forinstance, the Clean Power Plan, if implemented in its current form, would severely limit emissions of carbon dioxide which would adversely affect our abilityto sell coal. However, in April 2017, the EPA announced that it was initiating a review of the Clean Power Plan consistent with President Trump’s ExecutiveOrder 13783, and, in October 2017, the EPA published a proposed rule to formally repeal the Clean Power Plan. In December 2015, the United States and 195other countries reached an agreement (the “Paris Agreement” during the 21st Conference of the Parties to the United Nations Framework Convention onClimate Change, a long-term, international framework convention designed to address climate change over the next several decades. In June 2017, PresidentTrump announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement ondifferent terms or to establish a new framework agreement. The earliest permitted exit date under the Paris Agreement is four years from when the agreementtook effect in November 2016, or November 2020. Whether the United States will adhere to the Paris Agreement’s exit process is, and the terms on which theUnited States may reenter the Paris Agreement or a separately negotiated agreement are, uncertain at this time. However, any efforts to control and/or reducegreenhouse gas emissions by the United States or other countries that have also pledged “Nationally Determined Contributions,” or concerted conservationefforts that result in reduced electricity consumption, could adversely impact coal prices, our ability to sell coal and, in turn, our financial position and resultsof operations.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 more effectivepollution control equipment that reduces the need for low sulfur coal, or may cease operations, possibly reducing future demand for coal and a reduced needto construct new coal‑fueled power plants. Any switching of fuel sources away from coal, closure of existing coal‑fired plants, or reduced construction of newplants could have a material adverse effect on40Table of Contentsdemand for and prices received for our coal. Alternatively, less stringent air emissions limitations, particularly related to sulfur, to the extent enacted couldmake low sulfur coal less attractive, which could also have a material adverse effect on the demand for and prices received for our coal.You should see Item 1, “Environmental and Other Regulatory Matters” for more information about the various governmental regulations 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 and insurance companies associated withconcerns about environmental impacts of coal combustion, including perceived impacts on the global climate.Carbon dioxide, which is considered to be a greenhouse gas, is a by-product of burning coal. Global climate issues, including with respect 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 would severely limit emissions of carbon dioxide, possibly reducing future demand for coal. However, inApril 2017 the EPA announced that it was initiating a review of the Clean Power Plan consistent with President Trump’s Executive Order 13783, and inOctober 2017 published a proposed rule to formally repeal the Clean Power Plan. Additionally, a number of governments pledged to control and reducegreenhouse gas emissions under the Paris Agreement, which may impact demand for coal resources despite the United States’ June 2017 announcement that itintends to withdraw its commitment.Future regulation of greenhouse gas emissions in the United States could occur pursuant to future U.S. treaty obligations, statutory or regulatorychanges and the federal, state or local level or otherwise. Enactment of laws or passage of regulations regarding greenhouse emissions from the combustion ofcoal by the U.S., some of its states or other countries, or other actions to limit emissions could result in electricity generators switching from coal to other fuelsources or coal-fueled power plant closures. You should see Item 1, “Environmental and Other Regulatory Matters-Climate Change” for more informationabout governmental regulations relating to greenhouse gas emissions.In addition, certain banks, other financing sources and insurance companies have taken actions to limit available financing and insurance coveragefor the development of new coal-fueled power plants and coal miners and utilities that derive a majority of their revenue from thermal coal, which also mayadversely impact the future global demand for coal. Further, there have been recent efforts by members of the general financial and investment communities,such as investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to divest themselves and to promote the divestmentof securities issued by companies involved in the fossil fuel extraction market, such as coal producers. Those entities also have been pressuring lenders tolimit financing available to such companies. These efforts may adversely affect the market for our securities and our ability to access capital and financialmarkets 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 applicable41Table of Contentsregulatory processes, and otherwise engage in the permitting process, including bringing citizens’ lawsuits to challenge the issuance of permits, the validityof environmental impact statements or performance of mining activities. Accordingly, required permits may not be issued or renewed in a timely fashion or atall, or permits issued or renewed may be conditioned in a manner that may restrict our ability to efficiently and economically conduct our mining activities,any of which would materially reduce our production, cash flow and profitability.Federal or state regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances,which could materially and adversely affect our ability to meet our customers’ demands.Federal or state regulatory agencies have the authority under certain circumstances following significant health and safety incidents, such 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. Failure to comply with these laws and regulationsmay result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance ofinjunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limitingproduction from our operations. We may incur material costs and liabilities resulting from claims for damages to property or injury to persons arising from ouroperations. If we are pursued for sanctions, costs and liabilities in respect of these matters, our mining operations and, as a result, our profitability could bematerially 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.42Table 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. On May 22, 2017, the United States District Court for the Southern District of West Virginia granted theremaining subsidiary’s motion to dismiss plaintiffs’ Seventh Supplemental and Amended Complaint after the D.C. Circuit Court of Appeals affirmed theEPA’s final determination rescinding Mingo Logan Coal Company’s 404 authorization regarding Pigeonroost Branch and Oldhouse Branch. The D.C.Circuit Court of Appeals decision finally resolved a lawsuit filed by Mingo Logan against EPA challenging EPA’s authority to rescind a 404 permitauthorization.43Table 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. Furthermore, pursuant to aFebruary 2017 executive order and the proposed rule published on July 27, 2017, the EPA will review and revise the definition of “waters of the UnitedStates,” which may include re-codifying the definition that currently governs administration of the Clean Water Act. Adoption of more stringent applicationof existing regulations may materially increase our costs and adversely affect our operations.Risks Related to Income TaxesRecent U.S. tax legislation may materially adversely affect our financial condition, results of operations and cash flows.The ability to use our net operating losses (“NOLs”) and alternative minimum tax (“AMT”) credits has been limited by the “ownership change”under Section 382 of the Internal Revenue Code (the “Code”) that occurred on our emergence from bankruptcy (“the Emergence Ownership Change”). Thelimitation resulting from the Ownership Change is substantial and applies to all NOLs and AMT tax credits existing at the time of the Ownership Change.The limitation resulting from the Emergence Ownership Change may have a significant impact on our ability to offset future taxable income withcarryforward net operating losses. NOLs and AMT credits generated after the Emergence Ownership Change are generally not subject to the limitations.As a result of the discharge of debt in the Chapter 11 Cases, we and our subsidiaries were required to reduce the amount of our NOLs and AMTcredits and other tax attributes existing at the end of 2016.Recently enacted U.S. tax legislation has significantly changed the U.S. federal income taxation of U.S. corporations. Changes include the reductionof the U.S. corporate income tax rate, elimination of the AMT tax system, limitation of interest deductions and revision of the rules governing net operatinglosses. Many of these changes are effective immediately, without any transition periods or grandfathering for existing transactions.The legislation is unclear in many respects and could be subject to potential amendments and technical corrections, as well as interpretations andimplementing regulations by the Treasury and Internal Revenue Service (“IRS”), any of which could lessen or increase certain adverse impacts of thelegislation. In addition, it is unclear how these U.S. federal income tax changes will affect state and local taxation, which often uses federal taxable income asa starting point for computing state and local tax liabilities.While some of the changes made by the tax legislation may adversely affect us in one or more reporting periods and prospectively, other changesmay be beneficial on a going forward basis. We continue to work with our tax advisors to determine the full impact that the recent tax legislation as a wholewill have on us. We urge our investors to consult with their legal and tax advisors with respect to such legislation.ITEM 1B. UNRESOLVED STAFF COMMENTS.None.44Table of ContentsITEM 2. PROPERTIES.Our PropertiesAt December 31, 2017, we owned or controlled, primarily through long‑term leases, approximately 28,292 acres of coal land in Ohio, 1,060 acres ofcoal land in Maryland, 10,108 acres of coal land in Virginia, 359,160 acres of coal land in West Virginia, 98,488 acres of coal land in Wyoming, 267,857acres of coal land in Illinois, 34,446 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 20,165 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 81,436 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, 2017. Ourcoal reserve estimates at December 31, 2017 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.”45Table of ContentsThe following tables present our estimated assigned and unassigned recoverable coal reserves at December 31, 2017: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>2.5LeasedOwnedSurfaceground20152016Wyoming1,0251,019696362—8,8321,025 1,025—1,3181,115Colorado5347653——11,47653——535356Central App.6959102544—13,07662722473570Northern App.35323—35—13,018530—354048Illinois352015——3510,737305—353738Total1,2171,177401,041141359,3651,175421,0471701,4831,327(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)LeasedOwnedSurfacegroundWyoming2902444624248—8,446290—290—Colorado2822628——11,33928——28Central App.5144714241312,4822493318Northern App.19811583—195313,0099189—198Illinois28518996——28511,162592263282Total85261423828426730110,753388464326526(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, 2017 was $0.4 billion, consisting of $4.7 million of prepaid royalties and a net book value ofcoal lands and mineral rights of $0.4 billion.46Table 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. Please refer to 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.47Table of ContentsOn 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. In March 2017, the U.S. Secretary of Interior signed Secretarial Order 3348 lifting that moratorium andhalting the Federal Coal Program Programmatic Environmental Impact Statement that was in process at the time. Litigation is currently pending in the UnitedStates District Court for the District of Montana challenging the lifting of the moratorium as a violation of the National Environmental Policy Act, theMineral Leasing Act and the Federal Land Policy and Management Act. Although the Bureau of Land Management is now working to process coal leaseapplications and modifications expeditiously in accordance with regulations and guidance that existed before Secretarial Order 3338, which imposed themoratorium on new coal leases, any delay in the LBA process, including any delay caused by the now-lifted moratorium could prevent us from obtainingreplacement reserves when we require them. Also, the outcome of the government’s review is uncertain and could have a material and adverse impact on ourbusiness in any number of ways including by limiting our ability to mine reserves under ongoing or future applications, by increasing the costs or timeframeassociated with 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. Please see “Our inability to acquire additional coal reserves or our inability to develop coalreserves in an economically feasible manner may adversely affect our business,” contained in 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, 2017, approximately 24% 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 57,773 acres of property to other coal operators in 2017. We received royalty income of $4.1 million during 2017 from themining of approximately 1.2 million tons, $1.1 million during the period October 2 through December 31, 2016 from the mining of approximately0.4 million tons, $1.7 million during the period January 1 through October 1, 2016 from the mining of approximately 0.6 million tons, and $6.3 million in2015 from the mining of approximately 2.1 million tons on those properties. We have included reserves at properties leased by us to other coal operators inthe reserve figures set forth in this report.ITEM 3. LEGAL PROCEEDINGS.We are involved in various claims and legal actions arising in the ordinary course of business, including employee injury claims. After conferringwith counsel, it is the opinion of management that the ultimate resolution of these claims, to the extent not previously provided for, will not have a materialadverse effect on our consolidated financial condition, results of operations or liquidity.ITEM 4. MINE SAFETY DISCLOSURES. The statement concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street 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, 2017.48Table of ContentsPART IIITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITYSECURITIES.Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “ARCH” and has been trading since October 5, 2016 upon ouremergence from bankruptcy. No prior established public trading market existed for this newly issued common stock prior to this date. Based uponinformation provided by our transfer agent, as of February 16, 2018, we had four stockholders of record.Holders of our common stock are entitled to receive dividends when they are declared by our Board of Directors. We paid dividends on our commonstock totaling $24.4 million in 2017. There is no assurance as to the amount or payment of dividends in the future because they will be subject to ongoingBoard review and authorization will be based on a number of factors, including business and market conditions, the Company’s future financial performanceand other capital priorities.The following table sets forth for each period indicated the dividends paid per common share and the per share high and low closing prices for ourcommon stock as reported on the NYSE for the periods presented: High Low Dividends percommon shareYear Ended December 31, 2017 First quarter$79.27 $63.24 $—Second quarter77.59 60.13 0.35Third quarter81.09 67.39 0.35Fourth quarter94.57 68.95 0.35 Year Ended December 31, 2016 First quarter$— $— $—Second quarter— — —Third quarter— — —Fourth quarter (from October 5, 2016)86.47 59.05 —49Table of ContentsStockholder Return Performance PresentationThe following graph compares the cumulative 15-month total return of holders of Arch Coal, Inc.’s common stock with the cumulative total returns ofthe S&P Midcap 400 index and a customized peer group of three companies: Cloud Peak Energy Inc., Cnx Resources Corp and Westmoreland CoalCompany. The graph assumes that the value of the investment in our common stock, the S&P Midcap 400 index, and in the peer group (includingreinvestment of dividends) was $100 on October 5, 2016 and tracks it through December 31, 2017. 10/5/201610/1611/1612/161/172/173/174/17 Arch Coal, Inc.100.00116.48123.86123.89114.27114.06109.43111.49S&P Midcap 400100.0097.32105.12107.42109.22112.08111.65112.58Peer Group100.0090.38110.0399.0193.2584.5689.5578.93 5/176/177/178/179/1710/1711/1712/17Arch Coal, Inc.112.88108.94121.33127.97114.94122.44132.87149.93S&P Midcap 400112.03113.85114.85113.09117.52120.18124.59124.87Peer Group74.3575.9183.9772.5884.4481.2983.6587.92The stock price performance included in this graph is not necessarily indicative of future stock price performance.50Table of ContentsIssuer Purchases of Equity SecuritiesDuring April 2017, the Board of Directors of Arch Coal, Inc. authorized a new share repurchase program for up to $300 million of its common stock. InOctober 2017, the Company’s Board of Directors approved an incremental $200 million increase to the share repurchase program bringing the totalauthorization to $500 million. Below is a table showing the share repurchase activity in 2017:2017:Total Number ofShares PurchasedAverage Price Paidper ShareTotal Number ofShares Purchased asPart of PubliclyAnnounced ProgramApproximate DollarValue of Shares that MayYet Be Purchased Underthe Plan (in thousands)1st quarter—$——$—2nd quarter710,701$71.82710,701448,9573rd quarter2,208,133$75.492,208,133282,2724th quarter1,058,381$79.731,058,381197,892Total shares repurchased3,977,215$75.963,977,215 The timing of any future share repurchases, and the ultimate number of shares purchased, will depend on a number of factors, including business andmarket conditions, the Company’s future financial performance and other capital priorities. The shares will be acquired in the open market or through privatetransactions in accordance with the Securities and Exchange Commission requirements. The share repurchase program has no termination date, but may beamended, suspended or discontinued at any time and does not commit the Company to repurchase shares of its common stock. The actual number and valueof the shares to be purchased will depend on the performance of the Company’s stock price and other market conditions.51Table of ContentsITEM 6. SELECTED FINANCIAL DATA. SuccessorPredecessor(In thousands, except per share data)Year EndedDecember 31,2017October 2throughDecember 31,2016January 1throughOctober 1, 2016Year EndedDecember 31,2015Year EndedDecember 31,2014Year EndedDecember 31,2013Statement of Operations Data: (1)(1)(2) (3)Revenues$2,324,623$575,688$1,398,709$2,573,260$2,937,119$3,014,357Asset impairment and mine closure costs——129,2672,628,30324,113220,879Goodwill impairment—————265,423Income (loss) from operations232,39646,118(257,138)(2,865,063)(149,531)(663,141)Interest expense(26,905)(11,241)(135,888)(397,979)(390,946)(381,267)Non-operating expenses(4,945)(759)1,627,828(27,910)—(42,921)Income (loss) from continuing operations238,45033,4491,242,081(2,913,142)(558,353)(745,228)Net income (loss) attributable to Arch Coal238,45033,4491,242,081(2,913,142)(558,353)(641,832)Basic earnings (loss) per common share$10.05$1.34$58.33$(136.86)$(26.31)$(30.26)Diluted earnings (loss) per common share$9.84$1.31$58.28$(136.86)$(26.31)$(30.26)Balance Sheet Data: Total assets$1,979,632$2,136,597$2,123,829$5,041,881$8,346,362$8,896,571Working capital496,913566,391522,465(4,361,009)1,023,3571,293,849Current maturities of debt15,78311,0386,6625,042,35312,19114,419Long-term debt, less current maturities310,134351,841353,27230,9535,064,8185,043,454Other long-term obligations669,552725,948786,015755,283695,881717,174Noncurrent deferred income tax liability————422,809413,546Arch Coal stockholders’ equity665,865746,577687,483(1,244,289)1,668,1542,253,249Cash Flow Data: Cash provided by (used in) operating activities396,47384,192(228,218)(44,367)(33,582)55,742Depreciation, depletion and amortization, includingamortization of sales contracts, net176,44933,400190,853370,534405,561438,247Capital expenditures59,20515,21482,434119,024147,286296,984Net proceeds from the issuance of long term debt298,500———(4,519)623,511Payments to retire debt, including redemption premium325,684————628,660Purchases of treasury stock301,512 Dividend payments24,369———2,12325,475Operating Data: Tons sold98,21826,81267,128127,632134,360139,607Tons produced96,68626,61966,658126,820132,614136,613Tons purchased from third parties1,5321934811,2871,1822,92552Table 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 to theConsolidated Financial Statements, “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 6 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.The selected financial information presented above for the year ended December 31, 2017; the period October 2 through December 31, 2016, the periodfrom January 1 through October 1, 2016, and the years ended December 31, 2015, 2014 and 2013 was derived from, and is qualified by, reference to ourConsolidated Financial Statements, including the notes thereto, contained elsewhere herein. The selected financial information should be read inconjunction with the Consolidated Financial Statements and related notes and Item 7, “Management’s Discussion and Analysis of Financial Condition andResults 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 year ended December 31, 2017 benefited from strength in both the metallurgical and international thermal coal markets, while thedomestic thermal market was largely stable. Metallurgical coal markets remained volatile throughout 2017 with several notable spikes in promptinternational pricing. Despite the volatility, prompt international pricing at all times in 2017 remained at levels that supported significant cash margins forour low cost metallurgical operations. We believe the volatility seen in 2017 is an indication of a global market that is in fairly tight balance. Years of globalunderinvestment in the industry and a return of more robust economic growth have led to a supply and demand balance that is sensitive to any significantsupply disruption. Throughout the prompt pricing volatility of 2017 our realized net back prices remained fairly stable. This stability was due to havingcommitted and priced significant volumes prior to the beginning of the year, and timing of specific index based pricing mechanisms and pricingnegotiations. Future volatility in prompt international pricing will likely have a greater impact on realized net back pricing as we have elected to sell less ofour planned 2018 production volumes on a full year fixed price basis.Domestic thermal coal markets remained at levels that supported positive cash margins at all of our thermal operations throughout 2017. Natural gasprices remained tightly range bound for effectively the full year, as supply and demand for the competing fuel largely remained in balance. Late in the year,natural gas production levels began to increase, pressuring prices before increased seasonal heating demand drove natural gas prices higher. Natural gaspricing at the levels encountered in 2017 allowed some thermal coals, particularly Powder River Basin coals, to compete economically for electric generationin many regions of the country. Throughout the year, international thermal markets supported west coast export shipments from certain of our operations.Additionally, pricing in international thermal coal markets strengthened in the second half of the year increasing the opportunity for certain of our operationsto economically ship coal into both the Atlantic and Pacific thermal coal markets.Filing Under Chapter 11 of the United States Bankruptcy CodeOn January 11, 2016 (the “Petition Date”), Arch Coal and substantially all of its wholly owned domestic subsidiaries (the “Filing Subsidiaries” and,together with Arch Coal, the “Debtors”; the Debtors, solely following the effective date of the Plan, the “Reorganized Debtors”) filed voluntary petitions forreorganization (collectively, the “Bankruptcy Petitions”) under Chapter 11 of Title 11 of the U.S. Code (the “Bankruptcy Code”) in the United StatesBankruptcy Court for the Eastern District of Missouri (the “Court”). The Debtors’ Chapter 11 Cases (collectively, the “Chapter 11 Cases”) were jointlyadministered under the caption In re Arch Coal, Inc., et al. Case No. 16-40120 (lead case). During the Chapter 11 Cases, each Debtor operated its53Table of Contentsbusiness as a “debtor in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and theorders of the Court.Upon emergence from bankruptcy on October 5, 2016, Arch Coal applied the provisions of fresh start accounting effective October 1, 2016 whichresulted in Arch becoming a new entity for financial reporting purposes. Accordingly, the consolidated financial statements and accompanying footnotes onor after October 1, 2016 are not comparable to the consolidated financial statements prior to that date. References to “Successor” in the consolidated financialstatements and footnotes are in reference to reporting dates on or after October 2, 2016; references to “Predecessor” in the consolidated financial statementsand footnotes are in reference to reporting dates through October 1, 2016 which includes the impact of the Plan provisions and the application of fresh startaccounting. Results of Operations - SuccessorYear Ended December 31, 2017 and Period from October 2 through December 31, 2016Revenues. Our revenues include sales to customers of coal produced at our operations and coal purchased from third parties. Transportation costs areincluded in cost of coal sales and amounts billed by us to our customers for transportation are included in revenues.Coal sales. The following table summarizes information about our coal sales for the year ended December 31, 2017 and the period from October 2through December 31, 2016: Successor Year Ended December31, 2017 October 2 throughDecember 31, 2016 (In thousands)Coal sales $2,324,623 $575,688Tons sold 98,218 26,812 Coal sales for the year ended December 31, 2017 by segment were approximately 44% Powder River Basin, 38% Metallurgical, and 17% Other. Tonssold for the year by segment were approximately 82% Powder River Basin, 8% Metallurgical, and 9% Other. Coal sales for the period from October 2 throughDecember 31, 2016 by segment were approximately 48% Powder River Basin, 35% Metallurgical, and 17% Other. Tons sold for the period by segment wereapproximately 81% Powder River Basin, 9% Metallurgical, and 10% Other. See discussion in “Operational Performance” below for further information aboutregional results.Costs, expenses and other. The following table summarizes costs, expenses and other components of operating income for year ended December 31,2017 and the period from October 2 through December 31, 2016: Successor Year Ended December31, 2017October 2 throughDecember 31, 2016 (In thousands)Cost of sales (exclusive of items shown separately below) $1,843,093 $470,644Depreciation, depletion and amortization 122,464 32,604Accretion on asset retirement obligations 30,209 7,634Amortization of sales contracts, net 53,985 796Change in fair value of coal derivatives and coal trading activities, net 7,222 396Selling, general and administrative expenses149,31486,821 22,836Gain on sale of Lone Mountain Processing, Inc. (21,297) —Other operating (income) expense, net (30,270) (5,340)Total costs, expenses and other $2,092,227 $529,57054Table of ContentsCost of sales. Our cost of sales for the year ended December 31, 2017 consisted primarily of labor related costs (approximately 27%), repairs andsupplies (approximately 35%), operating taxes and royalties (approximately 21%), and transportation costs (approximately 14%). For the period fromOctober 2 through December 31, 2016, our cost of sales consisted primarily of labor related costs (approximately 25%), repairs and supplies (approximately33%), operating taxes and royalties (approximately 22%), and transportation costs (approximately 12%). See discussion in “Operational Performance” belowfor information about segment cost results. Depreciation, depletion and amortization. Our depreciation, depletion and amortization costs for the year ended December 31, 2017 consist ofdepreciation of plant and equipment (approximately 60%), depletion of reserves (approximately 19%), and amortization of development costs(approximately 21%). For the period from October 2 through December 31, 2016 these costs consist of depreciation of plant and equipment (approximately63%), depletion of reserves (approximately 20%), and amortization of development costs (approximately 17%). This reflects the application of fresh startaccounting. For further information on fresh start accounting, please see Note 3 to the Consolidated Financial Statements, “Emergence from Bankruptcy andFresh Start Accounting.” Accretion on asset retirement obligation. For the year ended December 31, 2017, approximately 67%, and for the period from October 2 throughDecember 31, 2016 approximately 66% of the accretion on our asset retirement obligation is attributable to our large surface operations in the Powder RiverBasin.Selling, general and administrative expenses. For the year ended December 31, 2017, selling, general and administrative expenses consist primarilyof compensation costs of $54.9 million, and professional services and usage and maintenance agreements of $20.7 million. For the period from October 2through December 31, 2016 , selling, general and administrative expenses consist primarily of compensation costs of $15.3 million, and professional servicesand usage and maintenance agreements of $5.1 million.Gain on sale of Lone Mountain Processing, Inc. During the year ended December 31, 2017 we sold Lone Mountain Processing Inc. and CumberlandRiver Coal LLC to Revelation Energy LLC, generating a gain of approximately $21.3 million. For further information on the sale of Lone MountainProcessing Inc. and Cumberland River Coal LLC to Revelation Energy LLC, please see Note 5 to the Consolidated Financial Statements, “Divestitures.”Other operating (income) expense, net. Other operating (income) expense, net for the year ended December 31, 2017 consists primarily ofmiscellaneous revenues including royalties, transloading fees, insurance recoveries, and net gains on asset sales totaling $31.6 million, and net income fromequity investments of $8.6 million, partially offset by miscellaneous expenses primarily related to our land company of $9.8 million. Other operating(income) expense, net for the period from October 2 through December 31, 2016 consists primarily of miscellaneous revenues including royalties and netgains on asset sales of $5.0 million and net income from equity investments of $1.7 million, partially offset by miscellaneous expenses primarily related toour land company of $1.4 million.Non-operating expense. The following table summarizes non-operating expense for the year ended December 31, 2017 and the period from October2 through December 31, 2016: Successor Year Ended December31, 2017 October 2 throughDecember 31, 2016 (In thousands)Net loss resulting from early retirement of debt and debt restructuring$(2,547) $—Reorganization income (loss), net$(2,398) $(759)Total nonoperating expense$(4,945) $(759)Nonoperating expenses in the year ended December 31, 2017 are related to efforts to replace our securitization facility and expenses associated withour Chapter 11 reorganization. Nonoperating expenses for the period from October 2 through December 31, 2016 are expenses associated with our Chapter11 reorganization. See further discussion in Note 3 to the Consolidated Financial Statements, “Emergence from Bankruptcy and Fresh Start Accounting”, andNote 14, “Debt and Financing Arrangements.”55Table of ContentsProvision for income taxes. The following table summarizes our provision for income taxes for the year ended December 31, 2017 and the periodfrom October 2 through December 31, 2016: Successor Year Ended December31, 2017 October 2 throughDecember 31, 2016 (In thousands)Provision for (benefit from) income taxes$(35,255) $1,156On December 22, 2017 the Tax Cut and Jobs Act of 2017 (“the Act”) was signed into law making significant changes to the Internal Revenue Code.Changes include, but are not limited to, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after December 31, 2017, theelimination of the corporate alternative minimum tax regime effective for tax years beginning after December 31, 2017, implementation of a process wherebycorporations with unused alternative minimum tax credits will be refunded during 2018-2022, the transition of U.S. international taxation from a worldwidetax system to a territorial system, a one-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings as of December 31, 2017,further limitation on the deductibility of certain executive compensation, allowance for immediate capital expensing of certain qualified property, andlimitations on the amount of interest expense deductible beginning in 2018. We have provided our best estimate of the impact of the Act in our year-endincome tax provision in accordance with our understanding of the Act and guidance available as of the date of this filing and as a result have recorded $35.7million as an additional income tax benefit in the fourth quarter of 2017, the period in which the legislation was enacted. A $35.7 million benefit wasrecorded from the release of a valuation allowance offsetting alternative minimum tax credits that have become refundable by the Act, as well as carrybackclaims filed in the fourth quarter related to specified liability losses that resulted in claims for refund of previously paid alternative minimum taxes. Seefurther discussion in Note 15, to the Consolidated Financial Statements “Taxes.”56Table of ContentsOperational Performance- SuccessorYear Ended December 31, 2017 and Period 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 by excluding transactions thatare not indicative of our core operating performance. Adjusted EBITDAR is not a measure of financial performance in accordance with generally acceptedaccounting principles, and items excluded from Adjusted EBITDAR are significant in understanding and assessing our financial condition. Therefore,Adjusted EBITDAR should not be considered in isolation, nor as an alternative to net income, income from operations, cash flows from operations or as ameasure of our profitability, liquidity or performance under generally accepted accounting principles. Furthermore, analogous measures are used by industryanalysts to evaluate the Company’s operating performance. Investors should be aware that our presentation of Adjusted EBITDAR may not be comparable tosimilarly titled measures used by other companies.The following table shows operating results of continuing coal operations for the year ended December 31, 2017 and the period from October 2through December 31, 2016. SuccessorYear Ended December31, 2017 October 2 throughDecember 31, 2016Powder River Basin Tons sold (in thousands)80,604 21,824Coal sales per ton sold$12.49 $12.41Cash cost per ton sold$10.53 $9.88Cash margin per ton sold$1.96 $2.53Adjusted EBITDAR (in thousands)$158,882 $55,765Metallurgical Tons sold (in thousands)8,192 2,442Coal sales per ton sold$90.17 $65.61Cash cost per ton sold$60.76 $52.98Cash margin per ton sold$29.41 $12.63Adjusted EBITDAR (in thousands)$243,616 $30,819Other Thermal Tons sold (in thousands)9,205 2,510Coal sales per ton sold$34.85 $34.01Cash cost per ton sold$24.20 $21.79Cash margin per ton sold$10.65 $12.22Adjusted EBITDAR (in thousands)$102,006 $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 year ended December 31, 2017 reflects relatively stable natural gas prices throughout the year atlevels that allowed Powder River Basin coal to be competitive for electric generation in many regions of the country. Our tons sold volume fluctuatedthroughout the year with seasonal increases and decreases in heating and cooling demand. Customers in general are shifting to shorter term purchasecontracts, and more actively managing delivery volumes to match their seasonal demand fluctuations. Our cash cost per ton sold was impacted by thesevolume fluctuations and increased diesel pricing. We are actively managing our operations to enhance our flexibility to respond to these volume fluctuationsefficiently. Our focus remains on cost control efforts in this dynamic market. We expect future demand for Powder River Basin coal will be largely dependenton natural gas pricing and seasonal demand factors.Adjusted EBITDAR for the period from October 2 through December 31, 2016 benefited from cost control efforts and rebounding demand driven byrising natural gas prices that increased the competitiveness of Powder River Basin coal for57Table of Contentselectric generation versus the competing fuel. Rising gas prices resulted from favorable summer heat, increased natural gas exports, both pipeline andliquefied natural gas, and flat to slightly declining natural gas production. Cost control efforts included adjusting operations to align with current marketvolume expectations.Metallurgical — Adjusted EBITDAR for the year ended December 31, 2017 benefited from sustained strength in international pricing formetallurgical coal. As discussed above, prompt international coking coal prices moved significantly during the year, but always remained at levels thatprovided significant margins for our low cost operations. Improved coal sales per ton sold was partially offset by the related increase in royalties andoperating taxes. During the third quarter of the year, we experienced adverse geologic conditions at both the Leer and Mountain Laurel longwall operations,limiting production volume at that time. Conditions at those operations returned to a more normal state later in the year. Sales volumes were also negativelyimpacted at year end by logistics and weather issues that pushed some scheduled shipments out of the year. Our metallurgical segment sold 6.4 million tonsof coking coal and 1.8 million tons of associated thermal and PCI coal in the year ended December 31, 2017. Longwall operations accounted forapproximately 57% of our shipment volume in the year.Adjusted EBITDAR for the period from October 2 through December 31, 2016 benefited from the significant increase in international pricing formetallurgical coal. Supply shortages driven by a Chinese mandate to restrict its domestic supply, supply rationalization in North America, years of globalunderinvestment in the industry, and some specific international supply disruptions, particularly in Australia, resulted in a significant increase ininternational prompt metallurgical coal prices. Our ability to take advantage of the rapid increase in prompt international pricing was muted due to havingsignificant volumes for the period committed and priced prior to the rapid increase. Our metallurgical segment sold 1.9 million tons of metallurgical coal and0.5 million tons of associated thermal coal in the period from October 2 through December 31, 2016. Longwall operations accounted for approximately 55%of our shipment volume in the period. Late in the period prompt international metallurgical pricing began to retreat as loosening of Chinese supplyrestrictions and easing of supply disruptions began to mitigate the supply shortage.Other Thermal— Adjusted EBITDAR for the year ended December 31, 2017 benefited from the stable natural gas pricing discussed in the PowderRiver Basin segment discussion above, and international thermal coal prices that supported certain export sales. These benefits were recognized throughoutthe year at our low cost West Elk longwall operation which has exposure to the Pacific international thermal markets. Later in the year Atlantic internationalthermal coal prices rose to levels that made export opportunities economic for our Coal Mac operation.Adjusted EBITDAR for the period from October 2 through December 31, 2016 benefited from the increased natural gas pricing discussed in thePowder River Basin segment discussion above, and increased international thermal prices. These benefits were primarily recognized at our West Elkoperation where domestic opportunities increased and export opportunities became economic. Partially offsetting those positive trends were operating issuesat our Viper operation’s largest customer that significantly reduced sales volume in the period.Results of Operations - PredecessorPeriod from January 1 through October 1, 2016 and Year Ended December 31, 2015Revenues. Our revenues include sales to customers of coal produced at our operations and coal purchased from third parties. Transportation costs areincluded in cost of coal sales and amounts billed by us to our customers for transportation are included in revenues.Coal sales. The following table summarizes information about our coal sales for the period from January 1 through October 1, 2016 and the yearended December 31, 2015. Predecessor January 1 throughOctober 1, 2016 Year Ended December31, 2015 (In thousands)Coal sales $1,398,709 $2,573,260Tons sold 67,128 127,632 58Table of ContentsCoal 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. Coal sales for the yearended December 31, 2015 by segment were approximately 56% Powder River Basin, 25% Metallurgical, and 17% Other. Tons sold for the year by segmentwere approximately 85% Powder River Basin, 7% Metallurgical, and 8% Other. See discussion in “Operational Performance” below for further informationabout 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 and the year ended December 31, 2015. Predecessor January 1 throughOctober 1, 2016 Year Ended December31, 2015 (In thousands)Cost of sales (exclusive of items shown separately below) $1,264,464 $2,172,753Depreciation, depletion and amortization 191,581 379,345Accretion on asset retirement obligations 24,321 33,680Amortization of sales contracts, net (728) (8,811)Change in fair value of coal derivatives and coal trading activities, net 2,856 (1,583)Asset impairment and mine closure costs 129,267 2,628,303Losses from disposed operations resulting from Patriot Coal bankruptcy149,314— 116,343Selling, general and administrative expenses 59,343 98,783Other operating (income) expense, net (15,257) 19,510Total costs, expenses and other $1,655,847 $5,438,323Cost 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%). Our cost ofsales for the year ended December 31, 2015 consisted primarily of labor related costs (approximately 28%), repairs and supplies (approximately 36%),operating taxes and royalties (approximately 23%), and transportation costs (approximately 9%). See discussion in “Operational Performance” below forinformation 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%). Our depreciation, depletion and amortization costs for the year ended December 31, 2015 consist of depreciation of plant andequipment (approximately 50%), depletion of reserves (approximately 38%), and amortization of development costs (approximately 12%).Accretion on asset retirement obligation. Approximately 70% of the accretion on our asset retirement obligation for the period from January 1through October 1, 2016, and 66% of the accretion on our asset retirement obligation for the year ended December 31, 2015 was attributable to our largesurface 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.During the year ended December 31, 2015 continued market deterioration, particularly for Appalachian products, was an indicator of impairment ofcertain active and undeveloped properties. Impairment costs in the year ended December 31, 2015 include a significant portion of our assets at threeoperating complexes, and a significant portion of our undeveloped coal reserves value.59Table of ContentsSelling, general and administrative expenses. Total selling, general and administrative expenses for the period from January 1 through October 1,2016 consist primarily of compensation costs of $38.5 million, and professional services and usage and maintenance agreements of $12.0 million. For theyear ended December 31, 2015 total selling, general and administrative expenses consist primarily of compensation costs of $56.5 million, and professionalservices and usage and maintenance agreements of $25.8 million.Losses 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 7, “Losses from disposed operations resulting from Patriot Coal bankruptcy,” to the Consolidated Financial Statements.Other operating (income) expense, net. Other operating (income) expense, net for the period from January 1 through October 1, 2016 consistsprimarily of miscellaneous revenues including royalties and net gains on asset sales of $18.1 million and net income from equity investments of $5.3 million,partially offset by miscellaneous expenses primarily related to our land company of $8.1 million. Other operating (income) expense, net for the year endedDecember 31, 2015 consists primarily of liquidated damages on logistics contracts of $52.9 million and miscellaneous expenses primarily related to our landcompany of $20.7 million partially offset by a $24 million gain from a contract settlement, miscellaneous revenues including royalties and net gains on assetsales of $22.2 million and net income from equity investments of $7.9 million. Non-operating expense. The following table summarizes non-operating expense for the period from January 1 through October 1, 2016 and the yearended December 31, 2015. Predecessor January 1 throughOctober 1, 2016 Year Ended December31, 2015 (In thousands)Net loss resulting from early retirement of debt and debt restructuring$(2,213) $(27,910)Reorganization income (loss), net1,630,041 —Total non-operating (expense) benefit$1,627,828$(27,910)Nonoperating expenses in the period from January 1 through October 1, 2016 related to our various debt restructuring activities and Chapter 11reorganization. Nonoperating expenses in the year ended December 31, 2015 related to our various debt restructuring activities. For further information onour successful reorganization, please see Note 3 to the Consolidated Financial Statements, “Emergence from Bankruptcy and Fresh Start Accounting.”Benefit from income taxes. The following table summarizes our benefit from income taxes for the period from January 1 through October 1, 2016 andthe year ended December 31, 2015. Predecessor January 1 throughOctober 1, 2016 Year Ended December31, 2015 (In thousands)Benefit from income taxes$(4,626) $(373,380)The income tax benefit in the year ended December 31, 2015 was largely due to the $2.6 billion in asset impairment losses recorded in 2015,partially offset by the increase of a valuation allowance relating to both federal and state net operating loss carryforwards. See further discussion in Note 15 tothe Consolidated Financial Statements, “Taxes,”.60Table 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 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 by excluding transactions thatare not indicative of our core operating performance. Adjusted EBITDAR is not a measure of financial performance in accordance with generally acceptedaccounting principles, and items excluded from Adjusted EBITDAR are significant in understanding and assessing our financial condition. Therefore,Adjusted EBITDAR should not be considered in isolation, nor as an alternative to net income, income from operations, cash flows from operations or as ameasure of our profitability, liquidity or performance under generally accepted accounting principles. Furthermore, analogous measures are used by industryanalysts to evaluate the Company’s operating performance. Investors should be aware that our presentation of Adjusted EBITDAR may not be comparable tosimilarly 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 theyear ended December 31, 2015. PredecessorJanuary 1 throughOctober 1, 2016 Year Ended December31, 2015Powder River Basin Tons sold (in thousands)54,911 108,481Coal sales per ton sold$13.01 $13.15Cash cost per ton sold$10.95 $10.54Cash margin per ton sold$2.06 $2.61Adjusted EBITDAR (in thousands)$113,185 $281,039Metallurgical Tons sold (in thousands)6,692 8,352Coal sales per ton sold$53.15 $66.62Cash cost per ton sold$51.40 $58.36Cash margin per ton sold$1.75 $8.26Adjusted EBITDAR (in thousands)$11,851 $70,450Other Thermal Tons sold (in thousands)5,181 9,764Coal sales per ton sold$36.16 $37.32Cash cost per ton sold$30.28 $28.01Cash margin per ton sold$5.88 $9.31Adjusted EBITDAR (in thousands)$31,448 $42,734 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 period from January 1 through October 1, 2016 was negatively impacted by demand destructiondriven by historically low natural gas prices that limited the competitiveness of Powder River Basin coal for electric generation versus the competing fuel.The low natural gas prices were driven by mild winter weather and record natural gas production levels.Adjusted EBITDAR for the year ended December 31, 2015 benefited from pricing a significant portion of 2015 tons sold following the harsh 2013-2014 winter season when the market was strong. Cost benefited from lower diesel fuel pricing and cost control efforts. Natural gas pricing fell to historicallylow levels due to mild winter weather in late 2015, and the competing fuel began to dispatch for electrical generation ahead of Power River Basin coal insome areas. This decrease in coal burn led to increasing generator stockpiles, further depressing demand. 61Table of ContentsMetallurgical — Adjusted EBITDAR for the period from January 1 through October 1, 2016 was negatively impacted by declines in metallurgicalcoal prices. Years of global oversupply from anemic economic growth and international overproduction, particularly from Australia, drove pricing down tolevels that were unprofitable for most North American producers. Our metallurgical segment sold 5.1 million tons of metallurgical coal and 1.6 million tonsof associated thermal coal in the period from January 1 through October 1, 2016. During the period we continued shifting volume to our lower cost Leeroperation. Longwall operations accounted for approximately 65% of our shipment volume in the period.Adjusted EBITDAR for the year ended December 31, 2015 was negatively impacted by declining metallurgical coal prices. Years of globaloversupply from anemic economic growth and international overproduction, particularly from Australia, continued pressuring prices downward. During theyear we shifted volume to lower cost operations, particularly the Leer operation. Longwall operations accounted for 59% of our shipment volume in 2015.Other Thermal— Adjusted EBITDAR for the period from January 1 through October 1, 2016 was negatively impacted by demand destruction drivenby historically low natural gas prices discussed in the Powder River Basin segment discussion above, and the lack of economic export opportunities. Theseconditions severely restricted tons sold and coal sales per ton sold at our West Elk and Coal Mac operations.Adjusted EBITDAR for the year ended December 31, 2015 was negatively impacted by declining tons sold at our West Elk and Coal Mac operationsrelated to low natural gas pricing and liquidated damages costs on logistics contracts. Reconciliation of NON-GAAP measuresNon-GAAP Segment coal sales per ton soldNon-GAAP Segment coal sales per ton sold is calculated as segment coal sales revenues divided by segment tons sold. Segment coal sales revenuesare adjusted for transportation costs, and may be adjusted for other items that, due to generally accepted accounting principles, are classified in “otherincome” on the statement of operations, but relate to price protection on the sale of coal. Segment coal sales per ton sold is not a measure of financialperformance in accordance with generally accepted accounting principles. We believe segment coal sales per ton sold provides useful information toinvestors as it better reflects our revenue for the quality of coal sold and our operating results by including all income from coal sales. The adjustments madeto arrive at these measures are significant in understanding and assessing our financial condition. Therefore, segment coal sales revenues should not beconsidered in isolation, nor as an alternative to coal sales revenues under generally accepted accounting principles. SuccessorYear Ended December 31, 2017Powder RiverBasinMetallurgicalOther ThermalIdle and OtherConsolidated(In thousands) GAAP Revenues in the consolidated statements ofoperations$1,024,197$887,839$396,504$16,083$2,324,623Less: Adjustments to reconcile to Non-GAAP Segment coal salesrevenue Coal risk management derivative settlements classified in"other income"——200—200Coal sales revenues from idled or otherwise disposedoperations not included in segments———15,06115,061Transportation costs17,437149,21275,4911,022243,162Non-GAAP Segment coal sales revenues$1,006,760$738,627$320,813$—$2,066,200Tons sold80,6048,1929,205 Coal sales per ton sold$12.49$90.17$34.85 62Table of Contents SuccessorOctober 2 through December 31, 2016Powder RiverBasinMetallurgicalOther ThermalIdle and OtherConsolidated(In thousands) GAAP Revenues in the consolidated statements ofoperations$275,703$200,377$97,382$2,226$575,688Less: Adjustments to reconcile to Non-GAAP Segment coal salesrevenue Coal risk management derivative settlements classified in"other income"——(112)—(112)Coal sales revenues from idled or otherwise disposedoperations not included in segments———2,1812,181Transportation costs4,82640,17012,1304557,171Non-GAAP Segment coal sales revenues$270,877$160,207$85,364$—$516,448Tons sold21,8242,4422,510 Coal sales per ton sold$12.41$65.61$34.01 PredecessorJanuary 1 through October 1, 2016Powder RiverBasinMetallurgicalOther ThermalIdle and OtherConsolidated(In thousands) GAAP Revenues in the consolidated statements ofoperations$726,747$437,069$213,052$21,841$1,398,709Less: Adjustments to reconcile to Non-GAAP Segment coal salesrevenue Coal risk management derivative settlements classified in"other income"——448—448Coal sales revenues from idled or otherwise disposedoperations not included in segments———19,36819,368Transportation costs12,55981,39025,2522,473121,674Non-GAAP Segment coal sales revenues$714,188$355,679$187,352$—$1,257,219Tons sold54,9116,6925,181 Coal sales per ton sold$13.01$53.15$36.16 PredecessorYear Ended December 31, 2015Powder RiverBasinMetallurgicalOther ThermalIdle and OtherConsolidated(In thousands) GAAP Revenues in the consolidated statements ofoperations$1,448,440$637,941$428,809$58,070$2,573,260Less: Adjustments to reconcile to Non-GAAP Segment coal salesrevenue Coal risk management derivative settlements classified in"other income"——(3,231)—(3,231)Coal sales revenues from idled or otherwise disposedoperations not included in segments———48,12648,126Transportation costs22,13781,55467,5989,944181,233Non-GAAP Segment coal sales revenues$1,426,303$556,387$364,442$—$2,347,132Tons sold108,4818,3529,764 Coal sales per ton sold$13.15$66.62$37.32 63Table of ContentsNon-GAAP Segment cash cost per ton soldNon-GAAP Segment cash cost per ton sold is calculated as segment cash cost of coal sales divided by segment tons sold. Segment cash cost of coalsales is adjusted for transportation costs, and may be adjusted for other items that, due to generally accepted accounting principles, are classified in “otherincome” on the statement of operations, but relate directly to the costs incurred to produce coal. Segment cash cost per ton sold is not a measure of financialperformance in accordance with generally accepted accounting principles. We believe segment cash cost per ton sold better reflects our controllable costsand our operating results by including all costs incurred to produce coal. The adjustments made to arrive at these measures are significant in understandingand assessing our financial condition. Therefore, segment cash cost of coal sales should not be considered in isolation, nor as an alternative to cost of salesunder generally accepted accounting principles. SuccessorYear Ended December 31, 2017Powder RiverBasinMetallurgicalOther ThermalIdle and OtherConsolidated(In thousands) GAAP Cost of sales in the consolidated statements ofoperations$863,836$646,911$298,229$34,118$1,843,093Less: Adjustments to reconcile to Non-GAAP Segment cash costof coal sales Diesel fuel risk management derivative settlementsclassified in "other income"(2,645)———(2,645)Transportation costs17,437149,21275,4911,022243,162Cost of coal sales from idled or otherwise disposedoperations not included in segments———28,06528,065Other (operating overhead, certain actuarial, etc.)———5,0315,031Non-GAAP Segment cash cost of coal sales849,044497,699222,738—1,569,480Tons sold80,6048,1929,205 Cash Cost Per Ton Sold$10.53$60.76$24.20 SuccessorOctober 2 through December 31, 2016Powder RiverBasinMetallurgicalOther ThermalIdle and OtherConsolidated(In thousands) GAAP Cost of sales in the consolidated statements ofoperations$220,714$169,532$66,811$13,586$470,644Less: Adjustments to reconcile to Non-GAAP Segment cash costof coal sales Diesel fuel risk management derivative settlementsclassified in "other income"363———363Transportation costs4,82540,17112,1304557,171Cost of coal sales from idled or otherwise disposedoperations not included in segments———5,8535,853Fresh start coal inventory fair value adjustment———7,3457,345Other (operating overhead, certain actuarial, etc.)———344344Non-GAAP Segment cash cost of coal sales$215,526$129,361$54,681$—$399,568Tons sold21,8242,4422,510 Cash Cost Per Ton Sold$9.88$52.98$21.79 64Table of Contents PredecessorJanuary 1 through October 1, 2016Powder RiverBasinMetallurgicalOther ThermalIdle and OtherConsolidated(In thousands) GAAP Cost of sales in the consolidated statements ofoperations$610,734$425,345$181,872$46,513$1,264,464Less: Adjustments to reconcile to Non-GAAP Segment cash costof coal sales Diesel fuel risk management derivative settlementsclassified in "other income"(3,361)—(276)(59)(3,696)Transportation costs12,56081,38925,2532,472121,674Cost of coal sales from idled or otherwise disposedoperations not included in segments———42,51342,513Other (operating overhead, certain actuarial, etc.)———1,5871,587Non-GAAP Segment cash cost of coal sales$601,535$343,956$156,895$—$1,102,386Tons sold54,9116,6925,181 Cash Cost Per Ton Sold$10.95$51.40$30.28 PredecessorYear Ended December 31, 2015Powder RiverBasinMetallurgicalOther ThermalIdle and OtherConsolidated(In thousands) GAAP Cost of sales in the consolidated statements ofoperations$1,157,258$568,971$340,738$105,785$2,172,753Less: Adjustments to reconcile to Non-GAAP Segment cash costof coal sales Diesel fuel risk management derivative settlementsclassified in "other income"(7,750)—(332)(80)(8,162)Transportation costs22,13781,55367,5989,945181,233Cost of coal sales from idled or otherwise disposedoperations not included in segments———79,29079,290Other (operating overhead, certain actuarial, etc.)———16,63016,630Non-GAAP Segment cash cost of coal sales$1,142,871$487,418$273,472$—$1,903,762Tons sold108,4818,3529,764 Cash Cost Per Ton Sold$10.54$58.36$28.01 65Table of ContentsReconciliation 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 by excluding transactions that are not indicative of our core operating performance. We useAdjusted EBITDAR to measure the operating performance of our segments and allocate resources to our segments. Adjusted EBITDAR is not a measure offinancial performance in accordance with generally accepted accounting principles, and items excluded from Adjusted EBITDAR are significant inunderstanding and assessing our financial condition. Therefore, Adjusted EBITDAR should not be considered in isolation, nor as an alternative to netincome, income from operations, cash flows from operations or as a measure of our profitability, liquidity or performance under generally acceptedaccounting principles. Investors should be aware that our presentation of Adjusted EBITDAR may not be comparable to similarly titled measures used byother companies. The table below shows how we calculate Adjusted EBITDAR. SuccessorPredecessor Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1through October1, 2016Year EndedDecember 31,2015(In thousands) Net income (loss) $238,450 $33,449$1,242,081 $(2,913,142)Income tax benefit (provision) (35,255) 1,156(4,626) (373,380)Interest expense, net 24,256 10,754133,235 393,549Depreciation, depletion and amortization 122,464 32,604191,581 379,345Accretion on asset retirement obligations 30,209 7,63424,321 33,680Amortization of sales contracts, net 53,985 796(728) (8,811)Asset impairment and mine closure costs — —129,267 2,628,303Losses from disposed operations resulting from Patriot Coalbankruptcy— —— 116,343Gain on sale of Lone Mountain Processing, Inc.(21,297) —— —Net loss resulting from early retirement of debt and debt restructuring2,547 —2,213 27,910Reorganization items, net2,398 759(1,630,041) —Fresh start coal inventory fair value adjustment— 7,345— —Adjusted EBITDAR 417,757 94,49787,303 283,797EBITDAR from idled or otherwise disposed operations 9,113 2,79514,514 23,605Selling, general and administrative expenses 86,821 22,83659,343 98,783Other (9,187) (2,385)(4,676) (11,962)Segment Adjusted EBITDAR from coal operations $504,504 $117,743$156,484 $394,223 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 year ended December 31, 2017, other consists primarily of net income from equity investments of $8.5 million.For the Successor period from October 2 through December 31, 2016, other consists primarily of net income from equity investments of $1.7 million.66Table of ContentsFor the Predecessor period from January 1 through October 1, 2016 Other consists primarily of net income from equity investments of $5.3 million.For the Predecessor year ended December 31, 2015 Other consists primarily of net income from equity investments of $7.9 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 prudently managing costs, including capital expenditures, maintaining a strong balance sheet, and insuringadequate liquidity.On April 27, 2017, our Board of Directors authorized a share repurchase program for up to $300 million of our common stock. On October 26, 2017our Board of Directors authorized an additional $200 million for our share repurchase program, bringing the total authorization to $500 million. During theyear ended December 31, 2017, we repurchased 3,977,215 shares of our stock for approximately $301.5 million. The timing of any future share purchases,and the ultimate number of shares to be purchased, will depend on a number of factors, including business and market conditions, our future financialperformance, and other capital priorities. The shares will be acquired in the open market or through private transactions in accordance with Securities andExchange Commission requirements.On April 27, 2017, our Board of Directors authorized a quarterly common stock cash dividend of $0.35 per share. During the year endedDecember 31, 2017, we paid three quarterly cash dividends of $0.35 per share, totaling approximately $24.4 million. On February 13, 2018 we announced anincreased in the quarterly dividend to $0.40 per share. The next dividend is scheduled to be paid on March 15, 2018 to stockholders of record at the close ofbusiness on March 5, 2018.Given the volatile nature of coal markets, we believe it is important to take a prudent approach to managing our balance sheet and liquidity. Ourdividend policy and share repurchase program will be implemented in a manner that will result in maintaining cash levels similar to those we have seen overthe past year. In the future, we will continue to evaluate our capital allocation initiatives in light of the current state of and our outlook for coal markets; theamount of our planned production that has been committed and priced; the capital needs of the business; and other strategic opportunities.On March 7, 2017, we entered into a senior secured term loan credit agreement in an aggregate principal amount of $300 million (the “New TermLoan Debt Facility”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent (in such capacities, the “Agent”), and theother financial institutions from time to time party thereto (collectively, the “Lenders”). The New Term Loan Debt Facility was issued at 99.50% of the faceamount and will mature on March 7, 2024. Proceeds from The New Term Loan Debt Facility were used to repay all outstanding obligations under ourpreviously existing term loan credit agreement, dated as of October 5, 2016.On September 25, 2017, we entered into the First Amendment (the “Amendment”) to the New Term Loan Debt Facility. The Amendment reduces theinterest rate on the term loan facility to, at our option, either (i) the London interbank offered rate (“LIBOR”) plus an applicable margin of 3.25%, subject to a1.00% LIBOR floor, or (ii) a base rate plus an applicable margin of 2.25%.The term loans provided under the New Term Loan Debt Facility (the “Term Loans”) are subject to quarterly principal amortization payments in anamount equal to $750,000. For further information regarding the New Term Loan Debt Facility see Note 14 to the Consolidated Financial Statements “Debtand Financing Arrangements”.67Table of ContentsDuring the second quarter of 2017, we entered into a series of interest rate swaps to fix a portion of the LIBOR interest payments due under the termloan. The interest rate swaps qualify for cash flow hedge accounting treatment and as such, the change in the fair value of the interest rate swaps are recordedon our Consolidated Balance Sheet as an asset or liability with the effective portion of the gains or losses reported as a component of accumulated othercomprehensive income and the ineffective portion reported in earnings. As interest payments are made on the term loan, amounts in accumulated othercomprehensive income will be reclassified into earnings through interest expense to reflect a net interest on the term loan equal to the effective yield of thefixed rate of the swap plus 3.25% which is the spread on the LIBOR term loan as amended. In the event that an interest rate swap is terminated prior tomaturity, gains or losses in accumulated other comprehensive income will remain deferred and reclassified into earnings in the periods which the hedgedforecasted transaction affects earnings. For further information regarding the interest rate swaps see Note 14 to the Consolidated Financial Statements “Debtand Financing Arrangements”.On April 27, 2017, we extended and amended our existing trade accounts receivable securitization facility which supports the issuance of letters ofcredit and requests for cash advances. The amendment to the Extended Securitization Facility decreases the borrowing capacity from $200 million to $160million and extends the maturity date to three years after the Securitization Facility Closing Date. Pursuant to the Extended Securitization Facility, we alsoagreed to a revised schedule of fees payable to the administrator and the providers of the Extended Securitization Facility. For further information regardingthe Extended Securitization Facility see Note 14 to the Consolidated Financial Statements “Debt and Financing Arrangements”.On April 27, 2017, we entered into a senior secured inventory-based revolving credit facility in an aggregate principal amount of $40 million (the“New Inventory Facility”) with Regions Bank (“Regions”) as administrative agent and collateral agent (in such capacities, the “Agent”), as lender andswingline lender (in such capacities, the “Lender”) and as letter of credit issuer. Availability under the New Inventory Facility is subject to a borrowing baseconsisting of (i) 85% of the net orderly liquidation value of eligible coal inventory, (ii) the lesser of (x) 85% of the net orderly liquidation value of eligibleparts and supplies inventory and (y) 35% of the amount determined pursuant to clause (i), and (iii) 100% of our Eligible Cash (defined in the New InventoryFacility), subject to reduction for reserves imposed by Regions.The commitments under the New Inventory Facility will terminate on the date that is the earliest to occur of (i) the third anniversary of the InventoryFacility Closing Date, (ii) the date, if any, that is 364 days following the first day that Liquidity (defined in the New Inventory Facility and consistent withthe definition in the Extended Securitization Facility (as defined below)) is less than $250 million for a period of 60 consecutive days and (iii) the date, ifany, that is 60 days following the maturity, termination or repayment in full of the Extended Securitization Facility.Revolving loan borrowings under the New Inventory Facility bear interest at a per annum rate equal to, at our option, either the base rate or theLondon interbank offered rate plus, in each case, a margin ranging from 2.25% to 2.50% (in the case of LIBOR loans) and 1.25% to 1.50% (in the case of baserate loans) determined using a Liquidity-based grid. Letters of credit under the New Inventory Facility are subject to a fee in an amount equal to theapplicable margin for LIBOR loans, plus customary fronting and issuance fees. For further information regarding the New Inventory Facility see Note 14 tothe Consolidated Financial Statements “Debt and Financing Arrangements”.On December 31, 2017 we had total liquidity of approximately $434 million including $429 in unrestricted cash and equivalents, and short terminvestments in debt securities, with the remainder provided by availability under our credit facilities, and funds withdrawable from brokerage accounts.The following is a summary of cash provided by or used in each of the indicated types of activities: SuccessorPredecessor Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1throughOctober 1, 2016 Year EndedDecember 31,2015(In thousands) Cash provided by (used in): Operating activities $396,473 $84,192$(228,218) $(44,367)Investing activities (59,802) 17,98415,134 (180,341)Financing activities (368,656) 2,709(37,210) (58,742) 68Table of ContentsCash Flow - SuccessorCash provided by operating activities in the year ended December 31, 2017 resulted from strong international coking coal markets, stable PowderRiver Basin thermal markets, and improving international thermal coal market conditions. Our operating cost performance provided significant cash marginsin these market conditions, particularly in the metallurgical segment as discussed in the Operational Performance section above. In addition, low cash interestexpense contributed to the cash provided by operating activities.Cash 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 used in investing activities in the year ended December 31, 2017 resulted from the net purchase of short term investments of approximately$69 million and capital expenditures of approximately $59 million. Capital expenditures in 2017 were at minimal levels. These uses of cash were partiallyoffset by withdrawals of restricted cash as reduced collateral requirements and the utilization of the New Inventory Facility resulted in no cash beingnecessary to support letters of credit at the end of the year.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 used in financing activities in the year ended December 31, 2017 resulted from purchases of treasury stock, payment of quarterly dividends, netpayments on outstanding debt, and financing costs associated with our New Term Loan Debt Facility, Extended Securitization Facility, and New InventoryFacility discussed above. For further information regarding our debt facilities see Note 14 to the Consolidated Financial Statements “Debt and FinancingArrangements”.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 our prior term loan.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 year ended December 31, 2015 resulted from deteriorating market conditions and high cash interestexpenses. Cash provided by investing activities in the Predecessor period January 1 through October 1, 2016 resulted from the net proceeds from sale of shortterm investments 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 year ended December 31, 2015 resulted from deposits of restricted cash as collateral requirements under thePredecessor securitization facility increased over the 2015 period, capital expenditures including the fourth of five annual $60 million lease by applicationbonus bid payments for reserves acquired in the Powder River Basin, partially offset by net proceeds from the sale of short term investments.Cash used in financing activities in the Predecessor period January 1 through October 1, 2016 resulted from financing costs associated with theprevious term loan facility and securitization facility, insurance premium financing payments, and expenses related to pre-filing debt restructuring costs.Cash used in financing activities in the year ended December 31, 2015 resulted from expenses related to pre-filing debt restructuring costs, principalpayments on our pre-filing term loan, and payments on other debt.69Table of ContentsContractual Obligations Payments Due by Period 2018 2019-2020 2021-2022 after 2022 Total (Dollars in thousands)Long-term debt, including related interest$32,287 $52,224 $40,023 $299,854 $424,388Operating leases5,936 6,914 4,010 8,292 25,152Coal lease rights3,582 12,879 14,219 34,371 65,051Coal purchase obligations11,207 — — — 11,207Unconditional purchase obligations85,947 — — — 85,947Total contractual obligations$138,959 $72,017 $58,252 $342,517 $611,745The related interest on long-term debt was calculated using rates in effect at December 31, 2017 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 $328.7 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 2018, 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.70Table of ContentsOff-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, 2017: Workers’ Reclamation Lease Compensation Obligations Obligations Obligations Other Total (Dollars in thousands)Surety bonds$531,735 $31,244 $17,334 $6,029 $586,342Letters of credit7,428 — 94,499 1,354 103,281Cash on deposit with others2,596 — 11,132 — 13,728Critical 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 required 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 and interest rate risk on long-term debt. Additionally, we may hold certaincoal derivative instruments for trading purposes. Derivative financial instruments are recognized in the balance sheet at fair value. Certain coal contracts maymeet the 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 byus over a reasonable period in the normal course of business, they are not recognized on the balance sheet.71Table of ContentsCertain 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 the underlying item being hedged. Changes in the fair value of the derivative instrument used as a hedge instrument in a cashflow hedge are recorded in other comprehensive income. Amounts in other comprehensive income are reclassified to earnings when the hedged transactionaffects earnings 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.We 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 6, “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, 2017, our balance sheet reflected asset retirement obligationliabilities of $328.7 million, including amounts classified as a current liability. As of December 31, 2017, we estimate the aggregate undiscounted cost offinal mine closures to be approximately $780.4 million.See the rollforward of the asset retirement obligation liability in Note 16 to the Consolidated Financial Statements, “Asset Retirement Obligations”.72Table of ContentsEmployee 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 21, “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 39% equity and 61% 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. The impact of lowering the expected long-term rate ofreturn on plan assets 0.5% for 2017 would have been an increase in expense of approximately $1.3 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 2017 would have been an decrease in expense of approximately $0.9 million.The 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 2017 .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.A valuation allowance is difficult to avoid when the company is in a cumulative loss position. A cumulative loss position is defined as a cumulative pre-tax loss for the current and the two preceding years. As our recent cumulative losses constitute significant negative evidence with regards to future taxableincome, we have relied solely on the expected reversal of taxable temporary differences to support the future realization of our deferred tax assets. We performa detailed scheduling process of our net taxable temporary differences.73Table of ContentsValuation allowances were established in prior years for federal and state net operating losses and tax credits that were not offset by the reversal of othernet 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.On December 22, 2017 the Tax Cut and Jobs Act of 2017 (“the Act”) was signed into law making significant changes to the Internal Revenue Code.Changes include, but are not limited to, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after December 31, 2017, theelimination of the corporate alternative minimum tax regime effective for tax years beginning after December 31, 2017, implementation of a process wherebycorporations with unused alternative minimum tax credits will be refunded during 2018-2022, the transition of U.S. international taxation from a worldwidetax system to a territorial system, a one-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings as of December 31, 2017,further limitation on the deductibility of certain executive compensation, allowance for immediate capital expensing of certain qualified property, andlimitations on the amount of interest expense deductible beginning in 2018.The Company has not completed its analysis for the income tax effects of the Act but has provided its best estimate of the impact of the Act in its year-end income tax provision in accordance with the guidance and interpretations available as of the date of this filing for the items noted below. The Companyanticipates finalizing the analysis for the estimate by December 31, 2018, within the one year measurement period under SAB 118, for the following items:•Remeasurement of deferred taxes: deferred tax assets and liabilities attributable to the U.S. were remeasured from 35% to the reduced tax rate of 21%.The provisional amount related to the remeasurement of certain deferred tax assets and liabilities based on the rates at which they are expected toreverse in the future was $330.9 million of income tax expense, with an offsetting valuation allowance adjustment. Finalization of theremeasurement of deferred taxes will occur upon finalization of 2017 taxable income and attribute carryback claims.•One-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings: The provisional amount of income tax expenserelated to the mandatory deemed repatriation of foreign earnings was $1.5 million based on cumulative foreign earnings of $4.2 million. Thedeemed repatriation tax is completely offset with net operating loss carryforwards, with an offsetting valuation allowance adjustment. Finalization of2017 earnings and profits calculations and receipt of further guidance in the form of Notices or Regulations may change the provisional calculation.•Elimination of the corporate AMT regime: Existing AMT credits as of December 31, 2017 will be refunded over the next four years. The refund maybe subject to a sequestration reduction rate of approximately 6.6%. The Company has provisionally determined that it will receive a refund ofexisting AMT credits of approximately $22.4 million after an estimated sequestration reduction of $1.5 million. The valuation allowance previouslyrecorded against these credits has been released and a tax benefit of $22.4 million was recorded. The Company’s accounting policy regarding thebalance sheet presentation of the AMT credits is to record the balance as a deferred tax asset until a return is filed claiming a refund of a portion ofthe credit, at which time the amount will be presented as a tax receivable. Finalization of the AMT credit balance will occur upon finalization of2017 taxable income and attribute carryback claims as well as the receipt of further guidance in the form of Notices or Regulations.•Elimination of executive compensation exemptions: The Act made changes to the $1 million limit on deductible compensation paid to certain“covered” employees. The Act eliminated exemptions for qualified performance based compensation and compensation paid after termination andexpanded the number of employees to which the limit applies. The Company recorded a provisional amount of $0.2 million of tax expense, with anoffsetting valuation allowance adjustment. The Act contains transitional rules, the implementation of which is uncertain at this time. The Companyis still analyzing related aspects of the Act including the impact of the transitional rules. The provisional amount detailed above may change whenfurther guidance is released that addresses these rules.74Table of ContentsOther provisions in the Act that may impact the company in future years include limitations on interest expense deductions and the global intangiblelow-taxed income “GILTI” rules covering foreign income earned in low-tax countries. There was no impact recorded for these changes in the 2017 provision.Additional work is necessary to do a more detailed review of the Act, but is anticipated to be completed by December 31, 2018.At December 31, 2017 additional tax losses were realized primarily as a result of the reversal of deductible temporary differences and percentagedepletion. A $35.7 million benefit was recorded from the release of valuation allowance offsetting alternative minimum tax credits that have becomerefundable by the Act, as well as carryback claims filed in the fourth quarter related to specific liability losses that resulted in claims for refund of previouslypaid alternative minimum taxes. At December 31, 2017 a $610.5 million valuation allowance fully offsets all net deferred tax assets, other than alternativeminimum tax credits.75Table 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 2018 are as follows: 2018 Tons $ per tonMetallurgical (in millions) Committed, Priced Coking 1.7 $103.96Committed, Unpriced Coking 2.6 Committed, Priced Thermal 0.5 $30.43Committed, Unpriced Thermal — Powder River Basin Committed, Priced 62.1 $11.95Committed, Unpriced 2.3 Other Thermal Committed, Priced 7.7 $36.88Committed, 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, 2017. Theestimated future realization of the value of the trading portfolio is $1.2 million of losses in 2018. 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, 2017, VaR for our coal trading positions that are recorded at fair value through earnings ranged from $0 to $1.0million. The linear mean of each daily VaR was $0.2 million. The final VaR at December 31, 2017 was under $0.1 million. 76Table of ContentsWe 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, 2017 VaR for our risk management positions that are recorded at fair value through earnings ranged from $0 to $1.1 million.The linear mean of each daily VaR was $0.3 million. The final VaR at December 31, 2017 was $0.8 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 42 to 46 milliongallons of diesel fuel for use in our operations during 2018. 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, 2017, we had purchased heating oil call options for approximately 26million gallons for the purpose of protecting against substantial increases in price relating to 2018 diesel purchases. These positions reduce our risk of cashflow fluctuations related to these fuel purchases but the positions are not accounted for as hedges. A $0.25 per gallon decrease in the price of heating oilwould not 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 theprice risk associated with fuel surcharges on barge and rail shipments, which cover increases in diesel fuel prices. At December 31, 2017, 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, 2017, of our $334.3 millionprincipal amount of debt outstanding, approximately $297.8 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, 2017, because we have fixed the LIBOR portion of the interest rate on our term loan using interest rate swaps.See Note 14, “Debt and Financing Arrangements” to the Consolidated Financial Statements for additional information on the interest rate swaps.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, 2017. 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 the opinion of independent registered public accounting firm and management’s report on internal control overfinancial reporting included within the Financial Statement section of this Annual Report on Form 10-K.ITEM 9B. OTHER INFORMATION.None.77Table 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 2018 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 2018Annual 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 2018 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 2018 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 2018 AnnualMeeting of Stockholders, which is expected to be filed with the SEC within 120 days after the close of our fiscal year.78Table 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- 63All 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 on the following page.ITEM 16.FORM 10-K SUMMARY.None.79Table of ContentsExhibits to be included in 10-K Description2.1 Debtors’ Fourth Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (incorporated by reference to Exhibit 2.1of Arch Coal’s Current Report on Form 8-K filed on September 15, 2016).2.2 Order 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).3.1 Amended and Restated Certificate of Incorporation of Arch Coal, Inc. 10.19 (incorporated by reference to Exhibit 3.1 of Arch Coal’sregistration statement on Form 8-A filed on October 4, 2016).3.2 Bylaws of Arch Coal, Inc. (incorporated by reference to Exhibit 3.2 of Arch Coal’s registration statement on Form 8-A filed on October 4,2016).4.1 Form of specimen Class A Common Stock certificate (incorporated by reference to Exhibit 4.1 of Arch Coal’s Current Report on Form 8-Kfiled on October 11, 2016).4.2 Form of specimen Class B Common Stock certificate (incorporated by reference to Exhibit 4.2 of Arch Coal’s Current Report on Form 8-Kfiled on October 11, 2016).4.3 Form of specimen Series A Warrant certificate (incorporated by reference to Exhibit A of Exhibit 10.5 of Arch Coal’s Current Report on Form8-K filed on October 11, 2016).10.1 Credit Agreement, dated as of March 7, 2017, among Arch Coal, Inc. as borrower, the lenders from time to time party thereto and CreditSuisse AG, Cayman Islands Branch, in its capacities as administrative agent and as collateral agent (incorporated by reference to Exhibit10.1 of Arch Coal’s Current Report on Form 8-K filed on March 8, 2017).10.2 First Amendment to Credit Agreement, dated as of September 25, 2017, among Arch Coal, Inc. as borrower, the lenders from time to timeparty thereto and Credit Suisse AG, Cayman Islands Branch, in its capacities as administrative agent and as collateral agent (incorporated byreference to Exhibit 10.1 of Arch Coal’s Current Report on Form 8-K filed on September 25, 2017).10.3 Credit Agreement, dated as of April 27, 2017, among Arch Coal, Inc. and certain of its subsidiaries, as borrowers, the lenders from time totime party thereto Regions Bank, in its capacities as administrative agent and as collateral agent (incorporated by reference to Exhibit 10.1of Arch Coal’s Current Report on Form 8-K filed on May 2, 2017).10.4 Third Amended and Restated Receivables Purchase Agreement among Arch Receivable Company, LLC, as seller, Arch Coal Sales Company,Inc., as initial servicer, PNC Bank, National Association as administrator and issuer of letters of credit thereunder and the other parties partythereto, as securitization purchasers (incorporated by reference to Exhibit 10.2 of Arch Coal’s Current Report on Form 8-K filed on October11, 2016).10.5 First Amendment to Third Amended and Restated Receivables Purchase Agreement, dated as of April 27, 2017, among Arch ReceivableCompany, LLC, as seller, Arch Coal Sales Company, Inc., as servicer, PNC Bank, National Association as administrator and issuer of lettersof credit thereunder and the other parties party thereto, as securitization purchasers (incorporated by reference to Exhibit 10.2 of Arch Coal’sCurrent Report on Form 8-K filed on May 2, 2017).10.6 Second 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).10.7 First Amendment to the Second Amended and Restated Purchase and Sale Agreement, dated as of December 21, 2016, among Arch Coal, Inc.and certain subsidiaries of Arch Coal, Inc., as originators (incorporated by reference to Exhibit 10.7 of Arch Coal’s Current Report on Form8-K filed on October 31, 2017).10.8 Second Amendment to the Second Amended and Restated Purchase and Sale Agreement, dated as of April 27, 2017, among the Arch Coal,Inc. and certain subsidiaries of the Arch Coal, Inc., as originators (incorporated by reference to Exhibit 10.3 of Arch Coal’s Current Report onForm 8-K filed on May 2, 2017).10.9 Second Amended and Restated Sale and Contribution Agreement between Arch Coal, Inc., as the transferor, and Arch Receivable Company,LLC (incorporated by reference to Exhibit 10.4 of Arch Coal’s Current Report on Form 8-K filed on October 11, 2016).10.10 First Amendment to the Second Amended and Restated Sale and Contribution Agreement, dated as of April 27, 2017, between Arch Coal,Inc., as the transferor, and Arch Receivable Company, LLC (incorporated by reference to Exhibit 10.4 of Arch Coal’s Current Report on Form8-K filed on May 2, 2017).10.11 Warrant Agreement, dated as of October 5, 2016, between Arch Coal, Inc. and American Stock Transfer & Trust Company, LLC, as WarrantAgent (incorporated by reference to Exhibit 10.5 of Arch Coal’s Current Report on Form 8-K filed on October 11, 2016).80Table of Contents10.12 Indemnification 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).10.13 Registration Rights Agreement between Arch Coal and Monarch Alternative Capital LP and certain other affiliated funds (incorporated byreference to Exhibit 10.1 of Arch Coal’s Current Report on Form 8-K filed on November 21, 2016)10.14 Coal Lease Agreement dated as of March 31, 1992, among Allegheny Land Company, as lessee, and UAC and Phoenix Coal Corporation, aslessors, and related guarantee (incorporated herein by reference to the Current Report on Form 8-K filed by Ashland Coal, Inc. on April 6,1992).10.15 Federal 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 Arch Coal’s Annual Report on Form 10-K for the year ended December 31, 1998).10.16 Federal Coal Lease Readjustment dated as of November 1, 1967 between the U.S. Department of the Interior and the Thunder Basin CoalCompany (incorporated herein by reference to Exhibit 10.21 to Arch Coal’s Annual Report on Form 10-K for the year ended December 31,1998).10.17 Federal 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 Arch Coal’s Annual Report on Form 10-K for the year ended December 31, 1998).10.18 Federal 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 Arch Coal’s Annual Report on Form 10-K for the year ended December 31, 1998).10.19 Federal Coal Lease effective as of March 1, 2005 by and between the United States of America and Ark Land LT, Inc. covering the tract ofland known as “Little Thunder” in Campbell County, Wyoming (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed by Arch Coal on February 10, 2005).10.20 Modified Coal Lease (WYW71692) executed January 1, 2003 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 Rochelle” in Campbell County,Wyoming (incorporated by reference to Exhibit 10.24 to Arch Coal’s Annual Report on Form 10-K for the year ended December 31, 2004).10.21 Coal 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 Campbell County,Wyoming (incorporated by reference to Exhibit 10.24 to Arch Coal’s Annual Report on Form 10-K for the year ended December 31, 2004).10.22* Form of Employment Agreement for Executive Officers of Arch Coal, Inc. (incorporated herein by reference to Exhibit 10.4 to Arch Coal’sAnnual Report on Form 10-K for the year ended December 31, 2011).10.23* Arch Coal, Inc. Incentive Compensation Plan For Executive Officers (incorporated herein by reference to Appendix B to the proxy statementon Schedule 14A filed by Arch Coal on March 22, 2010).10.24* Arch Coal, Inc. Deferred Compensation Plan (incorporated herein by reference to Exhibit 10.26 to Arch Coal’s Annual Report on Form 10-Kfor the year ended December 31, 2014).10.25 Arch 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).10.26* Arch Coal, Inc. Supplemental Retirement Plan (as amended on December 5, 2008) (incorporated herein by reference to Exhibit 10.2 to ArchCoal’s Current Report on Form 8-K filed on December 11, 2008).10.27* Arch Coal, Inc. 2016 Omnibus Incentive Plan (incorporated herein by reference to Exhibit 99.1 to Arch Coal’s Registration Statement onForm S-8 filed on November 1, 2016).10.28* Form 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).10.29* Form 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).10.30* Form of Performance Unit Contract (incorporated herein by reference to Exhibit 10.2 to Arch Coal’s Quarterly Report on Form 10-Q for theperiod ended March 31, 2013).10.31 Form of Director Indemnity Agreement (incorporated herein by reference to Exhibit 10.40 to Arch Coal’s Annual Report on Form 10-K forthe period ended December 31, 2010).10.32 Stock Repurchase Agreement dated September 13, 2017, among Arch Coal, Inc. and Monarch Alternative Solutions Master Fund Ltd,Monarch Capital Master Partners III LP, MCP Holdings Master LP, Monarch Debt Recovery Master Fund Ltd and P Monarch Recovery Ltd.(incorporated by reference to Exhibit 10.1 of Arch Coal’s Current Report on Form 8-K filed on September 19, 2017).81Table of Contents10.33 Stock Repurchase Agreement dated December 8, 2017, among Arch Coal, Inc. and Monarch Alternative Solutions Master Fund Ltd,Monarch Capital Master Partners III LP, MCP Holdings Master LP and Monarch Debt Recovery Master Fund Ltd. (incorporated by referenceto Exhibit 10.1 of Arch Coal’s Current Report on Form 8-K filed on December 11, 2017).21.1 Subsidiaries of the registrant.23.1 Consent of Ernst & Young LLP. 23.2 Consent of Weir International, Inc.24.1 Power of Attorney31.1 Rule 13a-14(a)/15d-14(a) Certification of John W. Eaves.31.2 Rule 13a-14(a)/15d-14(a) Certification of John T. Drexler.32.1 Section 1350 Certification of John W. Eaves.32.2 Section 1350 Certification of John T. Drexler.95.1 Mine Safety Disclosure Exhibit101 Interactive Data File (Form 10-K for the year ended December 31, 2017 filed in XBRL). The financial information contained in the XBRL-related documents is ''unaudited" and "unreviewed."* Denotes a management contract or compensatory plan or arrangement.82Table 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 23, 201883Table of Contents Signatures Capacity Date /s/ John W. Eaves John W. EavesChief Executive Officer, Director (Principal ExecutiveOfficer)February 23, 2018 /s/ John T. Drexler John T. DrexlerSenior Vice President and Chief Financial Officer(Principal Financial Officer)February 23, 2018 /s/ John W. Lorson John W. LorsonVice President and Chief Accounting Officer (PrincipalAccounting Officer)February 23, 2018 * James N. ChapmanChairmanFebruary 23, 2018 * Patrick J. Bartels, Jr.DirectorFebruary 23, 2018 * Sherman K. Edmiston IIIDirectorFebruary 23, 2018 * Patrick A. KriegshauserDirectorFebruary 23, 2018 * Richard A. NavarreDirectorFebruary 23, 2018 * Scott D. VogelDirectorFebruary 23, 2018 84Table of Contents*By/s/ Robert G. Jones Robert G. Jones,Attorney-in-Fact 85Table of ContentsFINANCIAL STATEMENTS AND SUPPLEMENTARY DATAIndex to Consolidated Financial StatementsReports of Independent Registered Public Accounting FirmF- 2Report of ManagementF- 4 Consolidated Statements of Operations: For the year ended December 31, 2017 (Successor); October 2, 2016 through December 31, 2016 (Successor); January 1, 2016 through October1, 2016 (Predecessor); and the year ended December 31, 2015 (Predecessor)F- 5 Consolidated Statements of Comprehensive Income (loss): For the year ended December 31, 2017 (Successor); October 2, 2016 through December 31, 2016 (Successor); January 1, 2016 through October1, 2016 (Predecessor); and the year ended December 31, 2015 (Predecessor)F- 6 Consolidated Balance Sheets at December 31, 2017 and 2016F- 7 Consolidated Statements of Cash Flows: For the year ended December 31, 2017 (Successor); October 2, 2016 through December 31, 2016 (Successor); January 1, 2016 through October1, 2016 (Predecessor); and the year ended December 31, 2015 (Predecessor)F- 8 Consolidated Statements of Stockholders’ Equity (Deficit): For the year ended December 31, 2017 (Successor); October 2, 2016 through December 31, 2016 (Successor); January 1, 2016 through October1, 2016 (Predecessor); and the year ended December 31, 2015 (Predecessor)F- 9 Notes to Consolidated Financial StatementsF- 10Financial Statement ScheduleF- 63 F- 1Table of ContentsReport of Independent Registered Public Accounting FirmTo the Stockholders and the Board of Directors of Arch Coal, Inc.Opinion on the Financial StatementsWe have audited the accompanying consolidated balance sheets of Arch Coal, Inc. and subsidiaries (the Company) as of December 31, 2017 and2016 (Successor), and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity (deficit) and cash flows for theyear ended December 31, 2017 (Successor), the period from October 2, 2016 through December 31, 2016 (Successor), the period from January 1, 2016through October 1, 2016 (Predecessor), and the year ended December 31, 2015 (Predecessor) and the related notes and financial statement schedule listed inthe Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, theconsolidated financial position of the Company at December 31, 2017 and 2016 (Successor), and the consolidated results of its operations and its cash flowsfor the year ended December 31, 2017 (Successor), the period from October 2, 2016 through December 31, 2016 (Successor), the period from January 1, 2016through October 1, 2016 (Predecessor), and the year ended December 31, 2015 (Predecessor), in conformity with U.S. generally accepted accountingprinciples.As discussed in Notes 1 and 3 to the consolidated financial statements, on September 13, 2016, the Bankruptcy Court entered an order confirmingthe Plan of Reorganization, which became effective on October 5, 2016. Accordingly, the accompanying consolidated financial statements have beenprepared in conformity with Accounting Standards Codification 852-10, Reorganizations, for the Successor Company as a new entity with assets, liabilitiesand a capital structure having carrying amounts not comparable with prior periods (Predecessor) as described in Notes 1 and 3.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), theCompany's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issuedby the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 23, 2018, expressed anunqualified opinion thereon.Basis for OpinionThese financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’sfinancial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to theCompany in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and thePCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtainreasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performingprocedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond tothose risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits alsoincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of thefinancial statements. We believe that our audits provide a reasonable basis for our opinion./s/ Ernst & Young, LLPWe have served as the Company’s auditor since 1997.St. Louis, MissouriFebruary 23, 2018F- 2Table of ContentsReport of Independent Registered Public Accounting FirmTo the Stockholders and the Board of Directors of Arch Coal, Inc.Opinion on Internal Control over Financial ReportingWe have audited Arch Coal, Inc. and subsidiaries internal control over financial reporting as of December 31, 2017, based on criteria established inInternal Control- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSOcriteria). In our opinion, Arch Coal, Inc. (and subsidiaries) (the Company) maintained, in all material respects, effective internal control over financialreporting as of December 31, 2017, based on the COSO criteria.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), theconsolidated balance sheets of Arch Coal, Inc. and subsidiaries (the Company) as of December 31, 2017 and 2016 (Successor), and the related consolidatedstatements of operations, comprehensive income (loss), stockholders’ equity (deficit) and cash flows for the year ended December 31, 2017 (Successor), theperiod from October 2, 2016 through December 31, 2016 (Successor), the period from January 1, 2016 through October 1, 2016 (Predecessor), and the yearended December 31, 2015 (Predecessor) and the related notes and financial statement schedule listed in the Index at Item 15 of the Company, and our reportdated February 23, 2018 expressed an unqualified opinion thereon.Basis for OpinionThe Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of theeffectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting.Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firmregistered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and theapplicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtainreasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testingand evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considerednecessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.Definition and Limitations of Internal Control Over Financial ReportingA company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’sinternal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded asnecessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of thecompany are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assuranceregarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on thefinancial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degreeof compliance with the policies or procedures may deteriorate. /s/ Ernst & Young, LLPSt. Louis, MissouriFebruary 23, 2018F- 3Table 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, 2017 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, 2017.The Company’s independent registered public accounting firm, Ernst & Young LLP, has issued an audit opinion on the Company’s internal controlover financial reporting as of December 31, 2017. F- 4Table of ContentsArch Coal, Inc. and SubsidiariesConsolidated Statements of Operations(in thousands, except per share data) SuccessorPredecessorYear EndedDecember 31,2017 October 2throughDecember 31,2016January 1through October1, 2016 Year EndedDecember 31,2015 Revenues $2,324,623 $575,688$1,398,709 $2,573,260Costs, expenses and other operating Cost of sales (exclusive of items shown separately below) 1,843,093 470,6441,264,464 2,172,753Depreciation, depletion and amortization 122,464 32,604191,581 379,345Accretion on asset retirement obligations 30,209 7,63424,321 33,680Amortization of sales contracts, net 53,985 796(728) (8,811)Change in fair value of coal derivatives and coal trading activities, net 7,222 3962,856 (1,583)Asset impairment and mine closure costs — —129,267 2,628,303Losses from disposed operations resulting from Patriot Coal bankruptcy — —— 116,343Selling, general and administrative expenses 86,821 22,83659,343 98,783Gain on sale of Lone Mountain Processing, Inc. (21,297) —— —Other operating (income) expense, net (30,270) (5,340)(15,257) 19,510 2,092,227 529,5701,655,847 5,438,323Income (loss) from operations232,396 46,118(257,138) (2,865,063) Interest expense, net Interest expense(26,905) (11,241)(135,888) (397,979)Interest and investment income2,649 4872,653 4,430 (24,256) (10,754)(133,235) (393,549) Income (loss) before nonoperating expenses 208,140 35,364(390,373) (3,258,612) Nonoperating income (expense) Net loss resulting from early retirement of debt and debt restructuring(2,547) —(2,213) (27,910)Reorganization income (loss), net (2,398) (759)1,630,041 — (4,945) (759)1,627,828 (27,910) Income (loss) before income taxes203,195 34,6051,237,455 (3,286,522)Provision for (benefit from) income taxes (35,255) 1,156(4,626) (373,380)Net income (loss)238,450 33,4491,242,081 (2,913,142) Earnings (loss) per common share Basic earnings (loss) per common share $10.05 $1.34$58.33 $(136.86) Diluted earnings (loss) per common share $9.84 $1.31$58.28 $(136.86) Weighted average shares outstanding Basic weighted average shares outstanding 23,725 25,00221,293 21,285 Diluted weighted average shares outstanding 24,240 25,46921,313 21,285The accompanying notes are an integral part of the consolidated financial statements.F- 5Table of ContentsArch Coal, Inc. and SubsidiariesConsolidated Statements of Comprehensive Income (Loss)(in thousands) SuccessorPredecessor Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1through October1, 2016 Year EndedDecember 31,2015 Net income (loss) $238,450 $33,449$1,242,081 $(2,913,142) Derivative instruments Comprehensive income (loss) before tax 647 —(532) (3,477)Income tax benefit (provision) — —80 1,252 647 —(452) (2,225)Pension, postretirement and other post-employment benefits Comprehensive income (loss) before tax (4,347) 24,067(1,848) (5,592)Income tax benefit (provision) — —483 2,011 (4,347) 24,067(1,365) (3,581)Available-for-sale securities Comprehensive income (loss) before tax (387) 3872,968 1,185Income tax benefit (provision) — —(1,042) (435) (387) 3871,926 750 Total other comprehensive income (loss) (4,087) 24,454109 (5,056)Total comprehensive income (loss) $234,363 $57,903$1,242,190 $(2,918,198) The accompanying notes are an integral part of the consolidated financial statements.F- 6Table of ContentsArch Coal, Inc. and SubsidiariesConsolidated Balance Sheets(in thousands, except per share data) December 31, 2017December 31, 2016Assets Current assetsCash and cash equivalents$273,387$305,372Short term investments155,84688,072Restricted cash—71,050Trade accounts receivable172,604184,483Other receivables29,77119,877Inventories128,960113,462Other current assets70,42696,306Total current assets830,994878,622 Property, plant and equipment Coal lands and mineral rights390,920387,591Plant and equipment445,407418,182Deferred mine development267,063280,323 1,103,3901,086,096Less accumulated depreciation, depletion and amortization(147,442)(32,493)Property, plant and equipment, net955,9481,053,603Other assetsPrepaid royalties4,280—Deferred income taxes22,520—Equity investments106,10796,074Other noncurrent assets59,783108,298Total other assets192,690204,372Total assets$1,979,632$2,136,597Liabilities and Stockholders' Equity Current liabilitiesAccounts payable$134,137$95,953Accrued expenses and other current liabilities184,161205,240Current maturities of debt15,78311,038Total current liabilities334,081312,231Long-term debt310,134351,841Asset retirement obligations308,855337,227Accrued pension benefits14,03638,884Accrued postretirement benefits other than pension102,369101,445Accrued workers’ compensation184,835184,568Other noncurrent liabilities59,45763,824Total liabilities1,313,7671,390,020Stockholders' equityCommon stock, $0.01 par value, authorized 300,000 shares, issued 25,047 and 25,002shares at December 31, 2017 and 2016, respectively250250Paid-in capital700,125688,424Treasury stock, 3,977 shares at December 31, 2017, at cost(302,109)—Retained earnings247,23233,449Accumulated other comprehensive income (loss)20,36724,454Total stockholders’ equity665,865746,577Total liabilities and stockholders’ equity$1,979,632$2,136,597The accompanying notes are an integral part of the consolidated financial statements.F- 7Table of ContentsArch Coal, Inc. and SubsidiariesConsolidated Statements of Cash Flows(in thousands) SuccessorPredecessorYear EndedDecember 31,2017 October 2throughDecember 31,2016January 1through October1, 2016 Year EndedDecember 31,2015 Operating activities Net income (loss)$238,450 $33,449$1,242,081 $(2,913,142)Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities: Depreciation, depletion and amortization122,464 32,604191,581 379,345Accretion on asset retirement obligations30,209 7,63424,321 33,680Amortization of sales contracts, net53,985 796(728) (8,811)Prepaid royalties expensed2,905 2,5874,791 8,109Deferred income taxes(21,965) 3(419) (367,210)Employee stock-based compensation expense10,437 1,0322,096 5,760Gains on disposals and divestitures(24,327) (485)(6,628) (2,270)Asset impairment and noncash mine closure costs— —119,194 2,613,345Losses from disposed operations resulting from Patriot Coal bankruptcy— —— 116,343Amortization relating to financing activities3,736 46712,800 25,241Net loss resulting from early retirement of debt and debt restructuring2,547 —2,213 27,910Non-cash bankruptcy reorganization items— —(1,775,910) —Changes in: Receivables8,370 (22,196)(42,786) 98,212Inventories(19,626) 24,87034,440 (6,534)Coal derivative assets and liabilities6,040 1,6625,678 973Accounts payable, accrued expenses and other current liabilities17,173 34,12915,316 (15,532)Asset retirement obligations(20,584) (4,535)(12,041) (17,040)Pension, postretirement and other postemployment benefits(15,253) (5,625)(15,692) 4,800Other1,912 (22,200)(28,525) (27,546)Cash provided by (used in) operating activities396,473 84,192(228,218) (44,367)Investing activities Capital expenditures(59,205) (15,214)(82,434) (119,024)Minimum royalty payments(5,296) (63)(305) (5,871)Proceeds from disposals and divestitures12,920 572(2,921) 2,191Purchases of short term investments(258,948) —(98,750) (246,735)Proceeds from sales of short term investments190,064 23,000185,859 290,205Proceeds from sale of investments in equity investments and securities— —1,147 2,259Investments in and advances to affiliates, net(10,173) (823)(3,441) (11,502)Withdrawals (deposits) of restricted cash70,836 10,51215,979 (91,864)Cash provided by (used in) investing activities(59,802) 17,98415,134 (180,341)Financing activities Proceeds from issuance of term loan due 2024298,500 —— —Payments to extinguish term loan due 2021(325,684) —— —Payments on term loan(2,250) (816)— (19,500)Net receipts (payments) on other debt(694) 3,374(11,986) (11,332)Debt financing costs(10,149) —(23,011) —Dividends paid(24,369) —— —Purchases of treasury stock(301,512) —— —Expenses related to debt restructuring(2,360) —(2,213) (27,910)Other(138) 151— —Cash provided by (used in) financing activities(368,656) 2,709(37,210) (58,742)Increase (decrease) in cash and cash equivalents(31,985) 104,885(250,294) (283,450)Cash and cash equivalents, beginning of period305,372 200,487450,781 734,231Cash and cash equivalents, end of period$273,387 $305,372$200,487 $450,781SUPPLEMENTAL CASH FLOW INFORMATION Cash paid during the period for interest$34,691 $39,620$79,979 $283,337Cash refunded during the period for income taxes, net$7,958 $287$49 $4,138The accompanying notes are an integral part of the consolidated financial statements.F- 8Table of ContentsArch Coal, Inc. and SubsidiariesConsolidated Statements of Stockholders’ Equity (Deficit)Three Years Ended December 31, 2017 Treasury RetainedEarnings Accumulated 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, 2015$2,141 $3,048,460 $(53,863) $(1,331,825) $3,241 $1,668,154Total comprehensive loss— — — (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) $(1,244,289)Total comprehensive income— — — 1,242,081 109 1,242,190Employee stock-based compensation expense— 2,099 — — — 2,099Elimination of predecessor equity(2,145) (3,056,310) 53,863 3,002,886 1,706 —BALANCE AT OCTOBER 1, 2016$— $— $— $— $— $—Successor Company Issuance of successor equity250 687,233 — — — 687,483Employee stock-based compensation— 1,032 — — — 1,032Warrants exercised— 159 — — — 159Total comprehensive income— — — 33,449 24,454 57,903BALANCE AT DECEMBER 31, 2016$250 $688,424 $— $33,449 $24,454 $746,577Dividends on common shares ($0.35/share)$— $— $— $(24,667) $— $(24,667)Employee stock-based compensation— 10,437 — — — 10,437Issuance of 17,233 shares of common stock underlong-term incentive plans— 1,244 — — — 1,244Warrants exercised— 20 — — — 20Purchase of 3,977,215 shares of common stock undershare repurchase program— — (302,109) — — (302,109)Total comprehensive income (loss)— — — 238,450 (4,087) 234,363 BALANCE AT DECEMBER 31, 2017$250 $700,125 $(302,109) $247,232 $20,367 $665,865F- 9Table 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, Illinois, Wyoming and Colorado. All subsidiaries are wholly-owned. Intercompany transactions andaccounts 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 required 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.F- 10Table 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 10 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 11 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- 11Table of ContentsProperty, Plant and EquipmentPlant and EquipmentPlant and equipment were recorded at fair value at emergence during fresh start accounting; subsequent purchases of property, plant and equipment havebeen recorded at cost. Interest costs incurred during the construction period for major asset additions are capitalized. The Company did not capitalize anyinterest costs during years ended December 31, 2017 and 2016, respectively. Expenditures that extend the useful lives of existing plant and equipment orincrease the productivity of the asset are capitalized. The cost of maintenance and repairs that do not extend the useful life or increase the productivity of theasset 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 21 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 sales revenue related to incidental production during thedevelopment phase will be recorded as coal sales revenue with an offset to cost of coal sales based on the estimated cost per ton sold for the mine when theasset is in place for its intended use.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 $361.2 million and $381.0 million at December 31, 2017 and 2016, respectively. Payments toacquire royalty lease agreements and lease bonus payments are capitalized as a cost of the underlying mineral reserves and depleted over the life of provenand probable 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 6 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 costsshown as an asset was $5.3 million at December 31, 2017, with $2.3 million classified as current; the unamortized balance of deferred financing costs shownas an asset at December 31, 2016 was $5.2 million with $1.9 million classified as current. The current amounts are classified within “Other current assets” andthe noncurrent amounts are classified withinF- 12Table of Contents“Other noncurrent assets.” For information on the unamortized balance of deferred financing fees related to outstanding debt, see Note 14 to the ConsolidatedFinancial Statements, “Debt and Financing Arrangements.”Revenue 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 10, “Equity Method Investments and Membership Interests in Joint Ventures”); non-material gains and losses from divestitures anddispositions of assets; and realized gains and losses on derivatives that do not qualify for hedge accounting and are not held for trading purposes (Note 12,“Derivatives”).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 16, “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 and interest rate risk on long-term debt. Additionally,the Company may hold certain coal derivative instruments for trading purposes. Derivative financial instruments are recognized in the balance sheet at fairvalue. Certain coal contracts may meet the definition of a derivative instrument, but because they provide for the physical purchase or sale of coal inquantities expected to be used or sold by the Company over a reasonable period in the normal course of business, they are not recognized on the balancesheet.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 the underlying item being hedged. Changes in the fair value of the derivative instrument used as a hedge instrument in a cash flowhedge are recorded in other comprehensive income or loss. Amounts in other comprehensive income or loss are reclassified to earnings when the hedgedtransaction affects earnings and are classified in a manner consistent with the transaction being hedged. The Company formally documents the relationshipsbetween hedging instruments and the respective hedged items, as well as its risk management objectives for hedge transactions.F- 13Table of ContentsThe 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.See Note 12, “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 17, “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 15, “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 is determined on an actuarialbasis 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 21, “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. The Company accounts forforfeitures as they occur. See further discussion in Note 19, “Stock-Based Compensation and Other Incentive Plans.” F- 14Table of ContentsRecently Adopted Accounting GuidanceIn March 2016, the FASB issued Accounting Standards Update No. 2016-09, Compensation - Stock Compensation (Topic 718) ("ASU 2016-09"). ASU2016-09 identifies areas for simplification involving several aspects of accounting for share-based payment transactions, including the income taxconsequences, classification of awards as either equity or liabilities, an option to recognize gross stock compensation expense with actual forfeituresrecognized as they occur, as well as certain classifications on the statement of cash flows. The Company adopted all provisions of this new accountingstandard in the first quarter of 2017 and changed its forfeiture policy to recognize the impact of forfeitures when they occur from estimating expectedforfeitures in determining stock-based compensation expense. There was no material impact to the Company's financial statements.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 requires that companies recognize revenue based on the value of transferred goods or services as they occurin the contract. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising fromcustomer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. ASU2014-09 is effective for interim and annual periods beginning after December 15, 2017. The Company’s primary source of revenue is from the sale of coalthrough both short-term and long-term contracts with utilities, industrial customers and steel producers whereby revenue is currently recognized when risk ofloss has passed to the customer. During the fourth quarter of 2017, the Company finalized its assessment related to the new standard by analyzing certaincontracts representative of the majority of the Company’s coal sales and determined that the timing of revenue recognition related to the Company’s coalsales will remain consistent between the new standard and the current standard. The Company also reviewed other sources of revenue, and concluded thecurrent basis of accounting for these items is in accordance with the new standard. The Company has concluded its adoption, using the modifiedretrospective method, will not have a material impact on its consolidated financial statements and there will be no cumulative adjustment to retainedearnings. The Company also reviewed the disclosure requirements under the new standard and is compiling information needed for the expanded disclosuresrequired during the first quarter of 2018.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 August 2016, the FASB issued ASU No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” The amendment requires theclassification of certain cash receipts and cash payments in the statement of cash flows to reduce diversity in practice. The new guidance will be effective forfiscal years beginning after December 15, 2017 and the interim periods therein, with early adoption permitted. The amendments in the classification shouldbe applied retrospectively to all periods presented, unless deemed impracticable, in which case, the prospective application is permitted. The Company plansto adopt the guidance in this standard during the first quarter of 2018.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. The Company plans to adopt theguidance in this standard during the first quarter of 2018.F- 15Table of ContentsIn March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement BenefitCost.” Under the new guidance, employers will present the service cost component of the net periodic benefit cost in the same income statement line item(s)as other employee compensation costs arising from services rendered during the period. Employers will present the other components separately from the lineitem(s) that includes the service cost and outside of any subtotal of operating income, if one is presented. Employers will have to disclose the line(s) used topresent the other components of net periodic benefit cost, if the components are not presented separately in the income statement. Additionally, only theservice cost component will be eligible for capitalization in assets. ASU 2017-07 is effective for fiscal years beginning after December 15, 2017, includinginterim periods within those fiscal year; early adoption is permitted. The Company plans to adopt the guidance in this standard during the first quarter of2018.In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” The new guidance providestargeted improvements to the accounting for hedging activities to better align an entity’s risk management activities and financial reporting for hedgingrelationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedgingresults. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early adoption ispermitted. The Company anticipates early adopting the standard in the first quarter of 2018, although we do not expect a significant impact to theCompany’s financial results.F- 16Table 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 required 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- 17Table 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.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 in such Transactionor (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 applicableF- 18Table of Contentstrustee vis-a-vis any parties other than the Debtors, (b) allow each trustee to receive distributions under the Plan and to distribute them to the holders of theCancelled Notes in accordance with the terms of the applicable indenture, (c) preserve any rights of the applicable trustee to compensation, reimbursementand indemnification under each of the applicable indentures solely as against any money or property distributable to holders of Cancelled Notes, (iv) permiteach of the trustees to enforce any obligation owed to them under the Plan and (v) permit each of the trustees to appear in the Chapter 11 cases or in anyproceeding 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 the DIP Agent and the lenders to expensereimbursement, indemnification and other similar amounts, certain reinstatement obligations set forth in the DIP Credit Agreement and any provisions thatmay survive termination or maturity of the credit facility governed by the DIP Credit Agreement in accordance with the terms 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 SeptemberF- 19Table of Contents28, 2016) among Arch Coal, Inc., as borrower, certain subsidiaries of Arch Coal, Inc., as guarantors, the lenders from time to time party there andWilmington Trust, National Association, in its capacity as administrative agent and as collateral agent (in such 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 significant effect on the determination of the Company’senterprise value. The assumptions used in the calculations for the DCF analysis included projected revenue, cost and cash flows for the years endingDecember 31, 2016 through each respective mine life and represented the Company’s best estimates at the time the analysis was prepared. The DCF analysiswas completed using discount rates at a range of estimated weighted average costs of capital ranging from 13.25% to 15.25% . The DCF analysis involvescomplex considerations and judgments concerning appropriate discount rates. Due to the unobservable inputs to the valuation, the fair value would beconsidered Level 3 in the fair value hierarchy.F- 20Table of ContentsThe 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- 21Table 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- 22Table 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- 23Table 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- 24Table 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 $3.1 million reduction in miscellaneous noncurrent liabilities. The fair value of sales contracts was estimated using a discounted cash flowmodel and will be amortized into earnings as the coal is shipped throughout the term of the associated contracts.F- 25Table of ContentsReorganization Items, NetIn accordance with ASC 852, the statement of operations shall portray the results of operations of the reporting entity while it is in Chapter 11. Revenues,expenses (including professional fees), realized gains and losses, and provisions for losses resulting from reorganization and restructuring of the businessshall be reported separately as reorganization items.The Company’s reorganization items, net for the respective periods are as follows: SuccessorPredecessor Year EndedDecember 31,2017 October 2 throughDecember 31, 2016January 1through October1, 2016 Year EndedDecember 31, 2015(In thousands) Gain on settlement of claims (per above)$— $—$4,142,104 $—Fresh start adjustments, net (per above)— —(2,466,010) —Professional fees(2,398) (759)(46,053) — $(2,398) $(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, 2017, 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- 26Table 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, 2016$325 $(721) $(1,419) $(1,815)Unrealized gains (losses)(138) — 701 563Amounts reclassified from accumulated other comprehensive income(loss)(316) (1,363) 1,225 (454)Fresh start accounting adjustment129 2,084 (507) 1,706October 1, 2016— — — —Successor Company Unrealized gains (losses)— 24,067 387 24,454Amounts reclassified from accumulated other comprehensive income(loss)— — — —December 31, 2016$— $24,067 $387 $24,454Unrealized gains (losses)497 (3,589) — (3,092)Amounts reclassified from accumulated other comprehensive income(loss)150 (758) (387) (995)December 31, 2017$647 $19,720 $— $20,367The unrealized gain in the successor period ended December 31, 2016 is the result of changes in the discount rates used to calculate our pension,postretirement health and occupational disease obligations.F- 27Table 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 Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1through October1, 2016 (in thousands) Derivative instruments Coal hedges $— $—$397 RevenuesInterest rate hedges (150) — Interest expense — —(81) Provision for (benefit from) income taxes $(150) $—$316 Net of tax Pension, postretirement and other post-employment benefits Amortization of prior service credits 1 $— $—$7,854 Amortization of net actuarial gains(losses) 1 — —(6,010) Curtailments (773) —— Settlements 1,531 —— 758 —1,844 Total before tax — —(481) Provision for (benefit from) income taxes $758 $—$1,363 Net of tax Available-for-sale securities 2 $387 $—$(2,263) Interest and investment income — —1,038 Provision for (benefit from) income taxes $387 $—$(1,225) 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- 28Table of Contents5. DivestituresOn September 14, 2017, the Company closed on its’ definitive agreement to sell Lone Mountain Processing LLC, an operating mine complex within theCompany’s metallurgical coal segment, and two idled mining companies, Cumberland River Coal LLC and Powell Mountain Energy LLC to RevelationEnergy LLC. The Company received $8.3 million of proceeds offset by $1.4 million in disbursements related to landholder consent fees and professionalfees; and recorded a gain of $21.3 million which is reflected as a separate line, “Gain on sale of Lone Mountain Processing, Inc.,” within the ConsolidatedStatement of Operations. The gain included a $4.7 million curtailment gain related to black lung liabilities accrued for active employees at these operations.6. Impairment Charges and Mine Closure CostsThe following table summarizes the amounts reflected on the line “Asset impairment and mine closure costs” in the consolidated statements of operations: SuccessorPredecessorDescriptionYear Ended December31, 2017 October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016 Year EndedDecember 31, 2015(In thousands) Coal lands and mineral rights$— $—$74,144 $2,210,488Plant and equipment— —— 199,107Deferred development— —— 159,474Prepaid royalties— —3,406 41,990Equity investments— —40,920 21,325Inventories— —— 66Other— —10,797 (4,147)Total$— $—$129,267 $2,628,303January 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 significantlyF- 29Table of Contentshigher coal prices. The then current prices and the significant capital outlay that would have been required to develop these reserves indicated that thecarrying value was not recoverable. As a result the Company recorded a $2.6 billion asset impairment charge in the last two quarters of 2015 of which $2.1billion was recorded during the third quarter and the remaining $0.5 billion was recorded in the fourth quarter. Of the total charge. $2.2 billion was recordedto the Company’s Appalachia segment, with the remaining $0.4 billion recorded to the Company’s Other operating segment. There is no fair value remainingrelated 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 royalty balance on a reserve base mined at the Company’s MountainLaurel, Spruce and Briar Branch operations that was determined would not be recouped based on estimates of sales volume and pricing through the March2017 recoupment period. Additionally, the Company recorded a $5.6 million impairment charge related to the closure of a higher-cost mining complexserving the metallurgical coal markets.7. 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 had providedsurety bonds to Patriot related to permits that were sold to an affiliate of Virginia Conservation Legacy Fund, Inc. (“VCLF”). The Company recognized$116.3 million in losses in 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.8. Inventories Inventories consist of the following: December 31,2017 December 31,2016(In thousands) Coal $54,692 $37,268Repair parts and supplies 74,268 76,194 $128,960 $113,462 The repair parts and supplies are stated net of an allowance for slow-moving and obsolete inventories of $0.3 million at December 31, 2017 and $0.0million at December 31, 2016. F- 30Table of Contents9. 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: December 31, 2017 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$64,151 $22 $(73) $64,100 $64,100 $—Corporate notes and bonds92,038 — (292) 91,746 91,746 —Total Investments$156,189 $22 $(365) $155,846 $155,846 $— 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 $2,137The aggregate fair value of investments with unrealized losses that had been owned for less than a year was $132.0 million and $47.6 million atDecember 31, 2017 and 2016, respectively. The aggregate fair value of investments with unrealized losses that have been owned for over a year was $0.0million and $40.4 million at December 31, 2017 and 2016, respectively.The debt securities outstanding at December 31, 2017 have maturity dates ranging from the first quarter of 2018through the second quarter of 2019. 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- 31Table of Contents10. 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, 2015 $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) 1,703December 31, 2016 $87,493 $8,581 $— $— $— $96,074Investments in affiliates — 7,158 — — — 7,158Advances to (distributions from) affiliates, net (8,736) 3,014 — — — (5,722)Equity in comprehensive income (loss) 11,409 (2,812) — — — 8,597 December 31, 2017 $90,166 $15,941 $— $— $— $106,107 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 in Dominion Terminal Associates (“DTA”), which is accounted for under the equity method. In March2017, the Company paid $7.2 million through an auction process held by one of the existing owners, increasing its ownership in DTA from 21.875% to 35%.DTA operates a ground storage-to-vessel coal transloading facility in Newport News, Virginia for use by the partners. Under the terms of a throughput andhandling agreement with DTA, each partner is charged its share of cash operating and debt-service costs in exchange for the right to use the facility’s loadingcapacity 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 previously held a 35% membership interest in the Tongue River Holding Company, LLC (“Tongue River”) joint venture. Tongue Riverwas formed to develop and construct a railway line near Miles City, Montana and the Otter Creek reserves formerly controlled by the Company. TheCompany had the right, upon the receipt of permits and approval for construction or under other prescribed circumstances, to require the other investors topurchase all of the Company’s units in the venture at an amount equal to the capital contributions made by the Company at that time, less any distributionsreceived. During the third quarter of 2015, the Company recorded an impairment charge of $21.3 million representing the entire value of the Company’sinvestment in the project; the impairment charge is included on the line “Asset impairment and mine closure costs.”F- 32Table of ContentsThe Company is not required to make any future contingent payments related to development financing for any of its equity investees.11. Sales ContractsThe sales contracts reflected in the consolidated balance sheets are as follows: December 31, 2017 December 31, 2016 Assets Liabilities Net Total Assets Liabilities Net Total (In thousands) (In thousands) Original fair value$97,196 $31,742 $97,196 $31,742 Accumulated amortization(84,760) (29,979) (25,625) (24,829) Total$12,436 $1,763 $10,673 $71,571 $6,913 $64,658Balance Sheet classification: Other current$12,432 $934 $59,702 $5,114 Other noncurrent$4 $829 $11,869 $1,799 The Company anticipates the majority of the remaining net book value of sales contracts to be amortized in 2018 based upon expected shipments.12. Derivatives Interest rate risk managementThe Company has entered into some interest rate swaps to reduce the variability of cash outflows associated with interest payments on its variable rateterm loan. These swaps have been designated as cash flow hedges. For additional information on these arrangements, see Note 14, “Debt and FinancingArrangements” in the Consolidated Financial Statements.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 approximately42 to 46 million gallons of diesel fuel for use in its operations during 2018. To protect the Company’s cash flows from increases in the price of diesel fuel forits operations, the Company uses forward physical diesel purchase contracts and purchased heating oil call options. At December 31, 2017, the Company hadheating oil call options for approximately 26.2 million gallons at an average strike price of $1.84.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, 2017, the Company held derivatives for risk management purposes that are expected to settle in the following years: (Tons in thousands) 2018 2019 TotalCoal sales 1,706 159 1,865Coal purchases 747 — 747The Company may also enter into natural gas options to protect the Company from decreases in natural gas prices, which could impact thermal coaldemand. These options are not designated as hedges. Additionally, the Company may enter into nominal quantities of foreign currency options protecting fordecreases in the Australian to United States dollar exchange rate, which could impact metallurgical coal demand. These options are not designated as hedges.F- 33Table of ContentsCoal 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 losses of $1.2 million in the trading portfolio areexpected to be realized in 2018.Tabular 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: December 31, 2017 December 31, 2016 Fair Value of Derivatives Asset Liability Asset Liability (In thousands) Derivative Derivative Derivative Derivative Derivatives Designated as HedgingInstruments Coal $942 $(2,146) $— $(15) Derivatives Not Designated as HedgingInstruments Heating oil -- diesel purchases 5,354 — 4,646 — Coal held for trading purposes, exchangetraded swaps and futures 44,088 (45,221) 68,948 (68,740) Coal -- risk management 5,139 (9,892) 475 (580) Natural gas 27 — 86 (13) Total 54,608 (55,113) 74,155 (69,333) Total derivatives 55,550 (57,259) 74,155 (69,348) Effect of counterparty netting (50,042) 50,042 (69,247) 69,247 Net derivatives as classified in thebalance sheets $5,508 $(7,217) $(1,709) $4,908 $(101) $4,807 December 31, 2017 December 31, 2016Net derivatives as reflected on the balance sheets Heating oil Other current assets $5,354 $4,646Coal Other current assets 154 262 Accrued expenses andother current liabilities (7,217) (101) $(1,709) $4,807 The Company had a current asset for the right to reclaim cash collateral of $16.2 million and $2.8 million at December 31, 2017 and 2016, 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- 34Table 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 Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1throughOctober 1,2016 Year EndedDecember 31,2015Coal sales(1) $(2,127) $—$(672) 12,816Coal purchases(2) 942 —536 (6,718) $(1,185) $—$(136) $6,098 Gains (Losses) Reclassified from Other Comprehensive Income intoIncome(Effective Portion) SuccessorPredecessor Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1throughOctober 1,2016 Year EndedDecember 31,2015Coal sales $— $—$1,634 $18,635Coal purchases — —(1,237) (9,060) $— $—$397 $9,575 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 respective periods. Derivatives Not Designated as Hedging Instruments (in thousands)For the noted periods, Gain (Loss) Recognized SuccessorPredecessor Year EndedDecember 31,2017October 2throughDecember 31,2016January 1throughOctober 1, 2016 Year EndedDecember 31,2015Coal — unrealized(3) $(4,648)$(408)$(1,662) $(3,883)Coal — realized(4) $—$116$(476) $3,236Heating oil — diesel purchases(4) $(1,057)$827$826 $(8,294)Natural gas $(774)$(91)$(463) $878Foreign currency $—$(9)$(451) $(867)F- 35Table 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, net The Company recognized net unrealized and realized losses of $2.0 million for the year ended December 31, 2017; an immaterial amount for the periodOctober 2 through December 31, 2016; net unrealized and realized losses of $0.9 million for the period January 1 through October 1, 2016; and netunrealized and realized gains of $5.7 million during the year ended December 31, 2015, respectively, related to its trading portfolio, which are included inthe caption “Change in fair value of coal derivatives and coal trading activities, net” in the accompanying consolidated statements of operations, and are notincluded in the previous tables reflecting the effects of derivatives on measures of financial performance. Based on fair values at December 31, 2017, 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 losses of $1.2 million.13. Accrued Expenses and Other Current LiabilitiesAccrued expenses and other current liabilities consist of the following: December 31,2017 December 31,2016(In thousands) Payroll and employee benefits $53,149 $58,468Taxes other than income taxes 77,017 92,733Interest 246 8,032Sales contracts 934 5,114Workers’ compensation 18,782 15,184Asset retirement obligations 19,840 19,515Other 14,193 6,194 $184,161 $205,240F- 36Table of Contents14. Debt and Financing Arrangements December 31,2017 December 31,2016(In thousands) Term loan due 2024 ($297.8 million face value) $296,435 $—Term loan due 2021 ($325.7 million face value) $— $325,684Other 36,514 37,195Debt issuance costs (7,032) — 325,917 362,879Less current maturities of debt 15,783 11,038Long-term debt $310,134 $351,841Term Loan FacilityOn March 7, 2017, the Company entered into a new senior secured term loan credit agreement in an aggregate principal amount of $300 million (the“New Term Loan Debt Facility”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent (in such capacities, the“Agent”), and the other financial institutions from time to time party thereto (collectively, the “Lenders”). The New Term Loan Debt Facility was issued at99.50% of the face amount and will mature on March 7, 2024.On September 25, 2017, the Company entered into the First Amendment (the “Amendment”) to its Credit Agreement, dated as of March 7, 2017, amongArch Coal as borrower, the lenders from time to time party thereto, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateralagent.The Amendment reduces the interest rate on the $300 million term loan facility to, at the option of Arch Coal, either (i) the London interbank offered rate(“LIBOR”) plus an applicable margin of 3.25%, subject to a 1.00% LIBOR floor, or (ii) a base rate plus an applicable margin of 2.25%. The Amendment alsoresets the 1.00% call premium to apply to repricing events that occur on or prior to March 26, 2018.Borrowings under the New Term Loan Debt Facility bear interest at a per annum rate equal to, at the Company’s option, either (i) a London interbankoffered rate plus an applicable margin of 4%, subject to a 1% LIBOR floor (the “LIBOR Rate”), or (ii) a base rate plus an applicable margin of 3%. The termloans provided under the New Term Loan Debt Facility (the “Term Loans”) are subject to quarterly principal amortization payments in an amount equal to$750,000.The New Term Loan Debt Facility is guaranteed by all existing and future wholly owned domestic subsidiaries of the Company (collectively, the“Subsidiary Guarantors” and, together with Arch Coal, the “Loan Parties”), subject to customary exceptions, and is secured by first priority security interestson substantially all assets of the Loan Parties, including 100% of the voting equity interests of directly owned domestic subsidiaries and 65% of the votingequity interests of directly owned foreign subsidiaries, subject to customary exceptions.The Company has the right to prepay Term 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 Term Loans that bear interest at the LIBOR Rate other than at the end of the applicable interest periods therefor shall be madewith reimbursement for any funding losses and redeployment costs of the Lenders resulting therefrom.The New Term Loan Debt Facility is subject to certain usual and customary mandatory prepayment events, including 100% of net cash proceeds of (i)debt issuances (other than debt permitted to be incurred under the terms of the New Term Loan Debt Facility) and (ii) non-ordinary course asset sales ordispositions, subject to customary thresholds, exceptions and reinvestment rights.The New Term Loan Debt Facility contains customary affirmative covenants and representations.F- 37Table of ContentsThe New Term Loan Debt Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, includerestrictions on (i) indebtedness, (ii) liens, (iii) liquidations, mergers, consolidations and acquisitions, (iv) disposition of assets or subsidiaries, (v) affiliatetransactions, (vi) creation or ownership of certain subsidiaries, partnerships and joint ventures, (vii) continuation of or change in business, (viii) restrictedpayments, (ix) prepayment of subordinated and junior lien indebtedness, (x) restrictions in agreements on dividends, intercompany loans and granting lienson the collateral, (xi) loans and investments, (xii) sale and leaseback transactions, (xiii) changes in organizational documents and fiscal year and (xiv)transactions with respect to bonding subsidiaries. The New Term Loan Debt Facility does not contain any financial maintenance covenant.The New Term Loan Debt Facility contains customary events of default, subject to customary thresholds and exceptions, including, among other things,(i) nonpayment of principal and nonpayment of interest and fees, (ii) a material inaccuracy of a representation or warranty at the time made, (iii) a failure tocomply with any covenant, subject to customary grace periods in the case of certain affirmative covenants, (iv) cross-events of default to indebtedness of atleast $50 million, (v) cross-events of default to surety, reclamation or similar bonds securing obligations with an aggregate face amount of at least $50million, (vi) uninsured judgments in excess of $50 million, (vii) any loan document shall cease to be a legal, valid and binding agreement, (viii) uninsuredlosses or proceedings against assets with a value in excess of $50 million, (ix) certain ERISA events, (x) a change of control or (xi) bankruptcy or insolvencyproceedings relating to the Company or any material subsidiary of the Company.On the effective date of the New Term Loan Debt Facility, all outstanding obligations under the Company’s previously existing term loan creditagreement, dated as of October 5, 2016, among the Company, as borrower, the lender party thereto and Wilmington Trust, National Association, asadministrative agent and collateral agent (the “Previous First Lien Debt Facility”), other than indemnification and other contingent obligations, were paid incash in full and the related transaction documents were terminated (other than with respect to certain provisions that customarily survive termination); therewas no gain or loss recognized on the extinguishment of the previously existing term loan credit agreement. All liens on property of the Company and theguarantors thereunder arising out of or related to the Previous First Lien Debt Facility were terminated.Accounts Receivable Securitization FacilityOn April 27, 2017, the Company extended and amended its existing trade accounts receivable securitization facility provided to Arch ReceivableCompany, LLC, a special-purpose entity that is a wholly owned subsidiary of the Company (“Arch Receivable”) (the “Extended Securitization Facility”),which supports the issuance of letters of credit and requests for cash advances. The amendment to the Extended Securitization Facility decreases theborrowing capacity from $200 million to $160 million and extends the maturity date to the date that is three years after the Securitization Facility ClosingDate. Pursuant to the Extended Securitization Facility, Arch Receivable also agreed to a revised schedule of fees payable to the administrator and theproviders of the Extended Securitization Facility.The Extended Securitization Facility will terminate at the earliest of (i) three years from the Securitization Facility Closing Date, (ii) if the Liquidity(defined in the Extended Securitization Facility and consistent with the definition in the New Inventory Facility) is less than $175 million for a period of 60consecutive 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 eventssubstantially consistent with the existing transaction documents. Under the Extended Securitization Facility, Arch Receivable, the Company and certain ofits subsidiaries 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 parties from the sale of coal and all proceeds thereof. As of December 31, 2017, letters ofcredit totaling $85.0 million were outstanding under the facility with no additional availability for borrowings.Inventory-Based Revolving Credit FacilityOn April 27, 2017, the Company and certain subsidiaries of Arch Coal entered into a new senior secured inventory-based revolving credit facility in anaggregate principal amount of $40 million (the “New Inventory Facility”) with Regions Bank (“Regions”) as administrative agent and collateral agent (insuch capacities, the “Agent”), as lender and swingline lender (in such capacities, the “ Lender ”) and as letter of credit issuer. Availability under the NewInventory Facility is subject to a borrowing base consisting of (i) 85% of the net orderly liquidation value of eligible coal inventory, (ii) the lesser of (x) 85%of the net orderly liquidation value of eligible parts and supplies inventory and (y) 35% of the amount determined pursuant to clause (i), and (iii) 100% ofArch Coal’s Eligible Cash (defined in the New Inventory Facility), subject to reduction for reserves imposed by Regions.F- 38Table of ContentsThe commitments under the New Inventory Facility will terminate on the date that is the earliest to occur of (i) the third anniversary of the InventoryFacility Closing Date, (ii) the date, if any, that is 364 days following the first day that Liquidity (defined in the New Inventory Facility and consistent withthe definition in the Extended Securitization Facility (as defined below)) is less than $250 million for a period of 60 consecutive days and (iii) the date, ifany, that is 60 days following the maturity, termination or repayment in full of the Extended Securitization Facility.Revolving loan borrowings under the New Inventory Facility bear interest at a per annum rate equal to, at the option of the Company, either at the baserate or the London interbank offered rate plus, in each case, a margin ranging from 2.25% to 2.50% (in the case of LIBOR loans) and 1.25% to 1.50% (in thecase of base rate loans) determined using a Liquidity-based grid. Letters of credit under the New Inventory Facility are subject to a fee in an amount equal tothe applicable margin for LIBOR loans, plus customary fronting and issuance fees.All existing and future direct and indirect domestic subsidiaries of the Company, subject to customary exceptions, will either constitute co-borrowersunder or guarantors of the New Inventory Facility (collectively with the Company, the “Loan Parties”). The New Inventory Facility is secured by first prioritysecurity interests in the ABL Priority Collateral (defined in the New Inventory Facility) of the Loan Parties and second priority security interests insubstantially all other assets of the Loan Parties, subject to customary exceptions (including an exception for the collateral that secures the ExtendedSecuritization Facility).The Company has the right to prepay borrowings under the New Inventory Facility at any time and from time to time in whole or in part withoutpremium or penalty, upon written notice, except that any prepayment of such borrowings that bear interest at the LIBOR rate other than at the end of theapplicable interest periods therefore shall be made with reimbursement for any funding losses and redeployment costs of the Lender resulting therefrom.The New Inventory Facility is subject to certain usual and customary mandatory prepayment events, including non-ordinary course asset sales ordispositions, subject to customary thresholds, exceptions (including exceptions for required prepayments under the Company’s term loan facility) andreinvestment rights.The New Inventory Facility contains certain customary affirmative and negative covenants; events of default, subject to customary thresholds andexceptions; and representations, including certain cash management and reporting requirements that are customary for asset-based credit facilities. The NewInventory Facility also includes a requirement to maintain Liquidity equal to or exceeding $175 million at all times. As of December 31, 2017, letters ofcredit totaling $29.0 million were outstanding under the facility with $1.1 million additional availability for borrowings.Interest Rate SwapsDuring the second quarter of 2017, the Company entered into a series of interest rate swaps to fix a portion of the LIBOR interest payments due under theterm loan. The interest rate swaps qualify for cash flow hedge accounting treatment and as such, the change in the fair value of the interest rate swaps arerecorded on the Company’s Consolidated Balance Sheet as an asset or liability with the effective portion of the gains or losses reported as a component ofaccumulated other comprehensive income and the ineffective portion reported in earnings. As interest payments are made on the term loan, amounts inaccumulated other comprehensive income will be reclassified into earnings through interest expense to reflect a net interest on the term loan equal to theeffective yield of the fixed rate of the swap plus 3.25% which is the spread on the revised LIBOR term loan. In the event that an interest rate swap isterminated prior to maturity, gains or losses in accumulated other comprehensive income will remain deferred and reclassified into earnings in the periodswhich the hedged forecasted transaction affects earnings.F- 39Table of ContentsBelow is a summary of the Company’s outstanding interest rate swap agreements designated as hedges as ofDecember 31, 2017:Notional Amount (inmillions)Effective DateFixed RateReceive RateExpiration Date $250.0June 30, 20171.372%1-month LIBORJune 29, 2018$250.0June 29, 20181.662%1-month LIBORJune 28, 2019$200.0June 28, 20191.952%1-month LIBORJune 30, 2020$150.0June 30, 20202.182%1-month LIBORJune 30, 2021The fair value of the interest rate swaps at December 31, 2017 is an asset of $1.8 million which is recorded within Other noncurrent assets with the offsetto accumulated other comprehensive income on the Company’s Consolidated Balance Sheet. The Company realized $0.1 million of losses during the yearended December 31, 2017 related to settlements of the interest rate swaps which was recorded to interest expense on the Company’s Consolidated Statementof Operations. The interest rate swaps are classified as level 2 within the fair value hierarchy.Debt MaturitiesThe contractual maturities of debt as of December 31, 2017 are as follows:Year (In thousands)2018 $16,8092019 11,1192020 11,4422021 8,8532022 3,130Thereafter 282,911 $334,264Financing CostsThe Company paid financing costs of $10.1 million during the year ended December 31, 2017; zero during the period October 2 through December 31,2016; $23.0 million during the period January 1 through October 1, 2016; and zero during the year ended December 31, 2015, respectively, in conjunctionwith its financing activities.The Company incurred $2.5 million and $2.2 million of legal fees and financial advisory fees associated with debt restructuring activities during theperiod ended December 31, 2017 and January 1 through October 1, 2016, respectively. Additionally, the Company incurred $24.2 million of legal fees andfinancial advisory fees associated with debt restructuring activities during 2015. During the year ended December 31, 2015 the Company wrote off $3.7million of deferred financing costs related to the termination of the revolver facility. All amounts have been reflected in the line, “Net loss resulting fromearly retirement and refinancing of debt” in the Consolidated Statement of Operations.F- 40Table of Contents15. TaxesIn 2016, under the Plan of bankruptcy reorganization, the Company’s pre-petition equity, bank related debt and certain other obligations were cancelledand extinguished. Absent an exception, a debtor recognizes cancellation of debt income (CODI) upon discharge of its outstanding indebtedness for anamount of consideration that is less than its adjusted issue price. In accordance with Internal Revenue Code (IRC) Section 108, the Company excluded theamount of discharged indebtedness from taxable income since the IRC provides that a debtor in a bankruptcy case may exclude CODI from income but mustreduce certain tax attributes by the amount of CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by ataxpayer is the adjusted issue price of any indebtedness discharged less than the sum of (i) the amount of cash paid, (ii) the issue price of any newindebtedness issued, and (iii) the fair market value of any other consideration, including equity, issued.CODI from the discharge of indebtedness was $3,414 million. As a result of the CODI and in accordance with IRC rules, the Company reduced its grossfederal net operating loss (NOL) carryovers $3,185 million and its alternative minimum tax (AMT) credits $76 million. The Company was able to retain$957.1 million of gross federal NOLs, $25.6 million of AMT credit and $64.5 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, based on comparing the fair value and carryover tax basis in assets, at the time of theownership change, therefore, certain built-in gains recognized within five years after the ownership change will increase the annual IRC section 382 limit forthe five year recognition period beginning October 1, 2016 through September 30, 2021. There is uncertainty surrounding which assets with built-in gainwill be realized within the five year period following the Company’s emergence from bankruptcy and allow the Company to realize the incremental netoperating losses and credit in excess of the base 382 limitation. The Company is reflecting a deferred tax asset for the full amount of the net operating lossesand credit carryforwards. If at some point in time it becomes 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 2017 remain open toexamination for U.S. federal income tax matters and 2002 through 2017 remain open to examination for various state income tax matters.Significant components of the provision for (benefit from) income taxes are as follows: SuccessorPredecessor Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1throughOctober 1,2016 Year EndedDecember 31,2015(In thousands) Current: Federal$835 $—$— $—State31 (252)7 3Total current866 (252)7 3Deferred: Federal(36,162) 1,352(4,720) (329,393)State41 5687 (43,990)Total deferred(36,121) 1,408(4,633) (373,383) $(35,255) $1,156$(4,626) $(373,380)F- 41Table 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 Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1through October1, 2016 Year EndedDecember 31,2015(In thousands) Income tax provision (benefit) at statutory rate$71,118 $12,112$433,109 $(1,150,283)Percentage depletion allowance(31,255) (4,292)(3,681) (19,035)State taxes, net of effect of federal taxes7,002 633(46,122) (76,445)Reversal of cancellation of indebtedness income— —(1,493,162) —Worthless stock deduction— —(80,077) —Change in valuation allowance(410,983) (7,655)1,185,326 865,146Impact of Tax Cuts and Jobs Act of 2017332,345 —— —Other, net(3,482) 358(19) 7,237 $(35,255) $1,156$(4,626) $(373,380)Significant 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: December 31,2017 December 31,2016(In thousands) Deferred tax assets: Tax loss carryforwards$271,405 $376,293Tax credit carryforwards29,736 22,798Investment in tax partnerships & corporations308,653 604,914Other28,321 39,251Gross deferred tax assets638,115 1,043,256Valuation allowance(610,571) (1,021,553)Total deferred tax assets27,544 21,703Deferred tax liabilities: Plant and equipment3,674 7,332Other1,351 14,258Total deferred tax liabilities5,025 21,590Net deferred tax asset22,519 113F- 42Table of ContentsThe Company has gross federal net operating loss carryforwards for regular income tax purposes of $980.2 million at December 31, 2017 that will expirebetween 2022 and 2037. The Company has an alternative minimum tax credit carryforward of $23.9 million at December 31, 2017, 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 its efforts to create operational efficiency leading up to and through the bankruptcy process, the Company has consolidated its miningoperations and land management into a partnership structure to match its legal form with the Company’s streamlined operations during 2016. As such,deferred taxes related to those operations are now reported based upon the book and tax outside basis difference in the partnership interests as provided inASC 740-30-25-7, which results in a different basis of presentation than used in 2015 under the Company’s prior legal structure.Valuation allowances were established in prior years for federal and state net operating losses and tax credits that were not offset by the reversal of othernet 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 were completely offset by a valuation allowance.On December 22, 2017 the Tax Cut and Jobs Act of 2017 (“the Act”) was signed into law making significant changes to the Internal Revenue Code.Changes include, but are not limited to, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after December 31, 2017, theelimination of the corporate alternative minimum tax regime effective for tax years beginning after December 31, 2017, implementation of a process wherebycorporations with unused alternative minimum tax credits will be refunded during 2018-2022, the transition of U.S. international taxation from a worldwidetax system to a territorial system, a one-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings as of December 31, 2017,further limitation on the deductibility of certain executive compensation, allowance for immediate capital expensing of certain qualified property, andlimitations on the amount of interest expense deductible beginning in 2018.The Company has not completed its analysis for the income tax effects of the Act but has provided its best estimate of the impact of the Act in its year-end income tax provision in accordance with the guidance and interpretations available as of the date of this filing for the items noted below. The Companyanticipates finalizing the analysis for the estimate by December 31, 2018, within the one year measurement period under SAB 118, for the following items:•Remeasurement of deferred taxes: deferred tax assets and liabilities attributable to the U.S. were remeasured from 35% to the reduced tax rate of 21%.The provisional amount related to the remeasurement of certain deferred tax assets and liabilities based on the rates at which they are expected toreverse in the future was $330.9 million of income tax expense, with an offsetting valuation allowance adjustment. Finalization of theremeasurement of deferred taxes will occur upon finalization of 2017 taxable income and attribute carryback claims.•One-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings: The provisional amount of income tax expenserelated to the mandatory deemed repatriation of foreign earnings was $1.5 million based on cumulative foreign earnings of $4.2 million. Thedeemed repatriation tax is completely offset with net operating loss carryforwards, with an offsetting valuation allowance adjustment and will notresult in a cash tax liability. Finalization of 2017 earnings and profits calculations and receipt of further guidance in the form of Notices orRegulations may change the provisional calculation.•Elimination of the corporate AMT regime: Existing AMT credits as of December 31, 2017 will be refunded over the next four years. The refund maybe subject to a sequestration reduction rate of approximately 6.6%. The Company has provisionally determined that it will receive a refund ofexisting AMT credits of approximately $22.4 million after an estimated sequestration reduction of $1.5 million. The valuation allowance previouslyrecorded against these credits has been released and a tax benefit of $22.4 million was recorded. The Company’s accounting policy regarding thebalance sheet presentation of the AMT credits is to record the balance as a deferred tax asset until a return is filed claiming a refund of a portion ofthe credit, at which time the amount will be presented as a tax receivable.F- 43Table of ContentsFinalization of the AMT credit balance will occur upon finalization of 2017 taxable income and attribute carryback claims as well as the receipt offurther guidance in the form of Notices or Regulations.•Elimination of executive compensation exemptions: The Act made changes to the $1 million limit on deductible compensation paid to certain“covered” employees. The Act eliminated exemptions for qualified performance based compensation and compensation paid after termination andexpanded the number of employees to which the limit applies. The Company recorded a provisional amount of $0.2 million of tax expense, with anoffsetting valuation allowance adjustment. The Act contains transitional rules, the implementation of which is uncertain at this time. The Companyis still analyzing related aspects of the Act including the impact of the transitional rules. The provisional amount detailed above may change whenfurther guidance is released that addresses these rules.Other provisions in the Act that may impact the company in future years include limitations on interest expense deductions and the global intangiblelow-taxed income “GILTI” rules covering foreign income earned in low-tax countries. There was no impact recorded for these changes in the 2017 provision.Additional work is necessary to do a more detailed review of the Act, but is anticipated to be completed by December 31, 2018.At December 31, 2017 additional tax losses were realized primarily as a result of the reversal of deductible temporary differences and percentagedepletion. A $35.7 million benefit was recorded from the release of valuation allowance offsetting alternative minimum tax credits that have becomerefundable by the Act, as well as carryback claims filed in the fourth quarter related to specific liability losses that resulted in claims for refund of previouslypaid alternative minimum taxes. At December 31, 2017 a $610.5 million valuation allowance fully offsets all net deferred tax assets, other than alternativeminimum tax credits.A reconciliation of the beginning and ending amounts of gross unrecognized tax benefits follows: (In thousands)Balance atJanuary 1, 2015$34,709Additions based on tax positions related to the current year4,168Balance atDecember 31, 201538,877Additions based on tax positions related to the current year2,979Additions for tax positions of prior years2,709Reductions as a result of lapses in the statute of limitations(37,110)Balance atDecember 31, 20167,455Additions for tax positions of prior years—Additions for tax positions related to the current year3,928Reductions as a result of bankruptcy—Balance atDecember 31, 2017$11,383If recognized, the entire amount of the gross unrecognized tax benefits at December 31, 2017 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 $0.6 million and $0.5 million at December 31, 2017 and 2016, respectively. In the next 12 months, $3.3 million gross unrecognized tax benefitsare expected to be reduced due to the expiration of the statute of limitations.F- 44Table of Contents16. 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, reclaiming refuse areas and slurry ponds and water treatment.The following table describes the changes to the Company’s asset retirement obligation liability: SuccessorPredecessor Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1throughOctober 1,2016(In thousands) Balance at beginning of period (including current portion)$356,742 $354,326$410,454Accretion expense30,209 7,63424,321Obligations of divested operations(12,569) —(14,702)Adjustments to the liability from changes in estimates(23,215) —3,003Liabilities settled(22,472) (5,218)(11,087)Fresh start accounting adjustment— —(57,663)Balance at period end$328,695 $356,742$354,326Current portion included in accrued expenses(19,840) (19,515)(17,290)Noncurrent liability$308,855 $337,227$337,036As of December 31, 2017, the Company had $531.7 million in surety bonds outstanding and $7.4 million in letters of credit to secure reclamationbonding obligations. Additionally, the Company has posted $2.6 million in cash as collateral related to reclamation surety bonds; this amount is recordedwithin “Noncurrent assets” on the Consolidated Balance Sheet.F- 45Table of Contents17. 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, coalcommodity contracts and interest rate swaps with fair values derived from quoted prices in over-the-counter markets or from prices received from direct brokerquotes. · 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, 2017 and 2016. 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: Fair Value at December 31, 2017 Total Level 1 Level 2 Level 3 (In thousands)Assets: Investments in marketable securities $155,846 $64,100 $91,746 $—Derivatives 7,339 — 1,985 5,354Total assets $163,185 $64,100 $93,731 $5,354Liabilities: Derivatives $7,217 $7,263 $26 $(72) 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) $— $109The 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- 46Table of ContentsThe following table summarizes the change in the fair values of financial instruments categorized as level 3. SuccessorPredecessor Year EndedDecember 31, 2017 October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016(In thousands) Balance, beginning of period $4,537 $3,842$2,432Realized and unrealized (gains) losses recognized in earnings, net (2,305) 926(1,686)Included in other comprehensive income — ——Purchases 4,910 1,2255,021Issuances (535) (34)(488)Settlements (1,181) (1,422)(1,437)Ending balance $5,426 $4,537$3,842 Net unrealized gains of $2.3 million were recognized during the year ended December 31, 2017 related to level 3 financial instruments held onDecember 31, 2017. Cash and Cash EquivalentsAt December 31, 2017 and 2016, the carrying amounts of cash and cash equivalents approximate their fair value.Fair Value of Long-Term Debt At December 31, 2017 and 2016, the fair value of the Company’s debt, including amounts classified as current, was $336.1 million and $362.9 million,respectively. Fair values are based upon observed prices in an active market, when available, or from valuation models using market information, which fallinto Level 2 in the fair value hierarchy. 18. Capital StockDividendsThe Company declared and paid cash dividends per share during the periods presented below:2017:Dividends per shareAmount (in thousands)1st quarter$—$—2nd quarter0.358,5633rd quarter0.358,2004th quarter0.357,606Total cash dividends declared and paid$1.05$24,369Future dividend declarations will be subject to ongoing Board review and authorization will be based on a number of factors, including business andmarket conditions, the Company’s future financial performance and other capital priorities.F- 47Table of ContentsShare Repurchase ProgramDuring April 2017, the Board of Directors of Arch Coal, Inc. authorized a new share repurchase program for up to $300 million of its common stock. InOctober 2017, the Company’s Board of Directors approved an incremental $200 million increase to the share repurchase program bringing the totalauthorization to $500 million. Below is a table showing the share repurchase activity in 2017:2017:Number of SharesAverage Repurchase Priceper ShareAmount (in thousands)1st quarter—$—$—2nd quarter710,701$71.8251,0433rd quarter2,208,133$75.49166,6854th quarter1,058,381$79.7384,381Total shares repurchased3,977,215$75.96$302,109The timing of any future share repurchases, and the ultimate number of shares purchased, will depend on a number of factors, including business andmarket conditions, the Company’s future financial performance and other capital priorities. The shares will be acquired in the open market or through privatetransactions in accordance with the Securities and Exchange Commission requirements. The share repurchase program has no termination date, but may beamended, suspended or discontinued at any time and does not commit the Company to repurchase shares of its common stock. The actual number and valueof the shares to be purchased will depend on the performance of the Company’s stock price and other market conditions.Outstanding WarrantsDuring 2017, holders of warrants had exercised 65,499 of the warrants, leaving 1,846,158 warrants outstanding at December 31, 2017.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.19. Stock-Based Compensation and Other Incentive PlansUnder 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 2.4 million at December 31, 2017.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.During 2017, the Company granted both time based awards and performance based awards. The time based awards vest over either a one or three yearperiod and the performance based awards vest over a three year period. The time based awards’ grant date fair value was determined based on the stock priceat the date of grant. The performance awards grant date fair value was determined using a Black-Scholes Monte Carlo simulation. A volatility of 50% and60% were selected for each of the performance-based awards 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 weighted average grant-date fair value follows:F- 48Table of Contents Time Based Awards Performance Based Awards Restricted StockUnitsWeightedAverage Grant-Date Fair Value Restricted StockUnitsWeighted AverageGrant-Date FairValue(Shares in thousands) Outstanding at January 1, 2017159$78.60 225$67.34Granted9281.91 86101.38Forfeited/Canceled(2)78.60 ——Vested(9)78.60 ——Unvested outstanding at December 31, 2017240$79.87 311$76.75The Company recognized expense related to restricted stock units of $10.4 million for the year ended December 31, 2017 and $1.0 million for the periodOctober 2, 2016 through December 31, 2016. As of December 31, 2017, there was $32.4 million of unrecognized share-based compensation expense which isexpected to be recognized over a weighted-average period of approximately three years.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. The liabilities are remeasured quarterly. The Company recognized expense of $0.7million for the year ended December 31, 2017, $1.6 million for the period October 2 through December 31, 2016, $7.2 million for the period January 1through October 1, 2016 and $7.9 million for the year ended December 31, 2015, respectively. The expense is included primarily in “Selling, general andadministrative expenses” in the accompanying consolidated statements of operations.Amounts accrued and unpaid for all grants under the plan totaled $8.7 million and $13.9 million as of December 31, 2017 and 2016, respectively.F- 49Table of Contents20. 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 2.43%. 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 Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1throughOctober 1, 2016 Year EndedDecember 31,2015(In thousands) Self-insured occupational disease benefits: Service cost $6,320 $1,583$3,465 $4,282Interest cost 4,651 1,1263,184 3,944Net amortization — —4,325 6,973Total occupational disease $10,971 $2,709$10,974 $15,199Traumatic injury claims and assessments 3,208 3,1626,628 16,781Total workers’ compensation expense $14,179 $5,871$17,602 $31,980The table below reconciles changes in the occupational disease liability for the respective period. SuccessorPredecessor(In thousands)Year EndedDecember 31,2017 October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016Beginning of period$111,159 $119,710$90,836Service cost6,320 1,5833,465Interest cost4,651 1,1263,184Curtailments(5,433) —4,156Actuarial (gain) loss12,242 (9,675)—Benefit and administrative payments(6,513) (1,585)(3,728)Fresh start accounting adjustment— —21,797 $122,426 $111,159$119,710F- 50Table of ContentsThe following table provides the assumptions used to determine the projected occupational disease obligation: SuccessorPredecessor Year Ended December31, 2017 October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016(Percentages) Occupational Disease Benefit Discount rate3.66 4.313.80Cost escalation rateN/A N/AN/ASummarized below is information about the amounts recognized in the accompanying consolidated balance sheets for workers’ compensation benefits: Year EndedDecember 31,2017 Year EndedDecember 31,2016(In thousands) Occupational disease costs$122,426 $111,159Traumatic and other workers’ compensation claims81,191 88,593Total obligations203,617 199,752Less amount included in accrued expenses18,782 15,184Noncurrent obligations$184,835 $184,568As of December 31, 2017, the Company had $123.0 million in surety bonds and letters of credit outstanding to secure workers’ compensationobligations.The Company’s recorded liabilities include $20.3 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 $3.3 million and$17.0 million, respectively.21. 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 Companyoffers a subsidy to eligible retirees based on age and years of service at retirement and contain other cost-sharing features such as deductibles andcoinsurance. The Company’s current funding policy is to fund the cost of all postretirement benefits as they are paid.On January 1, 2015, the Company’s cash balance and excess plans were amended to freeze new service credits for any new or active employee.F- 51Table of ContentsObligations and Funded Status.Summaries of the changes in the benefit obligations, plan assets and funded status of the plans are as follows: Pension Benefits Other Postretirement Benefits SuccessorPredecessor SuccessorPredecessor Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1throughOctober 1,2016 Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1throughOctober 1, 2016(In thousands) CHANGE IN BENEFIT OBLIGATIONS Benefit obligations at beginning of period$313,629 $341,427$301,292 $111,867 $120,311$103,460Service cost— —— 671 180393Interest cost11,169 2,7689,338 4,150 9783,223Divestitures (see Note 5 to the ConsolidatedFinancial Statements)(29,097) —— — ——Settlements(1,532) (135)— — ——Curtailments— —454 (520) —714Benefits paid(38,197) (11,009)(8,699) (8,152) (1,962)(8,273)Other-primarily actuarial (gain) loss14,126 (19,422)— 2,503 (7,640)—Fresh start accounting adjustments— —39,042 — —$20,794Benefit obligations at end of period$270,098 $313,629$341,427 $110,519 $111,867$120,311CHANGE IN PLAN ASSETS Value of plan assets at beginning of period$274,225 $292,726$273,499 $— $—$—Actual return on plan assets39,689 (7,899)27,811 ——Employer contributions429 407115 8,152 1,9628,273Benefits paid(38,197) (11,009)(8,699) (8,152) (1,962)(8,273)Divestitures$(20,504) $—$— $— $—$—Value of plan assets at end of period$255,642 $274,225$292,726 $— $—$—Accrued benefit cost$(14,456) $(39,404)$(48,701) $(110,519) $(111,867)$(120,311)ITEMS NOT YET RECOGNIZED AS A COMPONENTOF NET PERIODIC BENEFIT COST Prior service credit (cost)$— $—$— $— $—$—Accumulated gain16,178 6,751— 5,137 7,640— $16,178 $6,751$— $5,137 $7,640$—BALANCE SHEET AMOUNTS Current liability$(420) $(520)$(420) $(8,150) $(10,422)$(8,352)Noncurrent liability(14,036) (38,884)(48,281) (102,369) (101,445)(111,959) $(14,456) $(39,404)$(48,701) $(110,519) $(111,867)$(120,311)Pension BenefitsThe accumulated benefit obligation for all pension plans was $270.1 million and $313.6 million at December 31, 2017 and 2016, respectively.Due to the Company adopting the corridor method of amortizing actuarial gains (losses) during fresh start accounting, it is anticipated there will be noamortization recorded into net periodic benefit cost during 2018.Other Postretirement BenefitsDue to the Company adopting the corridor method of amortizing actuarial gains (losses) during fresh start accounting, it is anticipated there will be noamortization recorded into net periodic benefit cost during 2018.F- 52Table of ContentsComponents of Net Periodic Benefit Cost. The following table details the components of pension and postretirement benefit costs (credits): Pension Benefits Other Postretirement BenefitsSuccessorPredecessor SuccessorPredecessor Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1throughOctober 1,2016 Year EndedDecember 31,2015 Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1throughOctober 1,2016 Year EndedDecember 31,2015(In thousands) Service cost$— $—$— $9 $671 $180$393 $866Interest cost11,169 2,7689,338 14,604 4,150 9783,223 1,904Curtailments— —454 — (520) —(970) —Settlements(1,532) (135)— 2,656 — —— —Expected return on plan assets(16,498) (4,770)(13,623) (20,367) — —— —Amortization of prior servicecredits— —— — — —(7,854) (8,335)Amortization of other actuariallosses (gains)— —3,973 8,850 — —(849) (2,109)Net benefit cost (credit)$(6,861) $(2,137)$142 $5,752 $4,301 $1,158$(6,057) $(7,674)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 Year Ended December31, 2017 October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016(Percentages) Pension Benefits Discount rate3.49/3.27 3.953.39Rate of compensation increaseN/A N/AN/A Other Postretirement Benefits Discount rate3.49 3.933.37Rate of compensation increaseN/A N/AN/AF- 53Table of ContentsThe following table provides the weighted average assumptions used to determine net periodic benefit cost for the respective periods. SuccessorPredecessor Year EndedDecember 31, 2017 October 2throughDecember 31,2016January 1throughOctober 1,2016 Year Ended December 31,2015(Percentages) Pension Benefits Discount rate3.77 3.39/3.954.59/3.80 4.15/4.61/4.41/4.60Rate of compensation increaseN/A N/AN/A N/AExpected return on plan assets6.20 6.856.85 7.00 Other Postretirement Benefits Discount rate3.85 3.374.57/3.80 3.91Rate of compensation increaseN/A N/AN/A N/AExpected return on plan assetsN/A N/AN/A N/AThe discount rates used in 2017, 2016 and 2015 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 2018 is 6.2% 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, 2017 by $11.6 million and the net periodicpostretirement benefit cost for the year ended December 31, 2017 by $0.4 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 39% equity and 61% 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- 54Table of ContentsThe Company’s pension plan assets at December 31, 2017 and 2016, respectively, are categorized below according to the fair value hierarchy as definedin Note 17, “Fair Value Measurements”: Total Level 1 Level 2 Level 3 2017 2016 2017 2016 2017 2016 2017 2016 (In thousands)Equity Securities:(A) U.S. small-cap$5,064 $13,520 $5,064 $13,520 $— $— $— $—U.S. mid-cap22,640 29,687 6,017 9,422 16,623 20,265 — —U.S. large-cap43,232 70,226 21,416 34,107 21,816 36,119 — —Non-U.S.10,115 18,937 — — 10,115 18,937 — —Fixed income securities: —U.S. government securities(B)66,922 26,519 60,286 19,973 6,636 6,546 — —Non-U.S. government securities(C)4,050 1,567 — — 4,050 1,567 — —U.S. government asset and mortgagebacked securities(D)2,440 1,074 — — 2,440 1,074 — —Corporate fixed income(E)54,679 58,191 — — 54,679 58,191 — —State and local governmentsecurities(F)3,829 6,406 — — 3,829 6,406 — —Other investments(I)27,057 26,151 — — 8,457 6,910 18,600 19,241Total$240,028 $252,278 $92,783 $77,022 $128,645 $156,015 $18,600 $19,241Other fixed income(G)16,646 35,519 Short-term investments(H)8,573 8,598 Other liabilities(J)(9,605) (22,170) $255,642 $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- 55Table 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 2018, 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)2018$17,614 $12,381201917,834 12,549202018,174 12,990202118,635 13,239202219,235 13,423Next 5 years83,071 62,854 $174,563 $127,436Other 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 $18.0 million for the year ended December 31, 2017; $3.5 million for the period October 2 throughDecember 31, 2016; $13.8 million for the period January 1 through October 1, 2016; and $20.5 million for the year ended December 31, 2015, respectively.22. 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 share 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 Year EndedDecember 31, 2017October 2 throughDecember 31, 2016January 1 throughOctober 1, 2016Year EndedDecember 31, 2015(In Thousands) Weighted average shares outstanding: Basic weighted average shares outstanding23,72525,00221,29321,285Effect of dilutive securities51546720— Diluted weighted average shares outstanding24,24025,46921,31321,285F- 56Table of Contents23. 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, 2017 are as follows: Operating Leases Royalties (In thousands)2018$5,936 $3,58220194,655 5,92620202,260 6,95320211,985 7,21620222,024 7,003Thereafter8,292 34,371 $25,152 $65,051The Company has no obligations for future minimum payments under capital leases for equipment at December 31, 2017 and 2016.Rental expense, including amounts related to these operating leases and other shorter-term arrangements, amounted to $19.2 million in 2017, $5.0million for the period October 2 through December 31, 2016, $19.4 million for the period January 1 through October 1, 2016 and $28.4 million in 2015.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 $167.4 millionin 2017, $45.3 million for the period October 2 through December 31, 2016, $116.4 million for the period January 1 through October 1, 2016 and $227.7million in 2015.As of December 31, 2017, certain of the Company’s lease obligations were secured by outstanding surety bonds totaling $31.2 million.24. 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, 2017 and 2016, accounts receivable from electric utilities of $72.9 million and $96.0 million, respectively, represented 42%and 52% of total trade receivables at each date. As of December 31, 2017 and 2016, accounts receivable from sales of metallurgical-quality coal of $99.4million and $88.0 million, respectively, represented 58% and 48% 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- 57Table of Contentslocation are as follows: SuccessorPredecessor Year EndedDecember 31,2017 October 2 throughDecember 31,2016January 1 throughOctober 1, 2016 Year EndedDecember 31,2015(In thousands) Europe$388,926 $61,408$113,888 $170,314Asia264,503 55,63468,536 96,523North America88,145 43,83156,594 40,315Central and South America30,982 13,22441,861 55,323Africa14,901 —— —Brokered Sales6,137 —— 32,848Total$793,594 $174,097$280,879 $395,323The 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 98.2 million tons of coal in 2017. Approximately 66% of this tonnage (representingapproximately 55% 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 four years.Third-party sources of coalThe Company purchases coal from third parties that it sells to customers. Factors beyond the Company’s control could affect the availability of coalpurchased by the Company. Disruptions in the quantities of coal purchased by the Company could impair its ability to fill customer orders or require it topurchase coal from other sources at 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.25. 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, 2017 and 2016, the Company had accrued$0.2 million and $2.2 million, respectively, for all legal matters, including $0.2 million and $2.2 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 $97.2 million in 2018, 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 during the year ended December 31, 2015, respectively.F- 58Table of Contents26. Subsequent EventsOn February 13, 2018, the Company’s board of directors announced an increase in the Company’s quarterly dividend to $0.40 per common share from$0.35 per common share. The next quarterly cash dividend payment of $0.40 per common share is scheduled to be paid on March 15, 2018 to stockholders ofrecord at the close of business on March 5, 2018.27. Segment Information The Company’s reportable business segments are based on two distinct lines of business, metallurgical coal and thermal coal, and may include a numberof mine complexes. 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 assetretirement 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 uses Adjusted EBITDAR to measure the operating performance of its segments and allocateresources to the segments. Furthermore, analogous measures are used by industry analysts and investors to evaluate the Company’s operating performance.Investors should be aware that the Company’s presentation of Adjusted EBITDAR may not be comparable to similarly titled measures used by othercompanies. The Company reports its results of operations primarily through the following reportable segments: 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 West Virginia. Periods presented in this note have been recast for comparability.On September 14, 2017, the Company closed on its’ definitive agreement to sell Lone Mountain Processing LLC, an operating mine complex within theCompany’s metallurgical coal segment. Through this transaction the Company divested all active operations in the states of Kentucky and Virginia. Forfurther information on the divestiture, please see Note 5 to the Consolidated Financial Statements, “Divestitures.” Operating segment results for the year ended December 31, 2017, the Successor period October 2 through December 31, 2016 and the Predecessor periodsJanuary 1 through October 1, 2016 and the year ended December 31, 2015 are presented below. The Company measures its segments based on “adjustedearnings before interest, taxes, depreciation, depletion, amortization, accretion on asset retirements obligations, and reorganization items, net (AdjustedEBITDAR).” Adjusted EBITDAR does not reflect mine closure or impairment costs, since those are not reflected in the operating income reviewed bymanagement. See Note 6, “Impairment Charges and Mine Closure Costs” for discussion of these costs. The Corporate, Other and Eliminations groupingincludes these charges, as well as the change in fair value of coal derivatives and coal trading activities, net; corporate overhead; land management activities;other support functions; and the elimination of intercompany transactions. F- 59Table of Contents(In thousands) PRB MET Other Thermal Corporate,Other andEliminations ConsolidatedSuccessor YearEndedDecember 31, 2017 Revenues $1,024,197 $887,839 $396,504 $16,083 $2,324,623Adjusted EBITDAR 158,882 243,616 102,006 (86,747) 417,757Depreciation, depletion and amortization 36,349 70,896 13,588 1,631 122,464Accretion on asset retirement obligation 20,160 2,000 2,161 5,888 30,209Total Assets 390,665 548,476 134,397 906,094 1,979,632Capital expenditures 6,212 32,678 11,901 8,414 59,205Successor 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 15,214PredecessorPeriodJanuary 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 82,434Predecessor 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 2,253,916 5,041,881Capital expenditures 21,228 24,787 11,277 61,732 119,024F- 60Table of ContentsA reconciliation of segment Adjusted EBITDAR to consolidated income (loss) from continuing operations before income taxes follows: SuccessorPredecessor(In thousands) Year EndedDecember 31,2017 October 2throughDecember 31,2016January 1through October1, 2016 Year EndedDecember 31,2015 Income (loss) before income taxes $203,195 $34,605$1,237,455 $(3,286,522)Interest expense, net 24,256 10,754133,235 393,549Depreciation, depletion and amortization 122,464 32,604191,581 379,345Accretion on asset retirement obligations 30,209 7,63424,321 33,680Amortization of sales contracts, net 53,985 796(728) (8,811)Asset impairment and mine closure costs — —129,267 2,628,303Losses from disposed operations resulting from Patriot Coalbankruptcy — —— 116,343Gain on sale of Lone Mountain Processing, Inc. (21,297) —— —Net loss resulting from early retirement of debt and debt restructuring 2,547 —2,213 27,910Reorganization items, net 2,398 759(1,630,041) —Fresh start coal inventory fair value adjustment — 7,345— —Adjusted EBITDAR $417,757 $94,497$87,303 $283,797F- 61Table of Contents28. Quarterly Selected Financial Data (unaudited)Year Ended December 31, 2017March 31 June 30 September 30 December 31 (In thousands, except per share data) Revenues$600,975 $549,866 $613,538 560,244Gross profit$85,747 $62,577 $65,100 62,937Income from operations$66,264 $42,692 $72,489 $50,951Reorganization items, net$(2,828) $(21) $(43) $494Net income$51,668 $37,160 $68,351 $81,271Diluted income per common share$2.03 $1.48 $2.83 $3.64 PredecessorSuccessorYear Ended December 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$33,449Diluted income (loss) per common share$(9.71) $(8.26) $(2.41) $78.66$1.31(a) Challenging coal markets resulted in impairment charges relating to leased mineral reserves, prepaid mining royalties, investments in equity methodsubsidiaries and severance expense in 2016. See further discussion in Note 6, “Impairment Charges and Mine Closure Costs “ and Note 10, “Equity MethodInvestments and Membership Interests in Joint Ventures.”(b) The Company filed for bankruptcy on January 11, 2016 and subsequently emerged on October 5, 2016. See further discussion in Note 3, “Emergencefrom Bankruptcy and Fresh Start Accounting.”F- 62Table of ContentsSchedule IIArch Coal, Inc. and SubsidiariesValuation and Qualifying Accounts Additions (Reductions) Balance at Charged to Charged to Balance at Beginning of Costs and Other End of Year Expenses Accounts Deductions (a) Year (In thousands) Year Ended December 31, 2017 Reserves deducted from asset accounts: Accounts receivable and other receivables$— $—Current assets — supplies and inventory— 365 (17)(b) 87 261Deferred income taxes1,021,553 (410,982) 610,571Successor October 2 through December 31, 2016 Reserves deducted from asset accounts: Accounts receivable and other receivables$— $— $— $— $—Current assets — supplies and inventory— — — — —Deferred income taxes1,033,982 (12,429) — — 1,021,553Predecessor 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 — — 1,135,399(a) Reserves utilized, unless otherwise indicated.(b) Disposition of subsidiaries(c) Fresh start accounting adjustmentF- 63Exhibit 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 22, 2018: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%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%ICG Eastern Land, LLC (Delaware) 100%ICG Natural Resources, LLC (Delaware) 100%Exhibit 21.1Mountain 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 reports dated February 23, 2018, with respect to the consolidated financial statements and scheduleof Arch Coal, Inc. and subsidiaries, and the effectiveness of internal control over financial reporting of Arch Coal, Inc., included in thisAnnual Report (Form 10-K) for the year ended December 31, 2017./s/ Ernst & Young, LLPSt. Louis, MissouriFebruary 23, 2018Exhibit 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, 2017. 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 20, 2018Exhibit 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, 2017, 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 23, 2018/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. VogelDirectorExhibit 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 23, 2018Exhibit 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 23, 2018 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, 2017 (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 23, 2018 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, 2017 (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 23, 2018 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, 2017 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, 2017) 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.1Exhibit 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 OperationsVindex Wolf Den Run /18-00790—————0.1—NoNo———Beckley Pocahontas Mine /46‑0525296—5——407.1—NoNo1350Beckley Pocahontas Plant /46‑092164————1.2—NoNo———Coal Mac Holden #22 Prep Plant/46‑05909—————0.1—NoNo———Coal Mac Ragland Loadout /46‑08563—————0.1—NoNo———Coal Mac Holden #22 Surface /46‑089842————2.9—NoNo———Sentinel Mine /46‑0416830—2——46.7—NoNo—1—Sentinel Prep Plant /46‑087771————0.8—NoNo———Mingo Logan Mountaineer II /46‑09029651———218.0—NoNo12115Mingo Logan Cardinal Prep Plant/46‑090461————1.5—NoNo———Mingo Logan Daniel Hollow /46‑09047———————NoNo———Leer #1 Mine /46‑0919263————167.4—NoNo794Arch of Wyoming Elk Mountain/48‑01694———————NoNo———Black Thunder /48‑009772————6.7—NoNo———Coal Creek /48‑012153————5.3—NoNo—1—West Elk Mine /05‑0367213————71.5—NoNo———Viper Mine /11‑0266420————36.7—NoNo———Leer #1 Prep Plant /46-09191—————1.3—NoNo———Wolf Run Mining – Sawmill RunPrep Plant / 46-05544———————NoNo———Vindex Dobbin Ridge Prep Plant/046078371————0.3—NoNo———2Exhibit 95(1)See table below for additional details regarding Legal Actions Pending as of December 31, 2017Mine or Operating Name/MSHAIdentification NumberContests ofCitations,Orders (as ofDecember 31,2017)Contests ofProposedPenalties (as ofDecember 31,2017)Complaints forCompensation (asof December 31,2017)Complaints ofDischarge,Discrimination orInterference (as ofDecember 31, 2017)Applications forTemporary Relief(as ofDecember 31,2017)Appeals of Judges’Decisions orOrders (as ofDecember 31,2017)Beckley Pocahontas Mine / 46-0525237————Mingo Logan Mountaineer II / 46-09029—5————Leer #1 / 46‑09192—4————3

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