PART I
ITEM 1. BUSINESS
Introduction
We are one of the world’s largest coal producers. For the
year ended
December 31, 2017
, we sold approximately
98 million
tons of coal, including approximately
1.5 million
tons of coal we purchased from third parties. We sell substantially all of our coal to power plants, steel mills and industrial facilities. At
December 31, 2017
, we operated
9
active mines located in each of the major coal-producing regions of the United States. The locations of our mines and access to export facilities enable us to ship coal worldwide. We incorporate by reference the information about the geographical breakdown of our coal sales for the respective periods covered within this Form 10-K contained in Note
24
to the Consolidated Financial Statements.
Our History
We were organized in Delaware in 1969 as Arch Mineral Corporation. In July 1997, we merged with Ashland Coal, Inc., a subsidiary of Ashland Inc. that was formed in 1975. As a result of the merger, we became one of the largest producers of low‑sulfur coal in the eastern United States.
In June 1998, we expanded into the western United States when we acquired the coal assets of Atlantic Richfield Company. This acquisition included the Black Thunder and Coal Creek mines in the Powder River Basin of Wyoming, the West Elk mine in Colorado and a 65% interest in Canyon Fuel Company, which operated three mines in Utah. In October 1998, we acquired a leasehold interest in the Thundercloud reserve, a 412‑million‑ton federal reserve tract adjacent to the Black Thunder mine.
In July 2004, we acquired the remaining 35% interest in Canyon Fuel Company. In August 2004, we acquired Triton Coal Company’s North Rochelle mine adjacent to our Black Thunder operation. In September 2004, we acquired a leasehold interest in the Little Thunder reserve, a 719‑million‑ton federal reserve tract adjacent to the Black Thunder mine.
In December 2005, we sold the stock of Hobet Mining, Inc., Apogee Coal Company and Catenary Coal Company and their four associated mining complexes (Hobet 21, Arch of West Virginia, Samples and Campbells Creek) and approximately 455 million tons of coal reserves in Central Appalachia to Magnum Coal Company, which was subsequently acquired by Patriot Coal Corporation.
In October 2009, we acquired Rio Tinto’s Jacobs Ranch mine complex in the Powder River Basin of Wyoming, which included 345 million tons of low‑cost, low‑sulfur coal reserves, and integrated it into the Black Thunder mine.
In June 2011, we acquired International Coal Group, Inc., which owned and operated mines primarily in the Appalachian Region of the United States.
In August 2013, we sold the equity interests of Canyon Fuel Company, LLC (“Canyon Fuel”), which owned and operated our Utah operations.
Restructuring Under Chapter 11 of the United States Bankruptcy Code
On January 11, 2016 (the “Petition Date”), Arch and substantially all of its wholly owned domestic subsidiaries (the “Filing Subsidiaries” and, together with Arch, the “Debtors”) filed voluntary petitions for reorganization (collectively, the “Bankruptcy Petitions”) under Chapter 11 of Title 11 of the U.S. Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Eastern District of Missouri (the “Court”). The Debtor’s Chapter 11 Cases (collectively, the “Chapter 11 Cases”) were jointly administered under the caption
In re Arch Coal, Inc., et al.
Case No. 16-40120 (lead case). During the bankruptcy proceedings, each Debtor operated its business as a “debtor in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Court.
On September 13, 2016, the Bankruptcy Court entered an order, Docket No. 1324, confirming the Debtors’ Fourth Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code dated as of September 11, 2016 (the “Plan”), which order was amended on September 15, 2016, Docket No. 1334.
On October 5, 2016, Arch Coal emerged from Chapter 11 and the Plan became effective on such date (the “Effective Date”).
On the Plan Effective Date, we applied fresh start accounting which required us to allocate our reorganization value to the fair value of assets and liabilities in conformity with the guidance for the acquisition method of accounting for business combinations. In addition to fresh start accounting, our consolidated financial statements reflect all impacts of the transactions contemplated by the Plan. Under the provisions of fresh start accounting, a new entity has been created for financial reporting purposes. We selected an accounting convenience date of October 1, 2016 for purposes of applying fresh start accounting as the activity between the convenience date and the Effective Date does not result in a material difference in the results. References to “Successor” in the financial statements and accompanying footnotes are in reference to reporting dates on or after October 2, 2016; references to “Predecessor” in the financial statements and accompanying footnotes are in reference to reporting dates through October 1, 2016 which includes the impact of the Plan provisions and the application of fresh start accounting. As such, our financial statements for the Successor will not be comparable in many respects to its financial statements for periods prior to the adoption of fresh start accounting and prior to the accounting for the effects of the Plan.
For additional information, see Note
1
, “
Basis of Presentation
” and Note
3
, “
Emergence from Bankruptcy and Fresh Start Accounting
” to our Consolidated Financial Statements included within this Form 10-K.
Coal Characteristics
End users generally characterize coal as thermal coal or metallurgical coal. Heat value, sulfur, ash, moisture content, and volatility, in the case of metallurgical coal, are important variables in the marketing and transportation of coal. These characteristics help producers determine the best end use of a particular type of coal. The following is a description of these general coal characteristics:
Heat Value.
In general, the carbon content of coal supplies most of its heating value, but other factors also influence the amount of energy it contains per unit of weight. The heat value of coal is commonly measured in Btus. Coal is generally classified into four categories, lignite, subbituminous, bituminous and anthracite, reflecting the progressive response of individual deposits of coal to increasing heat and pressure. Anthracite is coal with the highest carbon content and, therefore, the highest heat value, nearing 15,000 Btus per pound. Bituminous coal, used primarily to generate electricity and to make coke for the steel industry, has a heat value ranging between 10,500 and 15,500 Btus per pound. Subbituminous coal ranges from 8,300 to 13,000 Btus per pound and is generally used for electric power generation. Lignite coal is a geologically young coal which has the lowest carbon content and a heat value ranging between 4,000 and 8,300 Btus per pound.
Sulfur Content.
Federal and state environmental regulations, including regulations that limit the amount of sulfur dioxide that may be emitted as a result of combustion, have affected and may continue to affect the demand for certain types of coal. The sulfur content of coal can vary from seam to seam and within a single seam. The chemical composition and concentration of sulfur in coal affects the amount of sulfur dioxide produced in combustion. Coal‑fueled power plants can comply with sulfur dioxide emission regulations by burning coal with low sulfur content, blending coals with various sulfur contents, purchasing emission allowances on the open market and/or using sulfur dioxide emission reduction technology.
Ash.
Ash is the inorganic residue remaining after the combustion of coal. As with sulfur, ash content varies from seam to seam. Ash content is an important characteristic of coal because it impacts boiler performance and electric generating plants must handle and dispose of ash following combustion. The composition of the ash, including the proportion of sodium oxide and fusion temperature, is also an important characteristic of coal, as it helps to determine the suitability of the coal to end users. The absence of ash is also important to the process by which metallurgical coal is transformed into coke for use in steel production.
Moisture.
Moisture content of coal varies by the type of coal, the region where it is mined and the location of the coal within a seam. In general, high moisture content decreases the heat value and increases the weight of the coal, thereby making it more expensive to transport. Moisture content in coal, on an as‑sold basis, can range from approximately 2% to over 30% of the coal’s weight.
Other.
Users of metallurgical coal measure certain other characteristics, including fluidity, swelling capacity and volatility to assess the strength of coke produced from a given coal or the amount of coke that certain types of coal will yield. These characteristics may be important elements in determining the value of the metallurgical coal we produce and market.
The Coal Industry
Background.
.
Coal is mined globally using various methods of surface and underground recovery. Coal is used primarily for the production of electric power and steel but is also used for chemical, food and cement processing. Coal is traded globally and can be transported to demand centers by ship, rail, barge, truck or conveyor belt.
Total world coal production exceeds 7.0 billion metric tons in 2017 according to the International Energy Agency (IEA). China is the largest producer of coal in the world, producing over 3.5 billion metric tons in 2017 according to the Chinese Bureau of Statistics. The United States and India follow 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 coal production occurs in the United States at mines located in Wyoming, Colorado, Illinois, and West Virginia. Subsequent to the sale of our Lone Mountain operation in the third quarter of 2017, our metallurgical coal is produced at operations in West Virginia. Heat value and sulfur content are the most important variables in the economic marketing and transportation of thermal coal. Carbon content, the composition of the non-carbon volatiles and other chemical constituents are critical characteristics for metallurgical coal.
The majority of our coal is sold at the mine where title and risk of loss transfer to the customer as coal is loaded into the railcar or truck. Customers are responsible for transportation - typically using third party carriers. There are some agreements where we retain responsibility for the coal during delivery to the customer site or intermediate terminal. Our international coal usually changes title and risk of loss as coal is loaded on an ocean vessel. We or our agent contracts for transportation services to the ocean loading port. On rare occasion, we might retain title to the coal to the ocean delivery port.
We seek to establish long-term relationships with customers through exemplary customer service while operating safe and environmentally responsible mines. We shipped to
35
states and
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 Energy Information Administration (EIA.) The coal we produced fueled approximately 4% of the electricity produced in the U.S. in 2017. We also exported 8% of our 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. metallurgical coal 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 producers of other energy sources including natural gas, renewables and nuclear, as well as other non-coal based forms of steel production. We compete with other coal producers and traders/brokers using price, coal quality, transportation, optionality, customer administration, reputation and reliability.
Coal demand and coal prices are tied to coal consumption patterns which are influenced by many uncontrollable factors. For power generation, the price of coal is affected by the relative supply and demand of competitive coal, transportation, availability and price of other non-coal forms of power production (particularly, natural gas), regulatory limits on using coal, taxes, the weather and economic conditions. For metallurgical coal, the price of coal is affected by the supply, demand and price of competitive coal, transportation, the price of steel, demand for steel, as well as regulations, taxes, and economic conditions.
We have an experienced and knowledgeable sales and marketing group. This group is dedicated to meeting customer needs, coordinating transportation, providing accounting services and managing risk.
U.S. Coal Production.
The United States is among the top three largest coal producers in the world, exceeded only by China and roughly equivalent to India based on preliminary data. According to the EIA, there are over 250 billion short tons of recoverable coal in the United States. The U.S. Department of Energy estimates that current domestic recoverable coal reserves could supply enough electricity to satisfy domestic demand for over 300 years.
Coal is mined from coal fields throughout the United States, with the major production centers located in the western United States, the Appalachian region and the Interior. According to the EIA and Mine Safety and Health Administration (MSHA), U.S. coal production increased by an estimated 45 million tons 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 United States increased from an estimated 404 million short tons in 2016 to 432 million short tons in 2017. The Powder River Basin is located in northeastern Wyoming and southeastern Montana and is the largest producing region in the United States. Coal from this region is sub-bituminous coal with low sulfur content ranging from 0.2% to 0.9% and heating values ranging from 8,300 to 9,500 Btu. The price of Powder River Basin coal is generally less than that of coal produced in other regions because Powder River Basin coal has a lower heat content, however it is produced from thick seams using surface recovery methods thus, has a lower cost of production. The Western Bituminous region includes Colorado, Utah and southern Wyoming. Coal from this region typically has low sulfur content ranging from 0.4% to 0.8% and heating values ranging from 10,000 to 12,200 Btu. Western bituminous coal has certain quality characteristics, especially its high heat content and low sulfur, that make this a desirable coal for domestic and international power producers.
The Appalachia region is divided into north, central and southern regions. According to the EIA, coal produced in the Appalachian region increased from 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 and increasing costs of production. However, virtually all U.S. metallurgical coal is produced in Appalachia and the relative scarcity and high-quality of this coal allows for a pricing premium over thermal coal. Appalachia, while still a major producer of thermal coal, is undergoing a shift towards heavier reliance on metallurgical coal production for both domestic and international use. This is especially the case in Central Appalachia.
Northern Appalachia includes Maryland, Ohio, Pennsylvania and northern West Virginia. Coal from this region generally has a high heat value ranging from 10,300 to 13,500 Btu and a sulfur content ranging from 0.8% to 4.0%. Central Appalachia includes eastern Kentucky, Tennessee, Virginia and Southern West Virginia. Coal mined from this region generally has a high heat value ranging from 11,400 to 13,200 Btu and low sulfur content ranging from 0.2% 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 content ranging from 0.7% to 3.0%.
The Interior region includes the Illinois Basin, Gulf Lignite production in Texas and Louisiana, and a small producing area in Kansas, Oklahoma, Missouri and Arkansas. The Illinois Basin is the largest producing region in the Interior and consists of Illinois, Indiana and western Kentucky. According to the EIA, coal produced in the Interior region increased from 144 million short tons in 2016 to approximately 145 million short tons in 2017. Coal from the Illinois Basin generally has a heat value ranging from 10,100 to 12,600 Btu and has a sulfur content ranging from 1.0% to 4.3%. Despite its high sulfur content, coal from the Illinois Basin can generally be used by electric power generation facilities that have installed emissions control devices, such as scrubbers.
Coal Mining Methods
The geological characteristics of our coal reserves largely determine the coal mining method we employ. We use two primary methods of mining coal: surface mining and underground mining.
Surface Mining.
We use surface mining when coal is found close to the surface. We have included the identity and location of our surface mining operations below under “Our Mining Operations-General.” The majority of the coal we produce comes from surface mining operations.
Surface mining involves removing the topsoil then drilling and blasting the overburden (earth and rock covering the coal) with explosives. We then remove the overburden with heavy earth‑moving equipment, such as draglines, power shovels, excavators and loaders. Once exposed, we drill, fracture and systematically remove the coal using haul trucks or conveyors to transport the coal to a preparation plant or to a loadout facility. We reclaim disturbed areas as part of our normal mining activities. After final coal removal, we use draglines, power shovels, excavators or loaders to backfill the remaining pits with the overburden removed at the beginning of the process. Once we have replaced the overburden and topsoil, we reestablish vegetation and plant life into the natural habitat and make other improvements that have local community and environmental benefits.
The following diagram illustrates a typical dragline surface mining operation:
Underground Mining.
We use underground mining methods when coal is located deep beneath the surface. We have included the identity and location of our underground mining operations below under “Our Mining Operations-General.”
Our underground mines are typically operated using one or both of two different mining techniques: longwall mining and room‑and‑pillar mining.
Longwall Mining.
Longwall mining involves using a mechanical shearer to extract coal from long rectangular blocks of medium to thick seams. Ultimate seam recovery using longwall mining techniques can exceed 75%. In longwall mining, continuous miners are used to develop access to these long rectangular coal blocks. Hydraulically powered supports temporarily hold up the roof of the mine while a rotating drum mechanically advances across the face of the coal seam, cutting the coal from the face. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface. Once coal is extracted from an area, the roof is allowed to collapse in a controlled fashion. The following diagram illustrates a typical underground mining operation using longwall mining techniques:
Room‑and‑Pillar Mining.
Room‑and‑pillar mining is effective for small blocks of thin coal seams. In room‑and‑pillar mining, a network of rooms is cut into the coal seam, leaving a series of pillars of coal to support the roof of the mine. Continuous miners are used to cut the coal and shuttle cars are used to transport the coal to a conveyor belt for further transportation to the surface. The pillars generated as part of this mining method can constitute up to 40% of the total coal in a seam. Higher seam recovery rates can be achieved if retreat mining is used. In retreat mining, coal is mined from the pillars as workers retreat. As retreat mining occurs, the roof is allowed to collapse in a controlled fashion.
The following diagram illustrates our typical underground mining operation using room‑and‑pillar mining techniques:
Coal Preparation and Blending.
We crush the coal mined from our Powder River Basin mining complexes and ship it directly from our mines to the customer. Typically, no additional preparation is required for a saleable product. Coal extracted from some of our underground mining operations contains impurities, such as rock, shale and clay occupying a wide range of particle sizes. All of our mining operations in the Appalachia region use a coal preparation plant located near the mine or connected to the mine by a conveyor. These coal preparation plants allow us to treat the coal we extract from those mines to ensure a consistent quality and to enhance its suitability for particular end‑users. In addition, depending on coal quality and customer requirements, we may blend coal mined from different locations, including coal produced by third parties, in order to achieve a more suitable product.
The treatments we employ at our preparation plants depend on the size of the raw coal. For coarse material, the separation process relies on the difference in the density between coal and waste rock and, for the very fine fractions, the separation process relies on the difference in surface chemical properties between coal and the waste minerals. To remove impurities, we crush raw coal and classify it into various sizes. For the largest size fractions, we use dense media vessel separation techniques in which we float coal in a tank containing a liquid of a pre‑determined specific gravity. Since coal is lighter than its impurities, it floats, and we can separate it from rock and shale. We treat intermediate sized particles with dense medium cyclones, in which a liquid is spun at high speeds to separate coal from rock. Fine coal is treated in spirals, in which the differences in density between coal and rock allow them, when suspended in water, to be separated. Ultra fine coal is recovered in column flotation cells utilizing the differences in surface chemistry between coal and rock. By injecting stable air bubbles through a suspension of ultra fine coal and rock, the coal particles adhere to the bubbles and rise to the surface of the column where they are removed. To minimize the moisture content in coal, we process most coal sizes through centrifuges. A centrifuge spins coal very quickly, causing water accompanying the coal to separate.
For more information about the locations of our preparation plants, you should see the section entitled “Our Mining Operations”.
Our Mining Operations
General.
At
December 31, 2017
, we operated
9
active mines in the United States. The Company’s reportable business segments are based on two distinct 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 our marketing and operations management. Our mining operations are evaluated based on Adjusted EBITDAR, per-ton cash operating costs (defined as including all mining costs except depreciation, depletion, amortization, accretion on asset retirements obligations, and pass-through transportation expenses), and on other non-financial measures, such as safety and environmental performance. Adjusted EBITDAR is defined as net income attributable to the Company before the effect of net interest expense, income taxes, depreciation, depletion and amortization, the amortization of sales contracts, the accretion on asset retirement obligations, and reorganization items, net. Adjusted EBITDAR may also be adjusted for items that may not reflect the trend of future results by excluding transactions that are not indicative of our core operating performance. We use Adjusted EBITDAR to measure the operating performance of our segments and allocate resources to our segments. Adjusted EBITDAR is not a measure of financial performance in accordance with generally accepted accounting principles, and items excluded from Adjusted EBITDAR are significant in understanding and assessing our financial condition. Therefore, Adjusted EBITDAR should not be considered in isolation, nor as an alternative to net income, income from operations, cash flows from operations or as a measure of our profitability, liquidity or performance under generally accepted accounting principles. Furthermore, analogous measures are used by industry analysts to evaluate the Company’s operating performance. Investors should be aware that our presentation of Adjusted EBITDAR may not be comparable to similarly titled measures used by other companies. The Company’s reportable segments are the Powder River Basin (PRB) segment containing the Company’s primary thermal operations in Wyoming; the Metallurgical (MET) segment, containing the Company’s metallurgical operations in West Virginia and the Other Thermal segment containing the Company’s supplementary thermal operations in Colorado, Illinois, and the Coal Mac thermal operation in West Virginia. For additional information about the operating results of each of our segments for the 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
, see Note
27
of the Consolidated Financial Statements.
In general, we have developed our mining complexes and preparation plants at strategic locations in close proximity to rail or barge shipping facilities. Coal is transported from our mining complexes to customers by means of railroads, trucks, barge lines, and ocean‑going vessels from terminal facilities. We currently own or lease under long‑term arrangements all of the equipment utilized in our mining operations. We employ sophisticated preventative maintenance and rebuild programs and upgrade our equipment to ensure that it is productive, well‑maintained and cost‑competitive.
The following table provides a summary of information regarding our active mining complexes as of
December 31, 2017
, including the total sales associated 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 for the total cost of property, plant and equipment of each mining complex does not include the costs of the coal reserves that we have assigned to an individual complex.
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Tons Sold
(1)
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Predecessor
|
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Successor
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Mining Complex
|
Captive Mines
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Mining Equipment
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Railroad
|
2015
|
Jan1-Oct1, 2016
|
Oct2-Dec31, 2016
|
2017
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Total Cost of Property, Plant and Equipment at December 31, 2017
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Total Assigned Recoverable Reserves
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(Million tons)
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($ millions)
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(Million tons)
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Powder River Basin:
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Black Thunder
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S
|
D, S
|
UP/BN
|
99.5
|
|
49.0
|
|
18.9
|
|
70.5
|
|
$
|
266.7
|
|
896.4
|
|
|
Coal Creek
|
S
|
D, S
|
UP/BN
|
7.8
|
|
5.5
|
|
2.7
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9.0
|
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43.5
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128.4
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Metallurgical:
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Mountain Laurel
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U
|
LW, CM
|
CSX
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2.0
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1.2
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0.4
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1.5
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25.2
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21.1
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Beckley
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U
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CM
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CSX
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0.9
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0.7
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0.3
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1.0
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38.7
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25.4
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Sentinel
|
U
|
CM
|
CSX
|
0.9
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0.8
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0.3
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1.5
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37.5
|
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4.7
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Leer
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U
|
LW, CM
|
CSX
|
2.9
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3.1
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1.0
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3.2
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217.0
|
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30.8
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Other Thermal:
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West Elk
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U
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LW, CM
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UP
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5.1
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2.4
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1.6
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4.9
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38.6
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53.1
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Viper
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U
|
CM
|
—
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2.1
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1.3
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0.3
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1.7
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25.0
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34.6
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Coal‑Mac
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S
|
L, E
|
NS/CSX
|
2.4
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1.5
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0.5
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2.4
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30.8
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22.7
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Totals
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123.6
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65.5
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26.0
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95.7
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$
|
723.0
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1,217.2
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S = Surface mine
|
D = Dragline
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UP = Union Pacific Railroad
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U = Underground mine
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L = Loader/truck
|
CSX = CSX Transportation
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S = Shovel/truck
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BN = Burlington Northern‑Santa Fe Railway
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E = Excavator/truck
|
NS = Norfolk Southern Railroad
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LW = Longwall
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CM = Continuous miner
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HW = Highwall miner
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(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 the table above.
|
Powder River Basin
Black Thunder.
Black Thunder is a surface mining complex located on approximately
35,800
acres in Campbell County, Wyoming. The Black Thunder complex extracts thermal coal from the Upper Wyodak and Main Wyodak seams.
We control a significant portion of the coal reserves through federal and state leases. The Black Thunder mining complex had approximately
896.4 million
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 rate of 190 million tons per year. Several large tracts of coal adjacent to the Black Thunder mining complex have been nominated for lease, and other potential large areas of unleased coal remain available for nomination by us or other mining operations. The U.S. Department of Interior Bureau of Land Management, which we refer to as the BLM, will determine if the tracts will be leased and, if so, the final boundaries of, and the coal tonnage for, these tracts.
The Black Thunder mining complex currently consists of four active pit areas and three loadout facilities. We ship all of the coal raw to our customers via the Burlington Northern Santa Fe and Union Pacific railroads. We do not process the coal mined at this complex. Each of the loadout facilities can load a 15,000‑ton train in less than two hours.
Coal Creek.
Coal Creek is a surface mining complex located on approximately
7,400
acres in Campbell County, Wyoming. The Coal Creek mining complex extracts thermal coal from the Wyodak‑R1 and Wyodak‑R3 seams.
We control a significant portion of the coal reserves through federal and state leases. The Coal Creek mining complex had approximately
128.4 million
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 of 50 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 the Burlington Northern Santa Fe and Union Pacific railroads. We do not process the coal mined at this complex. The loadout facility can load a 15,000‑ton train in less than three hours.
Metallurgical
Mountain 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 and Alma 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. The loadout facility can load a 15,000‑ton train in less than four hours.
Beckley.
The Beckley mining complex is located on approximately
19,700
acres in Raleigh County, West Virginia. Beckley is extracting high quality, low‑volatile metallurgical coal in the Pocahontas No. 3 seam. The Beckley mining complex had approximately
25.4 million
tons of proven and probable 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 a 10,000‑ton train in less than four hours.
Sentinel.
The Sentinel mining complex consists of one underground mine, a preparation plant and a loadout facility located on approximately
25,700
acres in Barbour County, West Virginia. Mining operations currently extract High-vol A metallurgical coal from the Clarion coal seam. Coal from the Sentinel mining complex is processed through the preparation plant and shipped by CSX rail to customers. The Sentinel mining complex had approximately
4.7 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 our Tygart Valley area. Substantially all of the reserves at Leer are owned rather than leased from third parties.
All the production is processed through a 1,400 ton‑per‑hour preparation plant and loaded on the CSX railroad. A 15,000‑ton train can be loaded in less than four hours.
Other Thermal
West Elk.
West Elk is an underground mining complex located on approximately
19,500
acres in Gunnison County, Colorado. The West Elk mining complex extracts thermal coal from the E seam.
We control a significant portion of the coal reserves through federal and state leases. The West Elk mining complex had approximately
53.1 million
tons 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 our customers via the Union Pacific railroad. The loadout facility can load an 11,000‑ton train in less than three hours.
Viper.
The Viper mining complex consists of one underground coal mine and a preparation plant located on approximately
39,700
acres in central Illinois near the city of Springfield. Mining operations extract thermal coal from the Illinois No. 5 seam, also referred to as the Springfield seam. All coal is processed through an 800 ton‑per‑hour preparation plant and shipped to customers by on‑highway trucks.
We control a significant portion of the coal reserves through private leases. As of
December 31, 2017
, we had approximately
34.6 million
tons of proven and probable reserves.
Coal‑Mac.
The surface mining complex is located on approximately
46,000
acres in Logan and Mingo Counties, West Virginia. Surface mining operations at the Coal‑Mac mining complex extract thermal coal primarily from the Coalburg and Stockton seams.
We control a significant portion of the coal reserves through private leases. The Coal‑Mac mining complex had approximately
22.7 million
tons of proven 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 and Ragland. We ship coal trucked to the Ragland loadout facility directly to our customers via the Norfolk Southern railroad. The Ragland loadout facility can load a 10,000‑ton train in less than four hours. We ship coal trucked to the Holden 22 loadout facility directly to our customers via the CSX railroad. We wash all of the coal transported to the Holden 22 loadout facility at an adjacent 600‑ton‑per‑hour preparation plant. The Holden 22 loadout facility can load a 10,000‑ton train in about four hours.
Sales, Marketing and Trading
Overview.
Coal prices are influenced by a number of factors and can vary materially by region. The price of coal within a region is influenced by market conditions, coal quality, transportation costs involved in moving coal from the mine to the point of use and mine operating costs. For example, higher heat and lower ash content generally result in higher prices, and higher sulfur and higher ash content generally result in lower prices within a given geographic region.
The cost of coal at the mine is also influenced by geologic characteristics such as seam thickness, overburden ratios and depth of underground reserves. It is generally less expensive to mine coal seams that are thick and located close to the surface than to mine thin underground seams. Within a particular geographic region, underground mining, which is the primary mining method we use in certain of our Appalachian mines, is generally more expensive than surface mining, which is the mining method we use in the Powder River Basin, and for one of our Appalachian mines. This is the case because of the higher capital costs, including costs for construction of extensive ventilation systems, and higher per unit labor costs due to lower productivity associated with underground mining.
Our sales, marketing and trading functions are principally based in St. Louis, Missouri and consist of sales and trading, transportation and distribution, quality control and contract administration personnel as well as revenue management. We also have sales representatives in our Singapore and London offices. In addition to selling coal produced from our mining complexes, from time to time we purchase and sell coal mined by others, some of which we blend with coal produced from our mines. We focus on meeting the needs and specifications of our customers rather than just selling our coal production.
Customers.
The Company markets its thermal and metallurgical coal to steel producers, domestic and foreign power generators, and other industrial facilities. For the
year ended
December 31, 2017
, we derived approximately
17%
of our total coal revenues from sales to our three largest customers,
United States Steel Corporation
,
ArcelorMittal
and
Southern Company
and approximately
41%
of our total coal revenues from sales to our
10
largest customers.
In
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 major coal-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 of
December 31, 2017
and
2016
, trade receivables related to metallurgical‑quality coal sales totaled
$99.4 million
and
$88.0 million
, respectively, or
58%
and
48%
of total trade receivables, respectively. We do not have foreign currency exposure for our international sales as all sales are denominated and settled in U.S. dollars.
The Company’s foreign revenues by coal shipment destination for the
year ended
December 31, 2017
, were as follows:
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|
|
|
|
|
|
|
(In thousands)
|
|
|
Europe
|
$
|
388,926
|
|
|
Asia
|
264,503
|
|
|
North America
|
88,145
|
|
|
Central and South America
|
30,982
|
|
|
Africa
|
14,901
|
|
|
Brokered Sales
|
6,137
|
|
|
Total
|
$
|
793,594
|
|
Long-Term Coal Supply Arrangements
As is customary in the coal industry, we enter into fixed price, fixed volume long-term supply contracts, the terms of which are more than one year, with many of our customers. Multiple year contracts usually have specific and possibly different volume and pricing arrangements for each year of the contract. Long-term contracts allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. In
2017
, we sold approximately
66%
of our coal under long-term supply arrangements. The majority of our supply contracts include a fixed price for the term of the agreement or a pre-determined escalation in price for each year. Some of our long-term supply agreements may include a variable pricing system. While most of our sales contracts are for terms of one to five years, some are as short as one month and other contracts have terms exceeding five years. At
December 31, 2017
, the average volume‑weighted remaining term of our long-term contracts was approximately 2.3 years, with remaining terms ranging from one to four years. At
December 31, 2017
, remaining tons under long-term supply agreements, including those subject to price re-opener or extension 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 coal sales agreements result from competitive bidding and negotiations with customers. Consequently, the terms of these contracts vary by customer, including base price adjustment features, price re‑opener terms, coal quality requirements, quantity parameters, permitted sources of supply, future regulatory changes, extension options,
force majeure
, termination, damages and assignment provisions. Our long‑term supply contracts typically contain provisions to adjust the base price due to new statutes, ordinances or regulations. We typically sell our metallurgical coal to non-North American customers based on various indices or agreements to mutually negotiate the price. These agreements generally are for one year and can reset pricing with each shipment. Additionally, some of our contracts contain provisions that allow for the recovery of costs affected by modifications or changes in the interpretations or application of any applicable statute by local, state or federal government authorities. These provisions only apply to the base price of coal contained in these supply contracts. In some circumstances, a significant adjustment in base price can lead to termination of the contract.
Certain of our contracts contain index provisions that change the price based on changes in market based indices or changes in economic indices or both. Certain of our contracts contain price re‑opener provisions that may allow a party to commence a renegotiation of the contract price at a pre‑determined time. Price re‑opener provisions may automatically set a new price based on prevailing market price or, in some instances, require us to negotiate a new price, sometimes within a specified range of prices. In a limited number of agreements, if the parties do not agree on a new price, either party has an option to suspend the agreement for the pricing period not agreed to. In addition, certain of our contracts contain clauses that may allow customers to terminate the contract in the event of certain changes in environmental laws and regulations that impact their operations.
Coal quality and volumes are stipulated in coal sales agreements. In most cases, the annual pricing and volume obligations are fixed, although in some cases the volume specified may vary depending on the customer consumption requirements. Most of our coal sales agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content (for thermal coal contracts), volatile matter (for metallurgical coal contracts), and for both types of contracts, sulfur, ash and moisture content. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts.
Our coal sales agreements also typically contain
force majeure
provisions allowing temporary suspension of performance by us or our customers, during the duration of events beyond the control of the affected party, including events such as strikes, adverse mining conditions, mine closures or serious transportation problems that affect us or unanticipated plant outages that may affect the buyer. Our contracts also generally provide that in the event a
force majeure
circumstance exceeds a certain time period, the unaffected party may have the option to terminate the purchase or sale in whole or in part. Some contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer. Agreements between our customers and the railroads servicing our mines may also contain
force majeure
provisions.
In most of our thermal coal contracts, we have a right of substitution (unilateral or subject to counterparty approval), allowing us to provide coal from different mines, including third‑party mines, as long as the replacement coal meets quality specifications and will be sold at the same equivalent delivered cost.
In some of our coal supply contracts, we agree to indemnify or reimburse our customers for damage to their or their rail carrier’s equipment while on our property, which result from our or our agents’ negligence, and for damage to our customer’s equipment due to non‑coal materials being included with our coal while on our property.
Trading.
In addition to marketing and selling coal to customers through traditional coal supply arrangements, we seek to optimize our coal production and leverage our knowledge of the coal industry through a variety of other marketing, trading and asset optimization strategies. From time to time, we may employ strategies to use coal and coal‑related commodities and contracts for those commodities in order to manage and hedge volumes and/or prices associated with our coal sales or purchase commitments, reduce our exposure to the volatility of market prices or augment the value of our portfolio of traditional assets. These strategies may include physical coal contracts, as well as a variety of forward, futures or options contracts, swap agreements or other financial instruments.
We maintain a system of complementary processes and controls designed to monitor and manage our exposure to market and other risks that may arise as a consequence of these strategies. These processes and controls seek to preserve our ability to profit from certain marketing, trading and asset optimization strategies while mitigating our exposure to potential losses. You should see Item 7A, entitled “Quantitative and Qualitative Disclosures About Market Risk” for more information about the market risks associated with these strategies at
December 31, 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 the costs 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 stable delivery costs. Transportation can be a large component of a purchaser’s total cost. Although the purchaser pays the freight, transportation costs still are important to coal mining companies because the purchaser may choose a supplier largely based on cost of transportation. Transportation costs borne by the customer vary greatly based on each customer’s proximity to the mine and our proximity to the loadout facilities. Trucks and overland conveyors haul coal over shorter distances, while barges, Great Lake carriers and ocean vessels move coal to export markets and domestic markets requiring shipment over the Great Lakes and several river systems.
Most coal mines are served by a single rail company, but much of the Powder River Basin is served by two rail carriers: the Burlington Northern‑Santa Fe railroad and the Union Pacific railroad; and our Coal Mac mine is served by both the CSX and Norfolk Souther railroads.. We generally transport coal produced at our Appalachian mining complexes via the CSX railroad or the Norfolk Southern railroad. Besides rail deliveries, some customers in the eastern United States rely on a river barge system.
We generally sell coal to international customers at an export terminal, and we are usually responsible for the cost of transporting coal to the export terminals. We transport our coal to Atlantic coast terminals, Pacific cost terminals or terminals along the Gulf of Mexico for transportation to international customers. Our international customers are generally responsible for paying the cost of ocean freight. We may also sell coal to international customers delivered to an unloading facility at the destination country.
We own a 35% interest in Dominion Terminal Associates, a partnership that operates a ground storage‑to‑vessel coal transloading facility in Newport News, Virginia. The facility has a rated throughput capacity of 20 million tons of coal per year and ground storage capacity of approximately 1.7 million tons. The facility primarily serves international customers, as well as domestic coal users located along the Atlantic coast of the United States. From time-to-time, we may lease a portion of our port capacity to third parties.
Competition
The coal industry is intensely competitive. The most important factors on which we compete are coal quality, delivered costs to the customer and reliability of supply. Our principal domestic competitors include Blackhawk Mining LLC, Blackjewel LLC, Contura Energy, Coronado Coal LLC, Corsa Coal Corp., Cloud Peak Energy, Peabody Energy Corp. and Ramaco Resources. Some of these coal producers are larger than we are and have greater financial resources and larger reserve bases than we do. We also compete directly with a number of smaller producers in each of the geographic regions in which we operate, as well as companies that produce coal from one or more foreign countries, such as Australia, Colombia, Indonesia and South Africa.
Additionally, coal competes with other fuels, such as natural gas, nuclear energy, hydropower, wind, solar and petroleum, for steam and electrical power generation. Costs and other factors relating to these alternative fuels, such as safety and environmental considerations, affect the overall demand for coal as a fuel.
Suppliers
Principal supplies used in our business include petroleum‑based fuels, explosives, tires, steel and other raw materials as well as spare parts and other consumables used in the mining process. We use third‑party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services and construction. We use sole source suppliers for certain parts of our business such as explosives and fuel, and preferred suppliers for other parts of our business such as dragline and shovel parts and related services. We believe adequate substitute suppliers are available. For more information about our suppliers, you should see Item 1A, “Risk Factors-Increases in the costs of mining and other industrial supplies, including steel‑based supplies, diesel fuel and rubber tires, or the inability to obtain a sufficient quantity of those supplies, could negatively affect our operating costs or disrupt or delay our production.”
Environmental and Other Regulatory Matters
Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety and the environment, including the protection of air quality, water quality, wetlands, special status species of plants and animals, land uses, cultural and historic properties and other environmental resources identified during the permitting process. Reclamation is required during production and after mining has been completed. Materials used and generated by mining operations must also be managed according to applicable regulations and law. These laws have, and will continue to have, a significant effect on our production costs and our competitive position.
We endeavor to conduct our mining operations in compliance with applicable federal, state and local laws and regulations. However, due in part to the extensive, comprehensive and changing regulatory requirements, violations during mining operations occur from time to time. We cannot assure you that we have been or will be at all times in complete compliance with such laws and regulations. Expenditures we incur to maintain compliance with all applicable federal and state laws have been and are expected to continue to be significant. Federal and state mining laws and regulations require us to obtain surety bonds to guarantee performance or payment of certain long‑term obligations, including mine closure and reclamation costs, federal and state workers’ compensation benefits, coal leases and other miscellaneous obligations. Compliance with these laws has substantially increased the cost of coal mining for domestic coal producers.
Future laws, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, may require substantial increases in equipment and operating costs and delays, interruptions or a termination of operations, the extent to which we cannot predict. Future laws, regulations or orders may also cause coal to become a less attractive fuel source, thereby reducing coal’s share of the market for fuels and other energy sources used to generate electricity. As a result, future laws, regulations or orders may adversely affect our mining operations, cost structure or our customers’ demand for coal.
The following is a summary of the various federal and state environmental and similar regulations that have a material impact on our business:
Mining Permits and Approvals.
Numerous governmental permits or approvals are required for mining operations. When we apply for these permits and approvals, we may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment. For example, in order to obtain a federal coal lease, an environmental impact statement must be prepared to assist the BLM in determining the potential environmental impact of lease issuance, including any collateral effects from the mining, transportation and burning of coal, which may in some cases include a review of impacts on climate change. The authorization, permitting and implementation requirements imposed by federal, state and local authorities may be costly and time consuming and may delay commencement or continuation of mining operations. In the states where we operate, the applicable laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if officers, directors, shareholders with specified interests or certain other affiliated entities with specified interests in the applicant or permittee have, or are affiliated with another entity that has, outstanding permit violations. Thus, past or ongoing violations of applicable laws and regulations could provide a basis to revoke existing permits and to deny the issuance of additional permits.
In order to obtain mining permits and approvals from federal and state regulatory authorities, mine operators must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition or other authorized use. Typically, we submit the necessary permit applications several months or even years before we plan to begin mining a new area. Some of our required permits are becoming increasingly more difficult and expensive to obtain, and the application review processes are taking longer to complete and becoming increasingly subject to challenge, even after a permit has been issued.
Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.
Surface Mining Control and Reclamation Act.
The Surface Mining Control and Reclamation Act, which we refer to as SMCRA, establishes mining, environmental protection, reclamation and closure standards for all aspects of surface mining as well as many aspects of underground mining. Mining operators must obtain SMCRA permits and permit renewals from the Office of Surface Mining, which we refer to as OSM, or from the applicable state agency if the state agency has obtained regulatory primacy. A state agency may achieve primacy if the state regulatory agency develops a mining regulatory program that is no less stringent than the federal mining regulatory program under SMCRA. All states in which we conduct mining operations have achieved primacy and issue permits in lieu of OSM.
In 1999, a federal court in West Virginia ruled that the stream buffer zone rule issued under SMCRA prohibited most excess spoil fills. While the decision was later reversed on jurisdictional grounds, the extent to which the rule applied to fills was left unaddressed. On December 12, 2008, OSM finalized a rulemaking regarding the interpretation of the stream buffer zone provisions of SMCRA which confirmed that excess spoil from mining and refuse from coal preparation could be placed in permitted areas of a mine site that constitute waters of the United States. That rule, however, was subject to a challenge in federal court. In addition, on November 30, 2009, OSM announced that it would re‑examine and reinterpret the regulations finalized eleven months earlier. On February 20, 2014, the federal court vacated the 2008 rule. On December 22, 2014, OSM published the final revisions to the stream buffer zone rule in the Federal Register. The revisions reinstated the previous version of the rule, but did not announce a new interpretation of the rule regarding the ability to construct excess spoil fills. On December 19, 2016, OSM finalized the “Stream Protection Rule,” a re-written version of the stream buffer zone rule which would have required coal operators to restrict mining within 100 feet of waterways. The rule would have also required states to impose additional information gathering and monitoring at and around coal mining sties and would have mandated new financial assurance and reclamation requirements. This rule could have restricted coal producers’ ability to develop new mines, or could have required coal producers to modify existing operations, curtailing surface mine operations in and near streams, especially in Appalachia. However, on February 2, 2017, Congress voted to repeal the stream protection rule under the Congressional Review Act. President Trump signed the bill repealing the rule on February 16, 2017.
SMCRA permit provisions include a complex set of requirements which include, among other things, coal prospecting; mine plan development; topsoil or growth medium removal and replacement; selective handling of overburden materials; mine pit backfilling and grading; disposal of excess spoil; protection of the hydrologic balance; subsidence control for underground mines; surface runoff and drainage control; establishment of suitable post mining land uses; and revegetation. We begin the process of preparing a mining permit application by collecting baseline data to adequately characterize the pre‑mining environmental conditions of the permit area. This work is typically conducted by third‑party consultants with specialized expertise and includes surveys and/or assessments of the following: cultural and historical resources; geology; soils; vegetation; aquatic organisms; wildlife; potential for threatened, endangered or other special status species; surface and ground water hydrology; climatology; riverine and riparian habitat; and wetlands. The geologic data and information derived from the other surveys and/or assessments are used to develop the mining and reclamation plans presented in the permit application. The mining and reclamation plans address the provisions and performance standards of the state’s equivalent SMCRA regulatory program, and are also used to support applications for other authorizations and/or permits required to conduct coal mining activities. Also included in the permit application is information used for documenting surface and mineral ownership, variance requests, access roads, bonding information, mining methods, mining phases, other agreements that may relate to coal, other minerals, oil and gas rights, water rights, permitted areas, and ownership and control information required to determine compliance with OSM’s Applicant Violator System, including the mining and compliance history of officers, directors and principal owners of the entity.
Once a permit application is prepared and submitted to the regulatory agency, it goes through an administrative completeness review and a thorough technical review. Also, before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of all reclamation obligations. After the application is submitted, a public notice or advertisement of the proposed permit is required to be given, which begins a notice period that is followed by a public comment period before a permit can be issued. It is not uncommon for a SMCRA mine permit application to take over a year to prepare, depending on the size and complexity of the mine, and anywhere from six months to two years or even longer for the permit to be issued. The variability in time frame required to prepare the application and issue the permit can be attributed primarily to the various regulatory authorities’ discretion in the handling of comments and objections relating to the project received from the general public and other agencies. Also, it is not uncommon for a permit to be delayed as a result of litigation related to the specific permit or another related company’s permit.
In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund, which was created by SMCRA, requires a fee on all coal produced. The proceeds of the fee are used to restore mines closed or abandoned prior to SMCRA’s adoption in 1977. The current fee is $0.28 per ton of coal produced from surface mines and $0.12 per ton of coal produced from underground mines. In
2017
, we recorded
$24.6 million
of expense related to these reclamation fees.
Surety Bonds.
Mine operators are often required by federal and/or state laws, including SMCRA, to assure, usually through the use of surety bonds, payment of certain long‑term obligations including mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other miscellaneous obligations. Although surety bonds are usually noncancelable during their term, many of these bonds are renewable on an annual basis.
The costs of these bonds have 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 of
December 31, 2017
, we posted an aggregate of approximately
$531.7 million
in surety bonds for reclamation purposes and secured
$10.0 million
in letters of credit and cash for reclamation bonding obligations. In addition, we had approximately
$161.6 million
of surety bonds, cash and letters of credit outstanding at
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 and coal lease obligations and, therefore, our ability to mine or lease coal, and a loss or reduction in our ability to self-bond could have a material, adverse effect on our business and results of operations,” contained in Item 1A, “Risk Factors—Risk Related to Our Operations,” for a discussion of certain risks associated with our surety bonds.
Mine Safety and Health.
Stringent safety and health standards have been imposed by federal legislation since Congress adopted the Mine Safety and Health Act of 1969. The Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed comprehensive safety and health standards on all aspects of mining operations. In addition to federal regulatory programs, all of the states in which we operate also have programs aimed at improving mine safety and health. Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive and pervasive systems for the protection of employee health and safety affecting any segment of U.S. industry.
Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on production of up to $1.10 per ton for coal mined in underground operations and up to $0.55 per ton for coal mined in surface operations. These amounts may not exceed 4.4% of the gross sales price. This excise tax does not apply to coal shipped outside the United States. In
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. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emissions control requirements relating to particulate matter which may include controlling fugitive dust. The Clean Air Act also indirectly affects coal mining operations, for example, by extensively regulating the emissions of fine particulate matter measuring 2.5 micrometers in diameter or smaller, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal‑fueled power plants and industrial boilers, which are the largest end‑users of our coal. Continued tightening of the already stringent regulation of emissions is likely, such as the Mercury and Air Toxics Standard (MATS), finalized in 2011 and discussed in more detail below. In addition, the U.S. Environmental Protection Agency, which we refer to as the EPA, has issued regulations on additional emissions, such as greenhouse gases (GHG’s), from new, modified, reconstructed and existing electric generating units, including coal-fired plants. Other GHG regulations apply to industrial boilers (see discussion of Climate Change, below). These regulations could eventually reduce the demand for coal.
Clean Air Act requirements that may directly or indirectly affect our operations include the following:
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Acid Rain.
Title IV of the Clean Air Act, promulgated in 1990, imposed a two‑phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and applies to all coal‑fueled power plants with a capacity of more than 25‑megawatts. Generally, the affected power plants have sought to comply with these requirements by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading sulfur dioxide emissions allowances. Although we cannot accurately predict the future effect of this Clean Air Act provision on our operations, we believe that implementation of Phase II has been factored into the pricing of the coal market.
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Particulate Matter.
The Clean Air Act requires the EPA to set national ambient air quality standards, which we refer to as NAAQS, for certain pollutants associated with the combustion of coal, including sulfur dioxide, particulate matter, nitrogen oxides and ozone. Areas that are not in compliance with these standards, referred to as non‑attainment areas, must take steps to reduce emissions levels. For example, NAAQS currently exist for particulate matter measuring 10 micrometers in diameter or smaller (PM10) and for fine particulate matter measuring 2.5 micrometers in diameter or smaller (PM2.5), and the EPA revised the PM2.5 NAAQS on December 14, 2012, making it more stringent. The states were required to make recommendations on nonattainment designations for the new NAAQS in late 2013. The EPA issued final designations for most areas of the country in 2012 and made some revisions in 2015. Individual states must now identify the sources of emissions and develop emission reduction plans. These plans may be state‑specific or regional in scope. Under the Clean Air Act, individual states have up to 12 years from the date of designation to secure emissions reductions from sources contributing to the problem. Future regulation and enforcement of the new PM2.5 standard, as well as future revisions of PM standards, will affect many power plants, especially coal‑fueled power plants, and all plants in non‑attainment areas.
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Ozone.
On October 26, 2015, the EPA published a final rule revising the existing primary and secondary NAAQS for ozone, reducing them to 70ppb on an 8-hour average. On November 17, 2016, the EPA issued a proposed implementation rule on non-attainment area classification an state implementation plans (SIPS). Significant additional emission control expenditures will likely be required at certain coal‑fueled power plants to meet the new stricter NAAQS. Nitrogen oxides, which are a byproduct of coal combustion, are classified as an ozone precursor. As a result, emissions control requirements for new and expanded coal‑fueled power plants and industrial boilers will continue to become more demanding in the years ahead. A suit challenging the EPA’s 2015 Ozone NAAQS,
Murray Energy Corp. v. EPA
, is currently pending in the United 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. Circuit granted the EPA’s motion, which cites President Trump’s March 28, 2017 Energy Independence Executive Order, to indefinitely delay any decision 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 days after the notice is
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published in the Federal Register. For the remaining areas of the United States, the EPA has not yet prepared final designations but plans to do so in a separate future action.
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NOx SIP Call.
The Nitrogen Oxides State Implementation Plan (NOx SIP) Call program was established by the EPA in October 1998 to reduce the transport of ozone on prevailing winds from the Midwest and South to states in the Northeast, which said that they could not meet federal air quality standards because of migrating pollution. The program was designed to reduce nitrous oxide emissions by one million tons per year in 22 eastern states and the District of Columbia. Phase II reductions were required by May 2007. As a result of the program, many power plants were required to install additional emission control measures, such as selective catalytic reduction devices. Installation of additional emission control measures has made it more costly to operate coal‑fueled power plants, which could make coal a less attractive fuel.
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Interstate Transport.
The EPA finalized the Clean Air Interstate Rule, which we refer to as CAIR, in March 2005. CAIR called for power plants in 28 Eastern states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrous oxide, which could lead to non-attainment of PM2.5 and ozone NAAQS in downwind states (interstate transport), pursuant to a cap and trade program similar to the system now in effect for acid deposition control. In July 2008, in
State of North Carolina v. EPA
and consolidated cases, the D.C. Circuit disagreed with the EPA’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 the rule to the EPA. The EPA proposed a revised transport rule on August 2, 2010 (75 Fed. Reg. 45209) to address attainment of the 1997 ozone NAAQS and the 2006 PM2.5 NAAQS. The rule was finalized as the Cross State Air Pollution Rule (CSAPR) on July 6, 2011, with compliance required for SO2 reductions beginning January 1, 2012 and compliance with NOx reductions required by May 1, 2012. Numerous appeals of the rule were filed and, on August 21, 2012, the D.C. Circuit vacated the rule, leaving the EPA to continue implementation of the CAIR. Controls required under the CAIR, especially in conjunction with other rules may have affected the market for coal inasmuch as multiple existing coal fired units were being retired rather than having required controls installed.
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The U.S. Supreme Court agreed to hear the EPA’s appeal of the decision vacating CSAPR and on April 29, 2014, issued an opinion reversing the August 21, 2012 D.C. Circuit decision, remanding the case back to the D.C. Circuit. The EPA then requested that the court lift the CSAPR stay and toll the CSAPR compliance deadlines by three years. On October 23, 2014, the D.C. Circuit granted the EPA’s request, and that court later dismissed all pending challenges to the rule on July 28, 2015 but it remanded some state budgets to EPA for further consideration. CSAPR Phase 1 implementation began in 2015, with Phase 2 beginning in 2017. CSAPR generally requires greater reductions than under CAIR. As a result, some coal‑fired power plants will be required to install costly pollution controls or shut down which may adversely affect the demand for coal. Finally, in October 2016, the EPA issued an update to the CSAPR to address interstate transport of air pollution under the more recent 2008 ozone NAAQS and the state budgets remanded by the D.C. Circuit. Consolidated judicial challenges to the rule are now pending, but on August 10, 2017, the D.C. Circuit suspended briefing in the litigation after industry petitioners challenging the rule requested to delay proceedings so EPA can determine whether to reconsider the revised CSAPR. If the rule is upheld, it is likely the CSAPR update will increase the pressure to install controls or shut down units, which may further adversely affect the demand for coal.
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Mercury.
In February 2008, the D.C. Circuit vacated the EPA’s Clean Air Mercury Rule (CAMR), which was promulgated to reduce mercury emissions from coal-fired power plants and remanded it to the EPA for reconsideration. In response, the EPA announced an Electric Generating Unit (EGU) Mercury and Air Toxics Standard (MATS) on December 16, 2011. The MATS was finalized April 16, 2012, and required compliance for most plants by 2015. In addition, before the court decision vacating the CAMR, some states had either adopted the CAMR or adopted state‑specific rules to regulate mercury emissions from power plants that are more stringent than the CAMR. MATS compliance, coupled with state mercury and air toxics laws and other factors have required many plants to install costly controls, re-fire with natural gas or to retire, which may adversely affect the demand for coal.
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MATS was challenged in the D.C. Circuit, which upheld the rule on April 15, 2013. Petitioners successfully obtained Supreme Court review, and on June 29, 2015, the Supreme Court issued a 5-4 decision striking down the final rule based on the EPA’s failure to consider economic costs in determining whether to regulate. The case was remanded to the D.C. Circuit. The EPA began reconsideration of costs, and petitioners unsuccessfully sought a stay of the rule in the Supreme Court in February 2016. In April 2016, the EPA issued a MATS 2016 Supplemental Finding, a final finding that it is appropriate and necessary to set standards for emissions of air toxics from coal- and oil-fired power plants. That finding is now being challenged in court. Therefore, the rule
remains in effect until further order of the D.C. Circuit. The D.C. Circuit denied petitioners’ motion to temporarily halt the pending litigation to allow the new administration to evaluate whether it can resolve any issues raised in the case. However, in April 2017, the EPA requested a delay in the D.C. Circuit proceedings while EPA is reviewing the determinations of the prior administration. Hence, while MATS will likely continue to impact coal-fueled generation as discussed above for at least the near term, the future course of the Rule is unclear.
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Regional Haze.
The EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks, particularly those located in the southwest and southeast United States. Under the Regional Haze Rule, affected states were required to submit regional haze SIPs by December 17, 2007, that, among other things, were to identify facilities that would have to reduce emissions and comply with stricter emission limitations. The vast majority of states failed to submit their plans by December 17, 2007, and the EPA issued a Finding of Failure to Submit plans on January 15, 2009 (74 Fed. Reg. 2392). The EPA had taken no enforcement action against states to finalize implementation plans and was slowly dealing with the state Regional Haze SIPs that were submitted, which resulted in the National Parks Conservation Association commencing litigation in the D.C. Circuit on August 3, 2012, against the EPA for failure to enforce the rule
(National Parks Conservation Act v. EPA, D.C. Cir)
. Industry groups, including the Utility Air Regulatory Group have intervened
(Utility Air Regulatory Group v. EPA. D.C. Cir 12‑1342, 8/6/2012
).
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The EPA ultimately agreed in a consent decree with environmental groups to impose regional haze federal implementation plans (FIPs) or to take action on regional haze SIPs before the agency for 42 states and the District of Columbia. The EPA has completed those actions for all but several states in its first planning period (2008-2010). In many eastern states, the EPA has allowed states to meet “best available retrofit control technology” (BART) requirements for power plants through compliance with CAIR and CSAPR (a policy under pending litigation). Other states have had BART imposed on a case-by-case basis, and where the EPA found SIPs deficient, it disapproved them and issued FIPs. It is possible that the EPA may continue to increase the stringency of control requirements imposed under the Regional Haze Program as it moves toward the next planning period, which could be delayed until 2021.
This program may result in additional emissions restrictions from new coal‑fueled power plants whose operations may impair visibility at and around federally protected areas. This program may also require certain existing coal‑fueled power plants to install additional control measures designed to limit haze‑causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could affect the future market for coal. However, on January 18, 2018, EPA announced that it was revisiting the 2017 Regional Haze Rule revisions, and announced an intent to commence a new rulemaking. This proceeding may slow or even roll back certain Regional Haze requirements.
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New Source Review.
A number of pending regulatory changes and court actions are affecting the scope of the EPA’s new source review program, which under certain circumstances requires existing coal‑fueled power plants to install the more stringent air emissions control equipment required of new plants. The new source review program is continually revised and such revisions may impact demand for coal nationally.
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Climate Change.
Carbon dioxide, which is considered to be a greenhouse gas, is a by-product of burning coal. Global climate issues, including with respect to greenhouse gases such as carbon dioxide and the relationship that greenhouse gases may have with perceived global warming, continue to attract significant public and scientific attention. For example, the Fourth and Fifth Assessment Reports of the Intergovernmental Panel on Climate Change have expressed concern about the impacts of human activity, especially from fossil fuel combustion, on global climate issues. As a result of the public and scientific attention, several governmental bodies increasingly are focusing on global climate issues and, more specifically, levels of emissions of carbon dioxide from coal combustion by power plants. Future regulation of greenhouse gas emissions in the United States could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes and the federal, state or local level or otherwise.
Demand for coal also may be impacted by international efforts to reduce emissions 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 for Reconstruction and Development, have announced that they will no longer provide financing for the development of new coal-fueled power plants, subject to very narrow exceptions.
Although the U.S. Congress has considered various legislative proposals that would address global climate issues and greenhouse gas emissions, no such federal proposals have been adopted into law to date. In the absence of U.S. federal legislation on these topics, the U.S. Environmental Protection Agency (the “EPA”) has been the primary source of federal oversight, although future regulation of greenhouse gases and global climate matters in the United States could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act, federal adoption of a greenhouse gas regulatory scheme or otherwise.
In 2007, the U.S. Supreme Court held that the EPA has authority under the Clean Air Act to regulate carbon dioxide emissions from automobiles and can decide against regulation only if the EPA determines that carbon dioxide does not significantly contribute to climate change and does not endanger public health or the environment. Although the Supreme Court’s holding did not expressly involve the EPA’s authority to regulate greenhouse gas emissions from stationary sources, such as coal-fueled power plants, the EPA since has determined on its own that it has the authority to regulate greenhouse gas emissions from power plants, and the EPA has published a formal determination that six greenhouse gases, including carbon dioxide, endanger both the public health and welfare of current and future generations.
In 2014, the EPA proposed a sweeping rule, known as the “Clean Power Plan,” to cut carbon emissions from existing electric generating units, including coal-fired power plants. A final version of the Clean Power Plan was adopted in August 2015. The final version of the Clean Power Plan aims to reduce carbon dioxide emissions from electrical power generation by 32% by 2030 relative to 2005 levels through reduction of emissions from coal-burning power plants and increased use of renewable energy and energy conservation methods. Under the Clean Power Plan, states are free to reduce emissions by various means and must submit emissions reduction plans to the EPA by September 2016 or, with an approved extension, September 2018. If a state has not submitted a plan by then, the Clean Power Plan authorizes the EPA to impose its own plan on that state. In order to determine a state’s goal, the EPA has divided the country into three regions based on connected regional electricity grids. States are to implement their plans by focusing on (i) increasing the generation efficiency of existing fossil fuel plants, (ii) substituting lower carbon dioxide emitting natural gas generation for coal-powered generation and (iii) substituting generation from new zero carbon dioxide emitting renewable sources for fossil fuel powered generation. States are permitted to use regionally available low carbon generation sources when substituting for in-state coal generation and coordinate with other states to develop multi-state plans. Following the adoption, 27 states sued the EPA, claiming that the EPA overstepped its legal authority in adopting the Clean Power Plan. In February 2016, the U.S. Supreme Court ordered the EPA to halt enforcement of the Clean Power Plan until a lower court rules on the lawsuit and until the Supreme Court determines whether or not to hear the case. In October 2017, EPA commenced rulemaking proceedings to rescind the Clean Power Plan, and in December 2017, EPA published an Advanced Notice of Proposed Rulemaking announcing an intent to commence a new rulemaking to replace the Clean Power 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 refer to as NSPS, for carbon dioxide emissions from new, modified, and reconstructed power plants under the Clean Air Act. One of the primary issues in these lawsuits is the EPA’s establishment of standards of performance based on technologies including carbon capture and sequestration, which we refer to as CCS. New coal plants cannot meet the new standards unless they implement CCS, which reportedly is not yet commercially available or technically feasible. In conjunction 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, and the 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 to address climate change over the next several decades. This agreement entered into force in November 2016 after more than 70 countries, including the United States, ratified or otherwise agreed to be bound by the agreement. The United States was among the countries that submitted its declaration of intended greenhouse gas reductions in early 2015, stating its intention to reduce U.S. greenhouse gas emissions by 26-28% by 2025 compared to 2005 levels. Whether and to what extent the United States meets its stated intention likely depends on several factors, including whether the presently-stayed Clean Power Plan (or a comparable alternative) is implemented. On June 1, 2017, The Trump Administration announced the United States was withdrawing from the Paris Agreement. Regardless of the extent to which the United States ultimately participates in these reductions, over the long term, international participation in the Paris Agreement framework could reduce overall demand for coal which could have a material adverse impact on us. These effects could be more adverse to the extent the United States ultimately participates in these reductions (whether via the Paris Agreement or otherwise).
Several U.S. states have enacted legislation establishing greenhouse gas emissions reduction goals or requirements or joined regional greenhouse gas reduction initiatives. Some states also have enacted legislation or regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources. For example, nine northeastern states currently are members of the Regional Greenhouse Gas Initiative, which is a mandatory cap-and-trade program established in 2005 to cap regional carbon dioxide emissions from power plants. Six midwestern states and one Canadian province entered into the Midwestern Regional Greenhouse Gas Reduction Accord to establish voluntary regional greenhouse gas reduction targets and develop a voluntary multi-sector cap-and-trade system to help meet the targets, although it has been reported that the members no longer are actively pursuing the group’s activities. Lastly, California and Quebec remain members of the Western Climate Initiative, which was formed in 2008 to establish a voluntary regional greenhouse gas reduction goal and develop market-based strategies to achieve emissions reductions, and those two jurisdictions have adopted their own greenhouse gas cap-and-trade regulations. Several states and provinces that originally were members of these organizations, as well as some current members, have joined the new North America 2050 initiative, which seeks to reduce greenhouse gas emissions and create economic opportunities aside from cap-and-trade programs. Any particular state, or any of these or other regional group, may have or adopt in the future rules or policies that cause some users of coal to switch from coal to a lower carbon fuel. There can be no assurance at this time that a carbon dioxide cap-and-trade-program, a carbon tax or other regulatory or policy regime, if implemented by any one or more states or regions in which our customers operate or at the federal level, will not affect the future market for coal in those states or regions and lower the overall demand for coal.
Clean Water Act.
The federal Clean Water Act (sometimes shortened to CWA) and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including dredged and fill materials, into waters of the United States. The Clean Water Act provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. Recent court decisions and regulatory actions have created uncertainty over Clean Water Act jurisdiction and permitting requirements that could variously increase or decrease the cost and time we expend on Clean Water Act compliance.
The scope of waters that fall within the Clean Water Act’s jurisdiction is expansive and may include features not commonly understood to be a stream 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. The WOTUS 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 in the 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, the Supreme Court ruled that challenges to the WOTUS rule must be made to the appropriate federal district courts rather than the Sixth Circuit. The Supreme Court’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 courts in 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 to propose a replacement to the WOTUS rule in May 2018.
Clean Water Act requirements that may directly or indirectly affect our operations include the following:
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Water Discharge.
Section 402 of the Clean Water Act creates a process for establishing effluent limitations for discharges to streams that are protective of water quality standards through the National Pollutant Discharge Elimination System, which we refer to as the NPDES, or an equally stringent program delegated to a state regulatory agency. Regular monitoring, reporting and compliance with performance standards are preconditions for the issuance and renewal of NPDES permits that govern discharges into waters of the United States, especially on selenium, sulfate and specific conductance. Discharges that exceed the limits specified under NPDES permits can lead to the imposition of penalties, and persistent non‑compliance could lead to significant penalties, compliance costs and delays in coal production. In addition, the imposition of future restrictions on the discharge of certain pollutants into waters of the United States could increase the difficulty of obtaining and complying with NPDES permits, which could impose additional time and cost burdens on our operations. You should see Item 3, “Legal Proceedings,” for more information about certain regulatory actions pertaining to our operations.
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Discharges of pollutants into waters that states have designated as impaired (i.e., as not meeting present water quality standards) are subject to Total Maximum Daily Load, which we refer to as TMDL, regulations. The TMDL regulations establish a process for calculating the maximum amount of a pollutant that a water body can receive while maintaining state water quality standards. Pollutant loads are allocated among the various sources that discharge pollutants into that water body. Mine operations that discharge into water bodies designated as impaired will be required to meet new TMDL allocations. The adoption of more stringent TMDL‑related allocations for our coal mines could require more costly water treatment and could adversely affect our coal production.
The Clean Water Act also requires states to develop anti‑degradation policies to ensure that non‑impaired water bodies continue to meet water quality standards. The issuance and renewal of permits for the discharge of pollutants to waters that have been designated as “high quality” are subject to anti‑degradation review that may increase the costs, time and difficulty associated with obtaining and complying with NPDES permits.
Under the Clean Water Act, citizens may sue to enforce NPDES permit requirements. Beginning in 2012, multiple citizens’ suits were filed in West Virginia against mine operators for alleged violations of NPDES permit conditions requiring compliance with West Virginia’s water quality standards. Some of the lawsuits alleged violations of water quality standards for selenium, whereas others alleged that discharges of conductivity and sulfate were causing violations of West Virginia water quality standards that prohibit adverse effects to aquatic life. The suits sought penalties as well as injunctive relief that would limit future discharges of selenium, conductivity or sulfate through the implementation of expensive treatment technologies. The federal district court for the Southern District of West Virginia has ruled in favor of the citizen suit groups in multiple suits alleging violations of the water quality standard for selenium and in two suits alleging violations of water quality standards due to discharge of conductivity (one of which was upheld on appeal by the United States Court of Appeals for the Fourth Circuit in January 2017). Additional rulings requiring operators to reduce their discharges of selenium, conductivity or sulfate could result in large treatment expenses for mine operators.
Citizens may also sue under the Clean Water Act when pollutants are being discharged without NPDES permits. Beginning in 2013, multiple citizens’ suits were filed in West Virginia against landowners alleging ongoing discharges of pollutants, including selenium and conductivity, from valley fills at reclaimed mining sites. In each case, the reclamation bond had been released and the mining and NPDES permits had been terminated following the completion of reclamation. While it is difficult to predict the outcome of such suits, any determination that discharges from valley fills require NPDES permits could result in increased compliance costs following the completion of mining at our operations.
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Dredge and Fill Permits.
Many mining activities, such as the development of refuse impoundments, fresh water impoundments, refuse fills, valley fills, and other similar structures, may result in impacts to waters of the United States, including wetlands, streams and, in certain instances, man‑made conveyances that have a hydrologic connection to such streams or wetlands. Under the Clean Water Act, coal companies are required to obtain a Section 404 permit from the Army Corps of Engineers, which we refer to as the Corps, prior to conducting such mining activities. The Corps is authorized to issue general “nationwide” permits for specific categories of activities that are similar in nature and that are determined to have minimal adverse effects on the environment. Permits issued pursuant to Nationwide Permit 21, which we refer to as NWP 21, generally authorize the disposal of dredged and fill material from surface coal mining activities into waters of the United States, subject to certain restrictions. Since March 2007, permits under NWP 21 were reissued for a five‑year period with new provisions intended to strengthen environmental protections. There must be appropriate mitigation in accordance with nationwide general permit conditions rather than less restricted state‑required mitigation requirements, and permit holders must receive explicit authorization from the Corps before proceeding with proposed mining activities.
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Notwithstanding the additional environmental protections designed in the NWP 21, on July 15, 2009, the Corps proposed to immediately suspend the use of NWP 21 in six Appalachian states, including West Virginia, Kentucky and Virginia where the Company conducts operations. On June 17, 2010, the Corps announced that it had suspended the use of NWP 21 in the same six states although it remained for use elsewhere. In February 2012, the Corps proposed to reissue NWP 21, albeit with significant restrictions on the acreage and length of stream channel that can be filled in the course of mining operations. The Corps’ decisions regarding the use of NWP 21 does not prevent the Company’s operations from seeking an individual permit under § 404 of the CWA, nor does it restrict an operation from utilizing another version of the nationwide permit, NWP 50, authorized for small underground coal mines that must construct fills as part of their mining operations.
Resource Conservation and Recovery Act.
The Resource Conservation and Recovery Act, which we refer to as RCRA, may affect coal mining operations through its requirements for the management, handling, transportation and disposal of hazardous wastes. . Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous substances. In addition, each state has its own laws regarding the proper management and disposal of waste material. In June 2010, the EPA released a proposed rule to regulate the disposal of certain coal combustion residuals, which we refer to as CCR. The proposed rule set forth two very different options for regulating CCR under RCRA. The first option called for regulation of CCR as a hazardous waste under Subtitle C, which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option utilized Subtitle D, which would give the EPA authority to set performance standards for waste management facilities and
would be enforced primarily through citizen suits. The proposal left intact the so-called Bevill exemption for beneficial uses of CCR. The EPA finalized the CCR rule on December 19, 2014, setting nationwide solid nonhazardous waste standards for CCR disposal. On April 17, 2015, the EPA finalized regulations under the solid waste provisions (Subtitle D) of RCRA and not the hazardous waste provisions (Subtitle C) which became effective on October 19, 2015. The final rule establishes national minimum criteria for existing and new CCR landfills, surface impoundments and lateral expansions, and also establishes structural integrity criteria for new and existing surface impoundments (including establishing requirements for owners and operators to conduct periodic structural integrity-related assessments). The criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post-closure care and recordkeeping, notification and internet posting requirements. While classification of CCR as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase our customers' operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, could lead to citizen suit enforcement against our customers under RCRA or other federal or state laws and potentially reduce the demand for coal. In another development regarding coal combustion wastes, the EPA conducted an assessment of impoundments and other units that manage residuals from coal combustion and that contain free liquids following a massive coal ash spill in Tennessee in 2008, the EPA contractors conducted site assessments at many impoundments and is requiring appropriate remedial action at any facility that is found to have a unit posing a risk for potential failure. The EPA is posting utility responses to the assessment on its web site as the responses are received. After industry groups filed a suit in the D.C. Circuit, challenging the 2015 rule, EPA Administrator Pruitt 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 specifying which provisions of the final rule are or are likely to be subject to reconsideration and estimated timeline for reconsideration. The court also ordered the parties 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 to continue to use coal in their power plants.
Comprehensive Environmental Response, Compensation and Liability Act.
The Comprehensive Environmental Response, Compensation and Liability Act, which we refer to as CERCLA, and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances that may endanger public health or welfare or the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners and lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could trigger the liability provisions of the statute. Thus, coal mines that we currently own or have previously owned or operated, and sites to which we sent waste materials, may be subject to liability under CERCLA and similar state laws. In particular, we may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination at sites where we own surface rights.
Endangered Species.
The Endangered Species Act and other related federal and state statutes protect species threatened or endangered with possible extinction. Protection of threatened, endangered and other special status species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species. A number of species indigenous to our properties are protected under the Endangered Species Act or other related laws or regulations. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans. We have been able to continue our operations within the existing spatial, temporal and other restrictions associated with special status species. Should more stringent protective measures be applied to threatened, endangered or other special status species or to their critical habitat, then we could experience increased operating costs or difficulty in obtaining future mining permits.
Use of Explosives.
Our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre‑blast surveys and blast monitoring. In addition, the storage of explosives is subject to strict regulatory requirements established by four different federal regulatory agencies. For example, pursuant to a rule issued by the Department of Homeland Security in 2007, facilities in possession of chemicals of interest, including ammonium nitrate at certain threshold levels, must complete a screening review in order to help determine whether there is a high level of security risk such that a security vulnerability assessment and site security plan will be required.
Other Environmental Laws.
We are required to comply with numerous other federal, state and local environmental laws in addition to those previously discussed. These additional laws include, for example, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right‑to‑Know Act.
Employees
At
December 31, 2017
, we employed approximately 3,790 full and part‑time employees. We believe that our relations with employees are good.
Executive Officers of the Registrant
The 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:
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Name
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Age
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Position
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Kenneth D. Cochran
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57
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Mr. Cochran has served as our Senior Vice President-Operations since August 2012. From May 2011 to August 2012, Mr. Cochran served as Group President of our western operations, which included Thunder Basin Coal Company, the Arch Western Bituminous Group, Arch of Wyoming and the Otter Creek development, and served as President and General Manager of Thunder Basin Coal Company from 2005 to April 2011. Prior to joining Arch Coal in 2005, Mr. Cochran spent 20 years with TXU Corporation. Mr. Cochran currently serves on the board of Knight Hawk Holdings, LLC.
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John T. Drexler
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48
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Mr. Drexler has served as our Senior Vice President and Chief Financial Officer since 2008. Mr. Drexler served as our Vice President-Finance and Accounting from 2006 to 2008. From 2005 to 2006, Mr. Drexler served as our Director of Planning and Forecasting. Prior to 2005, Mr. Drexler held several other positions within our finance and accounting department.
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John W. Eaves
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60
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Mr. Eaves has served as our Chief Executive Officer since 2012. Mr. Eaves served as our Chairman of the Board from 2015 to 2016 and our President and Chief Operating Officer from 2006 to 2012. From 2002 to 2006, Mr. Eaves served as our Executive Vice President and Chief Operating Officer. Mr. Eaves currently serves on the boards of the National Association of Manufacturers, the National Mining Association and CF Industries Holdings, Inc. Mr. Eaves was previously a director of Advanced Emissions Solutions, Inc. and former chairman of the National Coal Council.
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Robert G. Jones
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61
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Mr. Jones has served as our Senior Vice President-Law, General Counsel and Secretary since 2008. Mr. Jones served as Vice President-Law, General Counsel and Secretary from 2000 to 2008.
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Allen R. Kelley
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57
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Mr. Kelley was appointed Vice President-Human Resources in March 2014. From 2008 to March 2014, Mr. Kelley served as our Vice President-Enterprise Risk Management. From 2005 to 2008, Mr. Kelley served as our Director of Internal Audit. Prior to 2005, Mr. Kelley held various finance and accounting positions within the corporate and operations functions of Arch Coal, Inc.
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Paul A. Lang
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57
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Mr. Lang was elected our President and Chief Operating Officer in April 2015. He has served as our Executive Vice President and Chief Operating Officer since April 2012 and as our Executive Vice President-Operations from August 2011 to April 2012. Mr. Lang served as Senior Vice President-Operations from 2006 through August 2011, as President of Western Operations from 2005 through 2006 and President and General Manager of Thunder Basin Coal Company from 1998 to 2005. Mr. Lang is a director of Knight Hawk Holdings, LLC. Mr. Lang also served on the development board of the Mining Department of the Missouri University of Science & Technology, and is the former chairman of the University of Wyoming’s School of Energy Resources Council.
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Deck S. Slone
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54
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Mr. Slone has served as our Senior Vice President-Strategy and Public Policy since June 2012. Mr. Slone served as our Vice President-Government, Investor and Public Affairs from 2008 to June 2012. Mr. Slone served as our Vice President-Investor Relations and Public Affairs from 2001 to 2008. Mr. Slone is the Vice Chair of the National Coal Council, the immediate past co-chair of the Carbon Utilization Research Council, and the Chair of the National Mining Association’s Energy Policy Task Force.
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John A. Ziegler, Jr.
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51
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Mr. Ziegler was appointed Chief Commercial Officer in March 2014. Mr. Ziegler served as our Vice President-Human Resources from April 2012 to March 2014. From October 2011 to April 2012, Mr. Ziegler served as our Senior Director-Compensation and Benefits. From 2005 to October 2011 Mr. Ziegler served as Vice President-Contract Administration, President of Sales, then finally Senior Vice President, Sales and Marketing and Marketing Administration. Mr. Ziegler joined Arch Coal in 2002 as Director-Internal Audit. Prior to joining Arch Coal, Mr. Ziegler held various finance and accounting positions with bioMerieux and Ernst & Young.
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Available Information
We file annual, quarterly and current reports, and amendments to those reports, proxy statements and other information with the Securities and Exchange Commission. You may access and read our filings without charge through the SEC’s website, at
sec.gov
. You may also read and copy any document we file at the SEC’s Public Reference Room located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1‑800‑SEC‑0330 for further information on the public reference room.
We also make the documents listed above available without charge through our website,
archcoal.com
, as soon as practicable after we file or furnish them with the SEC. You may also request copies of the documents, at no cost, by telephone at (314) 994‑2700 or by mail at Arch Coal, Inc., One CityPlace Drive, Suite 300, St. Louis, Missouri, 63141 Attention: Senior Vice President-Strategy and Public Policy. The information on our website is not part of this Annual Report on Form 10-K.
GLOSSARY OF SELECTED MINING TERMS
Certain terms that we use in this document are specific to the coal mining industry and may be technical in nature. The following is a list of selected mining terms and the definitions we attribute to them.
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Assigned reserves
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Recoverable reserves designated for mining by a specific operation.
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Bituminous coal
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Coal used primarily to generate electricity and to make coke for the steel industry with a heat value ranging between 10,500 and 15,500 Btus per pound.
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Btu
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A measure of the energy required to raise the temperature of one pound of water one degree of Fahrenheit.
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Coking coal
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Coal used to produce coke, the primary source of carbon used in steelmaking.
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Compliance coal
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Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus, requiring no blending or other sulfur dioxide reduction technologies in order to comply with the requirements of the Clean Air Act.
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Continuous miner
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A machine used in underground mining to cut coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation.
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Dragline
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A large machine used in surface mining to remove the overburden, or layers of earth and rock, covering a coal seam. The dragline has a large bucket, suspended by cables from the end of a long boom, which is able to scoop up large amounts of overburden as it is dragged across the excavation area and redeposit the overburden in another area.
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Hard coal
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Coal of gross calorific value greater than 5700 kcal/kg on an ashfree but moist basis and further disaggregated into anthracite, coking coal and other bituminous coal.
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Lignite Coal
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Coal with the lowest carbon content and a heat value ranging between 4,000 and 8,300 Btus per pound.
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Longwall mining
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One of two major underground coal mining methods, generally employing two rotating drums pulled mechanically back and forth across a long face of coal.
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Low‑sulfur coal
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Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btus.
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Metallurgical coal
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Coal used in steel production either as coking coal or pulverized coal injection (PCI).
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Preparation plant
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A facility used for crushing, sizing and washing coal to remove impurities and to prepare it for use by a particular customer.
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Probable reserves
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Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced.
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Proven reserves
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Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well established.
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Pulverized coal injection coal (PCI)
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Coal that is introduced directly into the blast furnace as a source of energy and carbon in the steelmaking process.
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Reclamation
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The restoration of land and environmental values to a mining site after the coal is extracted. The process commonly includes “recontouring” or shaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers.
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Recoverable reserves
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The amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods and under current law.
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Reserves
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That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.
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Subbituminous coal
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Coal used primarily to generate electricity with a heat value ranging between 8,300 and 13,000 Btus per pound.
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Room‑and‑pillar mining
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One of two major underground coal mining methods, utilizing continuous miners creating a network of “rooms” within a coal seam, leaving behind “pillars” of coal used to support the roof of a mine.
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Unassigned reserves
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Recoverable reserves that have not yet been designated for mining by a specific operation.
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ITEM 1A. RISK FACTORS.
Our business involves certain risks and uncertainties. In addition to the risks and uncertainties described below, we may face other risks and uncertainties, some of which may be unknown to us and some of which we may deem immaterial and the following review of important risk factors should not be construed as exhaustive and should be read in conjunction with other cautionary statements that are included herein or elsewhere. If one or more of these risks or uncertainties occur, our business, financial condition or results of operations may be materially and adversely affected.
Risks Related to Emergence from Bankruptcy Protection
Information contained in our historical financial statements is not be comparable to the information contained in our financial statements after the application of fresh start accounting.
Following the consummation of the Plan, our financial condition and results of operations from and after the Effective Date are not be comparable to the financial condition or results of operations in our historical financial statements. As a result of our restructuring under Chapter 11 of the Bankruptcy Code, our financial statements are subject to fresh start accounting provisions of generally accepted accounting principles (“GAAP”). In the application of fresh start accounting, we allocated our reorganization value to the fair value of assets and liabilities in conformity with the guidance for the acquisition method of accounting for business combinations. Adjustments to the carrying amounts were material and will affect prospective results of operations as balance sheet items are settled, depreciated, amortized or impaired. This will make it difficult for stockholders to assess our performance in relation to prior periods. Our Annual Report on Form 10-K for the fiscal year ending December 31, 2016 reflects the consummation of the Plan and the adoption of fresh start accounting effective October 1, 2016.
Risks Related to Our Operations
Coal 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 historic level of depression. If there is a decline in prices, it could materially and adversely affect our profitability and the value of our coal reserves.
Our profitability and the value of our coal reserves depend upon the prices we receive for our coal. The contract prices we may receive in the future for coal depend upon factors beyond our control, including the following:
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the domestic and foreign supply of and demand for coal;
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the domestic and foreign demand for electricity and steel;
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the quantity and quality of coal available from competitors;
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competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;
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domestic and foreign air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards;
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adverse weather, climatic or other natural conditions, including unseasonable weather patterns;
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domestic and foreign economic conditions, including economic slowdowns and the exchange rate of U.S. dollars for foreign currency;
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domestic and foreign legislative, regulatory and judicial developments, environmental regulatory changes or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions or providing for increased funding and incentives for alternative energy sources;
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the proximity to, capacity of and cost of transportation and port facilities;
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market price fluctuations for sulfur dioxide or nitric oxide emission allowances; and
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technological advancements, including those related to alternative energy sources, those intended to convert coal-to-liquids or gas and those aimed at capturing, using and storing carbon dioxide.
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Declines in the prices we receive for our future coal sales contracts, could materially and adversely affect us by decreasing our profitability, cash flows, liquidity and the value of our coal reserves.
Unfavorable economic and market conditions have adversely affected and may continue to affect our revenues and profitability.
Our profitability depends, in large part, on conditions in the markets that we serve, which fluctuate in response to various factors beyond our control. The prices at which we sell our coal are largely dependent on prevailing market prices. We have experienced significant price pressure at times during the past several years as the demand for, and price of, coal has been subject to pressure for a variety of reasons, including reductions in domestic and international demand for metallurgical and thermal coal.
Global economic downturns have also had and in the future could have a negative impact on us. These conditions have, in the past, led to extreme volatility of prices, severely limited liquidity and credit availability, and resulted in declining valuations of assets. If there are downturns in economic conditions, our customers’ and our businesses, financial conditions or results of operations could be adversely affected. Furthermore, because we typically seek to enter into long-term arrangements for the sale of a substantial portion of our coal, the average sales price we receive for our coal may lag behind any general economic recovery. We are focused on cost control and capital discipline, but there can be no assurance that these actions, or any other actions that we may take, will be sufficient to offset any adverse effect these conditions may have on our business, financial condition or results of operations.
Competition could put downward pressure on coal prices and, as a result, materially and adversely affect our revenues and profitability.
We compete with numerous other domestic and foreign coal producers for domestic and international sales. Overcapacity and increased production within the coal industry, both domestically and internationally, and decelerating steel demand in Asia have at times, and could in the future, materially reduce coal prices and therefore materially reduce our revenues and profitability. Potential changes to international trade agreements, trade concessions or other political and economic arrangements may benefit coal producers operating in countries other than the United States. We may not be able to compete on the basis of price or other factors with companies that in the future benefit from favorable foreign trade policies or other arrangements. In addition, our ability to ship our coal to international customers depends on port capacity, which is limited. Increased competition within the coal industry for international sales could result in us not being able to obtain throughput capacity at port facilities, or the rates for such throughput capacity to increase to a point where it is not economically feasible to export our coal.
The domestic coal industry has experienced consolidation in recent years, including consolidation among some of our major competitors. In addition, substantial overcapacity exists in the coal industry and several other large coal companies have also filed, and others may file, bankruptcy proceedings which could enable them to lower their productions costs and thereby reduce the price for coal. Consolidation in the coal industry or current or future 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 has declined significantly in recent years. The decline in the price of natural gas has caused demand for coal to decrease and adversely affect the price of our coal. Sustained periods of low natural gas prices have also contributed to utilities phasing out or closing existing coal-fired power plants and continued low prices could reduce or eliminate construction of any new coal-fired power plants. This trend has, and could continue to have, a material adverse effect on demand and prices for our coal.
Any decrease in the coal consumption of electric power generators could result in less demand and lower prices for coal, which could materially and adversely affect our revenues and results of operations.
Thermal coal accounted for
93%
of our coal sales by volume during
2017
. The majority of these sales were to electric power generators. The amount of coal consumed for electric power generation is affected primarily by the overall demand for electricity, the availability, quality and price of competing fuels (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 be caused by a number of factors. An economic slowdown can significantly slow the growth of electricity demand and could result in reduced demand for coal. For example, declines in the rate of international economic growth in countries such as China, India or other developing countries could further negatively impact the demand for U.S. coal and result in a continuing oversupply of coal in the marketplace. Weather patterns can also greatly affect electricity demand. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increase generating requirements from all sources. Mild temperatures, on the other hand, result in lower electrical demand, which allow generators to choose the source of power generation when deciding which generation source to dispatch.
Gas-fueled generation has the potential to displace coal-fueled generation, particularly from older, less efficient coal-powered generators and this has occurred to date. We expect that many of the new power plants needed in the United States to meet increasing demand for electricity generation will be fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain as natural gas is seen as having a lower environmental impact than coal-fueled generation. In addition, state and federal mandates for increased use of electricity from renewable energy sources also have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.
Our coal mining operations are subject to operating risks that are beyond our control, which could result in materially increased operating expenses and decreased production levels and could materially and adversely affect our profitability.
We mine coal at underground and surface mining operations. Certain factors beyond our control, including those listed below, could disrupt our coal mining operations, adversely affect production and shipments and increase our operating costs:
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poor mining conditions resulting from geological, hydrologic or other conditions that may cause instability of highwalls or spoil piles or cause damage to nearby infrastructure or mine personnel;
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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;
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mining, processing and plant equipment failures and unexpected maintenance problems;
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adverse weather and natural disasters, such as heavy rains or snow, flooding and other natural events affecting operations, transportation or customers;
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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;
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unexpected or accidental surface subsidence from underground mining;
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accidental mine water discharges, fires, explosions or similar mining accidents;
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delays or closures by third-party transportation on coal shipments; and
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competition and/or conflicts with other natural resource extraction activities and production within our operating areas, such as coalbed methane extraction or oil and gas development.
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If any of these conditions or events occurs, particularly at our Black Thunder or Leer mining complexes, which accounted for approximately
75%
of the 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 halt of production or shipments or our operating costs could increase significantly. In addition, if our insurance coverage is limited or excludes certain of these conditions or events, then we may not be able to recover any of the losses we may incur as a result of such conditions or events, some of which may be substantial.
A decline in demand for metallurgical coal would limit our ability to sell our coal into higher
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priced metallurgical markets and could substantially affect our business.
Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on the prevailing conditions in the metallurgical and steam coal markets. We decide whether to mine, process and market these coals as metallurgical or steam coal based on management’s assessment as to which market is likely to provide us with a higher margin. We consider a number of factors when making this assessment, including the difference between the current and anticipated future market prices of steam coal and metallurgical coal and the increased costs incurred in producing coal for sale in the metallurgical market instead of the steam market. A decline in prices in the metallurgical market relative to the steam market could cause us, as well as our competitors, to shift coal from the metallurgical market to the steam market, thereby reducing our revenues and profitability and increasing the availability of coal to customers in the steam market.
Our inability to acquire additional coal reserves or our inability to develop coal reserves in an economically feasible manner may adversely affect our business.
Our profitability depends substantially on our ability to mine and process, in a cost-effective manner, coal reserves that possess the quality characteristics desired by our customers. As we mine, our coal reserves decline. As a result, our future success depends upon our ability to acquire additional coal that is economically recoverable. If we fail to acquire or develop additional coal reserves, our existing reserves will eventually be depleted. We may not be able to obtain replacement reserves when we require them. If available, replacement reserves may not be available at favorable prices, or we may not be capable of mining those reserves at costs that are comparable with our existing coal reserves. In certain locations, leases for oil, natural gas and coalbed methane reserves are located on, or adjacent to, some of our reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests.
Our ability to obtain coal reserves in the future could also be limited by the availability of cash we generate from our operations or available financing, restrictions under our existing or future financing arrangements, competition from other coal producers, the lack of suitable acquisition or lease-by-application, or LBA, opportunities or the inability to acquire coal properties or LBAs on commercially reasonable terms. Increased opposition from non-governmental organizations and other third parties may also lengthen, delay or adversely impact the LBA process. If we are unable to acquire replacement reserves, our future production may decrease significantly and our operating results may be negatively affected. In addition, we may not be able to mine future reserves as profitably as we do at our current operations.
In January 2016, the federal government imposed a moratorium on new leases for coal mined from federal lands as part of a review of the government’s management of federally-owned coal. In March 2017, the U.S. Secretary of Interior signed Secretarial Order 3348 lifting that moratorium and halting the Federal Coal Program Programmatic Environmental Impact Statement that was in process at the time. Litigation is currently pending in the United States District Court for the District of Montana challenging the lifting of the moratorium as a violation of the National Environmental Policy Act, the Mineral Leasing Act and the Federal Land Policy and Management Act. Although the Bureau of Land Management is now working to process coal lease applications and modifications expeditiously in accordance with regulations and guidance that existed before Secretarial Order 3338, which imposed the moratorium on new coal leases, any delay in the LBA process, including any delay caused by the now-lifted moratorium could prevent us from obtaining replacement reserves when we require them. Also, the outcome of the government’s review is uncertain and could have a material and adverse impact on our business in any number of ways including by limiting our ability to mine reserves under ongoing or future applications, by increasing the costs or timeframe associated with obtaining leases under the LBA program, by making it uneconomical for us to participate in the programs or by preventing us from obtaining replacement reserves if the LBA program were to be terminated.
Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.
Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. We base our estimates of reserves on engineering, economic and geological data assembled, analyzed and reviewed by internal and third-party engineers and consultants. We update our estimates of the quantity and quality of proven and probable coal reserves annually to reflect the production of coal from the reserves, updated geological models and mining recovery data, the tonnage contained in new lease areas acquired and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including the following:
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geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;
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the percentage of coal ultimately recoverable;
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the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;
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assumptions concerning the timing for the development of the reserves;
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assumptions concerning physical access to the reserves; and
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assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.
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As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary materially due to changes in the above factors and assumptions. Actual production recovered from identified reserve areas and properties, and revenues and expenditures associated with our mining operations, may vary materially from estimates. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues and/or higher than expected costs.
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal which could have a material adverse effect on our business and results of operations.
Federal and state laws require us to obtain surety bonds or post letters of credit to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations. The costs of surety bonds have fluctuated in recent years while the market terms of such bonds have generally become more unfavorable to mine operators. These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. In addition, federal and state regulators are considering making financial assurance requirements with respect to mine closure and reclamation more stringent. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, our failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal.
Increases in the costs of mining and other industrial supplies, including steel
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based supplies, diesel fuel and rubber tires, or the inability to obtain a sufficient quantity of those supplies, could negatively affect our operating costs or disrupt or delay our production.
Our coal mining operations use significant amounts of steel, diesel fuel, explosives, rubber tires and other mining and industrial supplies. The cost of roof bolts we use in our underground mining operations depends on the price of scrap steel. We also use significant amounts of diesel fuel and tires for trucks and other heavy machinery, particularly at our Black Thunder mining complex. There has been some consolidation in the supplier base providing mining materials to the coal industry, such as with suppliers of explosives in the U.S. and both surface and underground equipment globally, that has limited the number of sources for these materials. In situations where we have chosen to concentrate a large portion of purchases with one supplier, it has been to take advantage of cost savings from larger volumes of purchases and to ensure security of supply. If the prices of mining and other industrial supplies, particularly steel based supplies, diesel fuel and rubber tires, increase, our operating costs could be negatively affected. In addition, if we are unable to procure these supplies, our coal mining operations may be disrupted or we could experience a delay or halt in our production.
Our profitability depends upon the coal supply agreements we have with our customers. Changes in purchasing patterns in the coal industry could make it difficult for us to extend our existing coal supply agreements or to enter into new agreements in the future.
The success of our businesses depends on our ability to retain our current customers, renew our existing customer contracts and solicit new customers. Our ability to do so generally depends on a variety of factors, including the quality and price of our products, our ability to market these products effectively, our ability to deliver on a timely basis and the level of competition that we face. If current customers do not honor current contract commitments, or if they terminate agreements or exercise
force majeure
provisions allowing for the temporary suspension of performance, our revenues will be adversely affected. Changes in the coal industry may cause some of our customers not to renew, extend or enter into new coal supply agreements or enter into agreements to purchase fewer tons of coal or on different terms or prices than in the past. In addition,
uncertainty caused by federal and state regulations, including the 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 specified events beyond their control. Most of our coal supply agreements also contain provisions requiring us to deliver coal that satisfies certain quality specifications, such as heat value, sulfur content, ash content, hardness and ash fusion temperature. These provisions in our coal supply agreements could result in negative economic consequences to us, including price adjustments, purchasing replacement coal in a higher-priced open market, the rejection of deliveries or, in the extreme, contract termination. Our profitability may be negatively affected if we are unable to seek protection during adverse economic conditions or if we incur financial or other economic penalties as a result of these provisions of our coal supply agreements. For more information about our long-term coal supply agreements, you should see the section entitled “Long-Term Coal Supply Arrangements” under Item 1.
Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates and our financial position could be materially and adversely effected by the bankruptcy of any of our significant customers.
Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If we determine that a customer is not creditworthy, we may be able to withhold delivery under the customer’s coal sales contract. If this occurs, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contracted price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our significant customers could materially and adversely affect our financial position.
In addition, our customer base may change with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear for customer payment default. Some power plant owners may have credit ratings that are below investment grade, or may become below investment grade after we enter into contracts with them. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk of payment default. Customers in other countries may also be subject to other pressures and uncertainties that may affect their ability to pay, including trade barriers, exchange controls and local economic and political conditions.
A defect in title or the loss of a leasehold interest in certain property or surface rights could limit our ability to mine our coal reserves or result in significant unanticipated costs.
We conduct a significant part of our coal mining operations on properties that we lease. A title defect or the loss of a lease or surface rights could adversely affect our ability to mine the associated coal reserves. We may not verify title to our leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or coal reserves that we intend to mine may contain defects prohibiting our ability to conduct mining operations. Similarly, our leasehold interests may be subject to superior property rights of other third parties. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and require us to pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.
The availability, reliability and cost-effectiveness of transportation facilities and fluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.
We depend upon barge, ship, rail, truck and belt transportation systems, as well as seaborne vessels and port facilities, to deliver coal to our customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, route closures and other events beyond our control could impair our ability to supply coal to our customers. Since we do not have long-term contracts with all transportation providers we utilize, decreased performance levels over longer periods of time could cause our customers to look to other sources for their coal needs. In addition, increases in transportation costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of the United States or abroad. If we experience disruptions in our transportation services or if transportation costs increase significantly and we are unable to find alternative transportation providers, our coal mining operations may be disrupted, we could experience a delay or halt of production or our profitability could decrease significantly.
In addition, a growing portion of our coal sales in recent years has been into export markets, and we are actively seeking additional international customers. Our ability to maintain and grow our export sales revenue and margins depends on a number of factors, including the existence of sufficient and cost-effective export terminal capacity for the shipment of coal to foreign markets. At present, there is limited terminal capacity for the export of coal into foreign markets. Our access to existing and future terminal capacity may be adversely affected by regulatory and permit requirements, environmental and other legal challenges, public perceptions and resulting political pressures, operational issues at terminals and competition among domestic coal producers for access to limited terminal capacity, among other factors. If we are unable to maintain terminal capacity, or are unable to access additional future terminal capacity for the export of our coal on commercially reasonable terms, or at all, our results could be materially and adversely affected.
From time to time we enter into “take or pay” contracts for rail and port capacity related to our export sales. These contracts require us to pay for a minimum quantity of coal to be transported on the railway or through the port regardless of whether we sell and ship any coal. If we fail to acquire sufficient export sales to meet our minimum obligations under these contracts, we are still obligated to make payments to the railway or port facility, which could have a negative impact on our cash flows, profitability and results of operations.
The loss of, or significant reduction in, purchases by our largest customers could adversely affect our profitability.
For the year ended
December 31, 2017
, we derived approximately
17%
of our total coal revenues from sales to our three largest customers and approximately
41%
of our total coal revenues from sales to our ten largest customers. We are currently discussing the extension of coal sales agreements with some of these customers. However, we may be unsuccessful in obtaining coal supply agreements with those customers, and some or all of these customers could discontinue purchasing coal from us. If any of those customers, particularly any of our three largest customers, was to significantly reduce the quantities of coal it purchases from us, or if we are unable to sell coal to those customers on terms as favorable to us, it may have an adverse impact on the results of our business.
We may incur losses as a result of certain marketing, trading and asset optimization strategies.
We seek to optimize our coal production and leverage our knowledge of the coal industry through a variety of marketing, trading and other asset optimization strategies. We maintain a system of complementary processes and controls designed to monitor and control our exposure to market and other risks as a consequence of these strategies. These processes and controls seek to balance our ability to profit from certain marketing, trading and asset optimization strategies with our exposure to potential losses. While we employ a variety of risk monitoring and mitigation techniques, those techniques and accompanying judgments cannot anticipate every potential outcome or the timing of such outcomes. In addition, the processes and controls that we use to manage our exposure to market and other risks resulting from these strategies involve assumptions about the degrees of correlation or lack thereof among prices of various assets or other market indicators. These correlations may change significantly in times of market turbulence or other unforeseen circumstances. As a result, we may experience volatility in our earnings as a result of our marketing, trading and asset optimization strategies.
International growth in our operations adds new and unique risks to our business.
We have sales offices in Singapore and the United Kingdom. The international expansion of our operations increases our exposure to country and currency risks. In addition, our international offices are selling our coal to new customers and customers in new countries, whose business practices and reputations are not as well known to us. We are also challenged by political risks by expanding internationally, including the potential for expropriation of assets and limits on the repatriation of earnings. In the event that we are unable to effectively manage these new risks, our results of operations, financial position or cash flow could be adversely affected by these activities.
If we sustain cyber attacks or other security breaches that disrupt our operations, or that result in the unauthorized release of proprietary or confidential information, we could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks.
We may be subject to security breaches which could result in unauthorized access to our facilities or to information we are trying to protect. Unauthorized physical access to one or more of our facilities or locations, or electronic access to our proprietary or confidential information could result in, among other things, unfavorable publicity, litigation by parties affected by such breach, disruptions to our operations, loss of customers, and financial obligations for damages related to the theft or misuse of such information, any of which could have a substantial impact on our results of operations, financial condition or cash flow.
Our ability to operate the Company effectively could be impaired if we lose key personnel or fail to attract qualified personnel.
We manage our business with a number of key personnel, the loss of whom could have a material adverse effect on us, absent the completion of an orderly transition. In addition, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel, particularly personnel with mining experience. Failure to retain or attract key personnel could have a material adverse effect on us.
We may be unable to comply with the restriction imposed by our New First Lien Debt Facility and other financing arrangements.
The agreements governing our outstanding financing arrangements impose a number of restrictions on us. For example, the terms of our credit facilities, leases and other financing arrangements contain financial and other covenants that create limitations on our ability to borrow the full amount under our credit facilities, effect acquisitions or dispositions and incur additional debt and require us to comply with various affirmative covenants. The New First Lien Debt Facility contains customary affirmative and negative covenants, which include restrictions on (i) indebtedness, (ii) liens and guarantees, (iii) liquidations, mergers, consolidations, acquisitions, (iv) disposition of assets or subsidiaries, (v) affiliate transactions, (vi) creation or ownership of certain subsidiaries, partnerships and joint ventures, (vii) continuation of or change in business, (viii) restricted payments, (ix) payment of other indebtedness, (x) no restriction in agreements on dividends or certain loans, (xi) loans and investments, (ix) transactions with respect to Bonding Subsidiaries and (xiii) changes in organizational documents. Our ability to comply with these provisions may be affected by events beyond our control and our failure to comply could result in an event of default under the New First Lien Debt Facility.
Risks Related to Environmental, Other Regulations and Legislation
Extensive environmental regulations, including existing and potential future regulatory requirements relating to air emissions, affect our customers and could reduce the demand for coal as a fuel source and cause coal prices and sales of our coal to materially decline.
Coal contains impurities, including but not limited to sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. The operations of our customers are subject to extensive environmental regulation particularly with respect to air emissions. For example, the federal Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, and other compounds emitted into the air from electric power plants, which are the largest end‑users of our coal. A series of more stringent requirements relating to particulate matter, ozone, haze, mercury, sulfur dioxide, nitrogen oxide and other air pollutants is in the process of being developed and implemented. For instance, the Clean Power Plan, if implemented in its current form, would severely limit emissions of carbon dioxide which would adversely affect our ability to 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 Executive Order 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 195 other countries reached an agreement (the “Paris Agreement” during the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change, a long-term, international framework convention designed to address climate change over the next several decades. In June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or to establish a new framework agreement. The earliest permitted exit date under the Paris Agreement is four years from when the agreement took 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 the United States may reenter the Paris Agreement or a separately negotiated agreement are, uncertain at this time. However, any efforts to control and/or reduce greenhouse gas emissions by the United States or other countries that have also pledged “Nationally Determined Contributions,” or concerted conservation efforts that result in reduced electricity consumption, could adversely impact coal prices, our ability to sell coal and, in turn, our financial position and results of operations.
Considerable uncertainty is associated with these air emissions initiatives. The content of regulatory requirements in the United States continues to evolve and develop and many new regulatory initiatives remain subject to review by federal or state agencies or the courts. Stringent air emissions limitations are either in place or are likely to be imposed in the short to medium term, and these limitations will likely require significant emissions control expenditures for many coal‑fueled power plants. As a result, these power plants may switch to other fuels that generate fewer of these emissions, may install more effective pollution control equipment that reduces the need for low sulfur coal, or may cease operations, possibly reducing future demand for coal and a reduced need to construct new coal‑fueled power plants. Any switching of fuel sources away from coal, closure of existing coal‑fired plants, or reduced construction of new plants could have a material adverse effect on
demand for and prices received for our coal. Alternatively, less stringent air emissions limitations, particularly related to sulfur, to the extent enacted could make low sulfur coal less attractive, which could also have a material adverse effect on the demand for and prices received for our coal.
You should see Item 1, “Environmental and Other Regulatory Matters” for more information about the various governmental regulations affecting the market for our products.
The demand for our products or our securities, as well as the number and quantity of viable financing alternatives, may be significantly impacted by increased governmental regulations and unfavorable lending and investment policies by financial institutions and insurance companies associated with concerns about environmental impacts of coal combustion, including perceived impacts on the global climate.
Carbon dioxide, which is considered to be a greenhouse gas, is a by-product of burning coal. Global climate issues, including with respect to greenhouse gases such as carbon dioxide and the relationship that greenhouse gases may have with perceived climate change, continue to attract significant public and scientific attention. For example, the Fourth and Fifth Assessment Reports of the Intergovernmental Panel on Climate Change have expressed concern about the impacts of human activity, especially from fossil fuel combustion, on global climate issues. As a result of the public and scientific attention, several governmental bodies increasingly are focusing on climate issues and, more specifically, levels of emissions of carbon dioxide from coal combustion by power plants. The Clean Power Plan would severely limit emissions of carbon dioxide, possibly reducing future demand for coal. However, in April 2017 the EPA announced that it was initiating a review of the Clean Power Plan consistent with President Trump’s Executive Order 13783, and in October 2017 published a proposed rule to formally repeal the Clean Power Plan. Additionally, a number of governments pledged to control and reduce greenhouse gas emissions under the Paris Agreement, which may impact demand for coal resources despite the United States’ June 2017 announcement that it intends 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 regulatory changes and the federal, state or local level or otherwise. Enactment of laws or passage of regulations regarding greenhouse emissions from the combustion of coal by the U.S., some of its states or other countries, or other actions to limit emissions could result in electricity generators switching from coal to other fuel sources or coal-fueled power plant closures. You should see Item 1, “Environmental and Other Regulatory Matters-Climate Change” for more information about governmental regulations relating to greenhouse gas emissions.
In addition, certain banks, other financing sources and insurance companies have taken actions to limit available financing and insurance coverage for 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 may adversely impact the future global demand for coal. Further, there have been recent efforts by members of the general financial and investment communities, such as investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to divest themselves and to promote the divestment of securities issued by companies involved in the fossil fuel extraction market, such as coal producers. Those entities also have been pressuring lenders to limit financing available to such companies. These efforts may adversely affect the market for our securities and our ability to access capital and financial markets in the future.
Any future laws, regulations or other policies of the nature described above may adversely impact our business in material ways. The degree to which any particular law, regulation or policy impacts us will depend on several factors, including the substantive terms involved, the relevant time periods for enactment and any related transition periods. We routinely attempt to evaluate the potential impact on us of any proposed laws, regulations or policies, which requires that we make several material assumptions. From time to time, we determine that the impact of one or more such laws, regulations or policies, if adopted and ultimately implemented as proposed, may result in materially adverse impacts on our operations, financial condition or cash flow. In general, it is likely that any future laws, regulations or other policies aimed at reducing greenhouse gas emissions will negatively impact demand for our coal.
Our failure to obtain and renew permits necessary for our mining operations could negatively affect our business.
Mining companies must obtain numerous permits that impose strict regulations on various environmental and operational matters in connection with coal mining. These include permits issued by various federal, state and local agencies and regulatory bodies. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by the regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing operations or the development of future mining operations. The public, including non‑governmental organizations, anti‑mining groups and individuals, have certain statutory rights to comment upon and submit objections to requested permits and environmental impact statements prepared in connection with applicable
regulatory processes, and otherwise engage in the permitting process, including bringing citizens’ lawsuits to challenge the issuance of permits, the validity of environmental impact statements or performance of mining activities. Accordingly, required permits may not be issued or renewed in a timely fashion or at all, or permits issued or renewed may be conditioned in a manner that may restrict our ability to efficiently and economically conduct our mining activities, any of which would materially reduce our production, cash flow and profitability.
Federal or state regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances, which could materially and adversely affect our ability to meet our customers’ demands.
Federal or state regulatory agencies have the authority under certain circumstances following significant health and safety incidents, such as fatalities, to order a mine to be temporarily or permanently closed. If this occurred, we may be required to incur capital expenditures to re‑open the mine. In the event that these agencies order the closing of our mines, our coal sales contracts generally permit us to issue
force majeure
notices which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of
force majeure
notices. If these challenges are successful, we may have to purchase coal from third‑party sources, if it is available, to fulfill these obligations, incur capital expenditures to re‑open the mines and/or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery or terminate customers’ contracts. Any of these actions could have a material adverse effect on our business and results of operations.
Extensive environmental regulations impose significant costs on our mining operations, and future regulations could materially increase those costs or limit our ability to produce and sell coal.
The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to environmental matters such as:
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limitations on land use;
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•
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mine permitting and licensing requirements;
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•
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reclamation and restoration of mining properties after mining is completed and required surety bonds or other instruments to secure those reclamation and restoration obligations;
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•
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management of materials generated by mining operations;
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the storage, treatment and disposal of wastes;
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remediation of contaminated soil and groundwater;
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protection of human health, plant‑life and wildlife, including endangered or threatened species;
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protection of wetlands;
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the discharge of materials into the environment;
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the effects of mining on surface water and groundwater quality and availability; and
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the management of electrical equipment containing polychlorinated biphenyls.
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The costs, liabilities and requirements associated with the laws and regulations related to these and other environmental matters may be costly and time‑consuming and may delay commencement or continuation of exploration or production operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. We may incur material costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we are pursued for sanctions, costs and liabilities in respect of these matters, our mining operations and, as a result, our profitability could be materially and adversely affected.
New legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us to change operations significantly or incur increased costs. Such changes could have a material adverse effect on our financial condition and results of operations. You should see the section entitled “Environmental and Other Regulatory Matters” in Item 1 for more information about the various governmental regulations affecting us.
If the assumptions underlying our estimates of reclamation and mine closure obligations are inaccurate, our costs could be greater than anticipated.
SMCRA and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of underground mining. We base our estimates of reclamation and mine closure liabilities on permit requirements, engineering studies and our engineering expertise related to these requirements. Our management and engineers periodically review these estimates. The estimates can change significantly if actual costs vary from our original assumptions or if governmental regulations change significantly. We are required to record new obligations as liabilities at fair value under generally accepted accounting principles. In estimating fair value, we considered the estimated current costs of reclamation and mine closure and applied inflation rates and a third‑party profit, as required. The third‑party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf. The resulting estimated reclamation and mine closure obligations could change significantly if actual amounts change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial condition.
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.
Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. We could become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and cleanup of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or at sites that we may acquire. Under certain federal and state environmental laws, our liability for such conditions may be joint and several with other owners/operators, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share. Liability under these laws is generally strict. Accordingly, we may incur liability without regard to fault or to the legality of the conduct giving rise to the conditions.
We maintain extensive coal refuse areas and slurry impoundments at a number of our mining complexes. Such areas and impoundments are subject to extensive regulation. Slurry impoundments can fail, which could release large volumes of coal slurry into the surrounding environment. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined-out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.
Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage,” which we refer to as AMD. The treating of AMD can be costly. Although we do not currently face material costs associated with AMD, it is possible that we could incur significant costs in the future.
These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect us.
Judicial rulings that restrict how we may dispose of mining wastes could significantly increase our operating costs, discourage customers from purchasing our coal and materially harm our financial condition and operating results.
To dispose of mining overburden generated by our Appalachian surface mining operations, we often need to obtain permits to construct and operate valley fills and surface impoundments. Some of these permits are Clean Water Act § 404 permits issued by the Army Corps of Engineers (the Corps). Two of our operating subsidiaries were identified in an existing lawsuit, which challenged the issuance of such permits and asked that the Corps be ordered to rescind them. Two of our operating subsidiaries intervened in the suit to protect their interests in being allowed to operate under the issued permits, and the claims against one of the subsidiaries was thereafter dismissed. On February 13, 2009, the U.S. Court of Appeals for the Fourth Circuit ruled on appeals from decisions rendered prior to our intervention. On May 22, 2017, the United States District Court for the Southern District of West Virginia granted the remaining subsidiary’s motion to dismiss plaintiffs’ Seventh Supplemental and Amended Complaint after the D.C. Circuit Court of Appeals affirmed the EPA’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 permit authorization.
Changes in the legal and regulatory environment could complicate or limit our business activities, increase our operating costs or result in litigation.
The conduct of our businesses is subject to various laws and regulations administered by federal, state and local governmental agencies in the United States. These laws and regulations may change, sometimes dramatically, as a result of political, economic or social events or in response to significant events. Environmental and other non-governmental organizations and activists, many of which are well funded, continue to exert pressure on regulators and other government bodies to enact more stringent laws and regulations. Changes in the legal and regulatory environment in which we operate may impact our results, increase our costs or liabilities, complicate or limit our business activities or result in litigation. Such legal and regulatory environment changes may include changes in such items as: the processes for obtaining or renewing permits; federal lease by application programs; costs associated with providing healthcare benefits to employees; health and safety standards; accounting standards; taxation requirements; and competition laws. Furthermore, pursuant to a February 2017 executive order and the proposed rule published on July 27, 2017, the EPA will review and revise the definition of “waters of the United States,” which may include re-codifying the definition that currently governs administration of the Clean Water Act. Adoption of more stringent application of existing regulations may materially increase our costs and adversely affect our operations.
Risks Related to Income Taxes
Recent 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”). The limitation 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 with carryforward 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 AMT credits 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 reduction of the U.S. corporate income tax rate, elimination of the AMT tax system, limitation of interest deductions and revision of the rules governing net operating losses. 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 and implementing regulations by the Treasury and Internal Revenue Service (“IRS”), any of which could lessen or increase certain adverse impacts of the legislation. 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 as a 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 changes may 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 whole will 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.
ITEM 2. PROPERTIES.
Our Properties
At
December 31, 2017
, we owned or controlled, primarily through long‑term leases, approximately
28,292
acres of coal land in Ohio,
1,060
acres of coal 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,
267,857
acres 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
acres of 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 of property in Alabama, Indiana, Washington, Arkansas, California, Utah and Texas. We lease approximately
81,436
acres of our coal land from the federal government and approximately
22,385
acres of our coal land from various state governments. Certain of our preparation plants or loadout facilities are located on properties held under leases which expire at varying dates over the next 30 years. Most of the leases contain options to renew. Our remaining preparation plants and loadout facilities are located on property owned by us or for which we have a special use permit.
Our executive headquarters occupies leased office space at One CityPlace Drive, in St. Louis, Missouri. Our subsidiaries currently own or lease the equipment utilized in their mining operations. You should see “Our Mining Operations” for more information about our mining operations, mining complexes and transportation facilities.
Our Coal Reserves
We estimate that we owned or controlled approximately
2.1. billion
tons of proven and probable recoverable reserves at
December 31, 2017
. Our coal reserve estimates at
December 31, 2017
were prepared by our engineers and geologists and reviewed by Weir International, Inc., a mining and geological consultant. Our coal reserve estimates are based on data obtained from our drilling activities and other available geologic data. Our coal reserve estimates are periodically updated to reflect past coal production and other geologic and mining data. Acquisitions or sales of coal properties will also change these estimates. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam.
Our coal reserve estimates include reserves that can be economically and legally extracted or produced at the time of their determination. In determining whether our reserves meet this standard, we take into account, among other things, our potential inability to obtain a mining permit, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in costs required to be incurred to meet regulatory requirements and obtaining mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. We use various assumptions in preparing our estimates of our coal reserves. You should see “Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs” contained in Item 1A, “Risk Factors.”
The following tables present our estimated assigned and unassigned recoverable coal reserves at
December 31, 2017
:
Total Assigned Reserves
(Tons in millions)
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Total Assigned Recoverable Reserves
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As Received Btus per lb. (1)
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Sulfur Content (lbs. per million Btus)
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Mining Method
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Past Reserve Estimates
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Reserve Control
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Under-
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Proven
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Probable
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<1.2
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1.2-2.5
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>2.5
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Leased
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Owned
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Surface
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ground
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2015
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2016
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Wyoming
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1,025
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1,019
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6
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|
963
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62
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—
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8,832
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1,025
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1,025
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—
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1,318
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1,115
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Colorado
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53
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47
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6
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53
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—
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—
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11,476
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53
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—
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—
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53
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53
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56
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Central App.
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69
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59
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10
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25
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44
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—
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13,076
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62
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7
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22
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47
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35
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70
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Northern App.
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35
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32
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3
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—
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35
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—
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13,018
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5
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|
30
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—
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35
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40
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48
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Illinois
|
35
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|
20
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15
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—
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—
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35
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10,737
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30
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5
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—
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35
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37
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38
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Total
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1,217
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1,177
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|
40
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1,041
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|
141
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35
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9,365
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1,175
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|
42
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1,047
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|
170
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1,483
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1,327
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(1)
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As received Btus per lb. includes the weight of moisture in the coal on an as sold basis.
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Total Unassigned Reserves
(Tons in millions)
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Total Unassigned Recoverable Reserves
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Sulfur Content
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Mining Method
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(lbs. per million Btus)
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As Received
|
Reserve Control
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Under‑
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|
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Proven
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Probable
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<1.2
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1.2-2.5
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>2.5
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Btus per lb.
(1)
|
Leased
|
Owned
|
Surface
|
ground
|
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Wyoming
|
290
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|
244
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46
|
|
242
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|
48
|
|
—
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8,446
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|
290
|
|
—
|
|
290
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|
—
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|
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Colorado
|
28
|
|
22
|
|
6
|
|
28
|
|
—
|
|
—
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|
11,339
|
|
28
|
|
—
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|
—
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|
28
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|
|
Central App.
|
51
|
|
44
|
|
7
|
|
14
|
|
24
|
|
13
|
|
12,482
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|
2
|
|
49
|
|
33
|
|
18
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|
|
Northern App.
|
198
|
|
115
|
|
83
|
|
—
|
|
195
|
|
3
|
|
13,009
|
|
9
|
|
189
|
|
—
|
|
198
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|
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Illinois
|
285
|
|
189
|
|
96
|
|
—
|
|
—
|
|
285
|
|
11,162
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|
59
|
|
226
|
|
3
|
|
282
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Total
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852
|
|
614
|
|
238
|
|
284
|
|
267
|
|
301
|
|
10,753
|
|
388
|
|
464
|
|
326
|
|
526
|
|
|
|
|
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(1)
|
As received Btus per lb. includes the weight of moisture in the coal on an as sold basis.
|
Federal and state legislation controlling air pollution affects the demand for certain types of coal by limiting the amount of sulfur dioxide which may be emitted as a result of fuel combustion and encourages a greater demand for low-sulfur coal. All of our identified coal reserves have been subject to preliminary coal seam analysis to test sulfur content. Of these reserves, approximately 66% consist of compliance coal, or coal which emits 1.2 pounds or less of sulfur dioxide per million Btus upon combustion, while an additional approximately 8% could be sold as low-sulfur coal. The balance is classified as high-sulfur coal. Most of our reserves are suitable for the domestic steam coal markets. A substantial portion of the low-sulfur and compliance coal reserves at a number of our Appalachian mining complexes may also be used as metallurgical coal.
The carrying cost of our coal reserves at
December 31, 2017
was $
0.4 billion
, consisting of $
4.7 million
of prepaid royalties and a net book value of coal lands and mineral rights of
$0.4 billion
.
Reserve Acquisition Process
We acquire a significant portion of the coal we control in the western United States through the lease‑by‑application (LBA) process. Under this process, before a mining company can obtain new coal reserves, the coal tract must be nominated for lease, and the company must win the lease through a competitive bidding process. The LBA process can last anywhere from five to ten years or more from the time the coal tract is nominated to the time a final bid is accepted by the BLM. After the LBA is awarded, the company then conducts the necessary testing to determine what amount can be classified as reserves.
To initiate the LBA process, companies wanting to acquire additional coal must file an application with the BLM’s state office indicating interest in a specific coal tract. The BLM reviews the initial application to determine whether the application conforms to existing land‑use plans for that particular tract of land and that the application would provide for maximum coal recovery. The application is further reviewed by a regional coal team at a public meeting. Based on a review of the available information and public comment, the regional coal team will make a recommendation to the BLM whether to continue, modify or reject the application.
If the BLM determines to continue the application, the company that submitted the application will pay for a BLM‑directed environmental analysis or an environmental impact statement to be completed. This analysis or impact statement is subject to publication and public comment. The BLM may consult with other governmental agencies during this process, including state and federal agencies, surface management agencies, Native American tribes or bands, the U.S. Department of Justice or others as needed. The public comment period for an analysis or impact statement typically occurs over a 60‑day period.
After the environmental analysis or environmental impact statement has been issued and a recommendation has been published that supports the lease sale of the LBA tract, the BLM schedules a public competitive lease sale. The BLM prepares an internal estimate of the fair market value of the coal that is based on its economic analysis and comparable sales analysis. Prior to the lease sale, companies interested in acquiring the lease must send sealed bids to the BLM. The bid amounts for the lease are payable in five annual installments, with the first 20% installment due when the mining operator submits its initial bid for an LBA. Before the lease is approved by the BLM, the company must first furnish to the BLM an initial rental payment for the first year of rent along with either a bond for the next 20% annual installment payment for the bid amount, or an application for history of timely payment, in which case the BLM may waive the bond requirement if the company successfully meets all the qualifications of a timely payor. The bids are opened at the lease sale. If the BLM decides to grant a lease, the lease is awarded to the company that submitted the highest total bid meeting or exceeding the BLM’s fair market value estimate, which is not published. The BLM, however, is not required to grant a lease even if it determines that a bid meeting or exceeding the fair market value of the coal has been submitted. The winning bidder must also submit a report setting forth the nature and extent of its coal holdings to the U.S. Department of Justice for a 30‑day antitrust review of the lease. If the successful bidder was not the initial applicant, the BLM will refund the initial applicant certain fees it paid in connection with the application process, for example the fees associated with the environmental analysis or environmental impact statement, and the winning bidder will bear those costs. Coal won through the LBA process and subject to federal leases are administered by the U.S. Department of Interior under the Federal Coal Leasing Amendment Act of 1976. In addition, we occasionally add small coal tracts adjacent to our existing LBAs through an agreed upon lease modification with the BLM. Once the BLM has issued a lease, the company must also complete the permitting process before it can mine the coal. 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 is produced in commercial quantities. These leases require diligent development within the first ten years of the lease award with a required coal extraction of 1.0% of the total coal under the lease by the end of that 10‑year period. At the end of the 10‑year development period, the lessee is required to maintain continuous operations, as defined in the applicable leasing regulations. In certain cases a lessee may combine contiguous leases into a logical mining unit, which we refer to as an LMU. This allows the production of coal from any of the leases within the LMU to be used to meet the continuous operation requirements for the entire LMU. Some of our mines are also subject to coal leases with applicable state regulatory agencies and have different terms and conditions that we must adhere to in a similar way to our federal leases. Under these federal and state leases, if the leased coal is not diligently developed during the initial 10‑year development period or if certain other terms of the leases are not complied with, including the requirement to produce a minimum quantity of coal or pay a minimum production royalty, if applicable, the BLM or the applicable state regulatory agency can terminate the lease prior to the expiration of its term.
On January 15, 2016, the federal government ordered a moratorium on new leases for coal mined from federal lands as part of a review of the government’s management of federally-owned coal. In March 2017, the U.S. Secretary of Interior signed Secretarial Order 3348 lifting that moratorium and halting the Federal Coal Program Programmatic Environmental Impact Statement that was in process at the time. Litigation is currently pending in the United States District Court for the District of Montana challenging the lifting of the moratorium as a violation of the National Environmental Policy Act, the Mineral Leasing Act and the Federal Land Policy and Management Act. Although the Bureau of Land Management is now working to process coal lease applications and modifications expeditiously in accordance with regulations and guidance that existed before Secretarial Order 3338, which imposed the moratorium on new coal leases, any delay in the LBA process, including any delay caused by the now-lifted moratorium could prevent us from obtaining replacement reserves when we require them. Also, the outcome of the government’s review is uncertain and could have a material and adverse impact on our business in any number of ways including by limiting our ability to mine reserves under ongoing or future applications, by increasing the costs or timeframe associated with obtaining leases under the LBA program, by making it uneconomical for us to participate in the programs or by preventing us from obtaining replacement reserves if the LBA program were to be terminated. Please see “Our inability to acquire additional coal reserves or our inability to develop coal reserves in an economically feasible manner may adversely affect our business,” contained in Item 1A. “Risk Factors” for more information.
Title to Coal Property
Title to coal properties held by lessors or grantors to us and our subsidiaries and the boundaries of properties are normally verified at the time of leasing or acquisition. However, in cases involving less significant properties and consistent with industry practices, title and boundaries are not completely verified until such time as our independent operating subsidiaries prepare to mine such reserves. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to mine such reserves could be adversely affected. You should see “A defect in title or the loss of a leasehold interest in certain property or surface rights could limit our ability to mine our coal reserves or result in significant unanticipated costs” contained in Item 1A, “Risk Factors” for more information.
At
December 31, 2017
, approximately
24%
of our coal reserves were held in fee, with the balance controlled by leases, most of which do not expire until the exhaustion of mineable and merchantable coal. Under current mining plans, substantially all reported leased reserves will be mined out within the period of existing leases or within the time period of assured lease renewals. Royalties are paid to lessors either as a fixed price per ton or as a percentage of the gross sales price of the mined coal. The majority of the significant leases are on a percentage royalty basis. In some cases, a payment is required, payable either at the time of execution of the lease or in annual installments. In most cases, the prepaid royalty amount is applied to reduce future production royalties.
From time to time, lessors or sublessors of land leased by our subsidiaries have sought to terminate such leases on the basis that such subsidiaries have failed to comply with the financial terms of the leases or that the mining and related operations conducted by such subsidiaries are not authorized by the leases. Some of these allegations relate to leases upon which we conduct operations material to our consolidated financial position, results of operations and liquidity, but we do not believe any pending claims by such lessors or sublessors have merit or will result in the termination of any material lease or sublease.
We leased approximately 57,773 acres of property to other coal operators in
2017
. We received royalty income of $4.1 million during 2017 from the mining of approximately 1.2 million tons, $1.1 million during the period
October 2 through December 31, 2016
from the mining of approximately 0.4 million tons, $1.7 million during the period
January 1 through October 1, 2016
from the mining of approximately 0.6 million tons, and $6.3 million in
2015
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 in the 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 conferring with counsel, it is the opinion of management that the ultimate resolution of these claims, to the extent not previously provided for, will not have a material adverse effect on our consolidated financial condition, results of operations or liquidity.
ITEM 4. MINE SAFETY DISCLOSURES.
The statement concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Annual Report on Form 10-K for the period ended
December 31, 2017
.
Notes to Consolidated Financial Statements
1.
Basis of Presentation
The 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 the Predecessor and Successor Company. The Company’s primary business is the production of thermal and metallurgical coal from surface and underground mines located throughout the United States, for sale to utility, industrial and steel producers both in the United States and around the world. The Company currently operates mining complexes in West Virginia, Illinois, Wyoming and Colorado. All subsidiaries are wholly-owned. Intercompany transactions and accounts have been eliminated in consolidation.
Chapter 11 Filing and Emergence from Bankruptcy
On January 11, 2016 (the “Petition Date”), Arch and substantially all of its wholly owned domestic subsidiaries (the “Filing Subsidiaries” and, together with Arch, the “Debtors”) filed voluntary petitions for reorganization (collectively, the “Bankruptcy Petitions”) under Chapter 11 of Title 11 of the U.S. Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Eastern District of Missouri (the “Court”). The Debtor’s Chapter 11 Cases (collectively, the “Chapter 11 Cases”) were jointly administered under the caption
In re Arch Coal, Inc., et al.
Case No. 16-40120 (lead case). During the bankruptcy proceedings, each Debtor operated its business as a “debtor in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Court.
For periods subsequent to filing the Bankruptcy Petitions, the Company applied the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, “Reorganizations”, in preparing its consolidated financial statements. ASC 852 requires that financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings have been recorded in a reorganization line item on the Consolidated Statement of Operations. In addition, the pre-petition obligations that may be impacted by the bankruptcy reorganization 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 Reorganization under Chapter 11 of the Bankruptcy Code dated as of September 11, 2016 (the “Plan”), which order was amended on September 15, 2016, Docket No. 1334.
On October 5, 2016, Arch Coal satisfied the closing conditions contemplated by the Plan, which became effective on that date (the “Effective Date”).
On the Plan Effective Date, the Company applied fresh start accounting which required the Company to allocate its reorganization value to the fair value of assets and liabilities in conformity with the guidance for the acquisition method of accounting for business combinations. In addition to fresh start accounting, the Company’s consolidated financial statements reflect all impacts of the transactions contemplated by the Plan. Under the provisions of fresh start accounting, a new entity has been created for financial reporting purposes. The Company selected an accounting convenience date of October 1, 2016 for purposes of applying fresh start accounting as the activity between the convenience date and the Effective Date does not result in a material difference in the results. References to “Successor” in the financial statements and accompanying footnotes are in reference to reporting dates on or after October 2, 2016; references to “Predecessor” in the financial statements and accompanying footnotes are in reference to reporting dates through October 1, 2016 which includes the impact of the Plan provisions and the application of fresh start accounting. As such, the Company’s financial statements for the Successor will not be comparable in many respects to its financial statements for periods prior to the adoption of fresh start accounting and prior to the accounting for the effects of the Plan.
2.
Accounting Policies
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States for financial reporting and U.S. Securities and Exchange Commission regulations.
Accounting Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and revenues and expenses in the accompanying consolidated financial statements and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost. Cash equivalents consist of highly-liquid investments with an original maturity of three months or less when purchased.
Restricted cash
Restricted cash represents cash collateral supporting letters of credit issued under the Company’s accounts receivable securitization program.
Accounts Receivable
Accounts receivable are recorded at amounts that are expected to be collected, based on past collection history, the economic environment and specified risks identified in the receivables portfolio.
Inventories
Coal 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 period the stripping costs are incurred.
Investments and Membership Interests in Joint Ventures
Investments and membership interests in joint ventures are accounted for under the equity method of accounting if the Company has the ability to exercise 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 Financial Statements, “
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 and are recorded at their fair values. Unrealized gains and losses on these investments are recorded in other comprehensive income or loss. A decline in the value of an investment that is considered other-than-temporary would be recognized in operating expenses.
Sales Contracts
Coal supply agreements (sales contracts) valued during fresh start accounting or acquired in a business combination are capitalized at their fair value and amortized 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 flows attributable 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
to the Consolidated Financial Statements, “
Sales Contracts
” for further information related to the Company’s sales contracts.
Exploration Costs
Costs to acquire permits for exploration activities are capitalized. Drilling and other costs related to locating coal deposits and evaluating the economic viability of such deposits are expensed as incurred.
Prepaid Royalties
Leased mineral rights are often acquired through royalty payments. When royalty payments represent prepayments recoupable against royalties owed on future 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 recognized for prepaid royalties that are not expected to be recouped.
Property, Plant and Equipment
Plant and Equipment
Plant and equipment were recorded at fair value at emergence during fresh start accounting; subsequent purchases of property, plant and equipment have been recorded at cost. Interest costs incurred during the construction period for major asset additions are capitalized. The Company did not capitalize any interest costs during years ended
December 31, 2017
and
2016
, respectively. Expenditures that extend the useful lives of existing plant and equipment or increase 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 the asset is expensed as incurred.
Preparation plants and loadouts are depreciated using the units-of-production method over the estimated recoverable reserves, subject to a minimum level 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. The useful lives of buildings and leasehold improvements generally range from
1
to
21
years.
Deferred Mine Development
Costs of developing new mines or significantly expanding the capacity of existing mines are capitalized and amortized using the units-of-production method 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, deferred mine development includes the asset cost associated with asset retirement obligations. Coal sales revenue related to incidental production during the development 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 the asset is in place for its intended use.
Coal Lands and Mineral Rights
Rights to coal reserves may be acquired directly through governmental or private entities. A significant portion of the Company’s coal reserves are controlled through leasing arrangements. Lease agreements are generally long-term in nature (original terms range from
10
to
50
years), and substantially all of 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 to acquire royalty lease agreements and lease bonus payments are capitalized as a cost of the underlying mineral reserves and depleted over the life of proven and 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 amortization
The depreciation, depletion and amortization related to long-lived assets is reflected in the statement of operations as a separate line item. No depreciation, depletion or amortization is included in any other operating cost categories.
Impairment
If 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 reviewed for potential impairment. If this review indicates that the carrying amount of the asset will not be recoverable through projected undiscounted cash flows generated 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 to its fair value. The Company may, under certain circumstances, idle mining operations in response to market conditions or other factors. Because an idling is not a permanent closure, it is not considered an automatic indicator of impairment. See additional discussion in Note
6
to the Consolidated Financial Statements, “
Impairment Charges and Mine Closure Costs
.”
Deferred Financing Costs
The Company capitalizes costs incurred in connection with new borrowings, the establishment or enhancement of credit facilities and the issuance of debt 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 interest method. Debt issuance costs related to a recognized liability are presented in the balance sheet as a direct reduction from the carrying amount of that liability whereas debt issuance costs related to a credit facility with no balance outstanding are shown as an asset. The unamortized balance of deferred financing costs shown 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 shown as 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” and the noncurrent amounts are classified within
“Other noncurrent assets.” For information on the unamortized balance of deferred financing fees related to outstanding debt, see Note
14
to the Consolidated Financial Statements, “
Debt and Financing Arrangements
.”
Revenue Recognition
Revenues include sales to customers of coal produced at Company operations and coal purchased from third parties. The Company recognizes revenue at 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 to its customers for transportation are included in revenues.
Other Operating Expense (Income), net
Other operating expense (income), net
in the accompanying consolidated statements of operations reflects income and expense from sources other than physical 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 equity investments (Note
10
, “
Equity Method Investments and Membership Interests in Joint Ventures
”); non-material gains and losses from divestitures and dispositions 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 Obligations
The 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 mine commences for underground and surface mines or construction begins for support facilities, refuse areas and slurry ponds. The obligation’s fair value is determined using a discounted cash flow technique and is based upon permit requirements and various estimates and assumptions that would be used by market participants, including estimates of disturbed acreage, reclamation costs and assumptions regarding equipment productivity. Upon initial recognition of 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 authorities and for revisions of estimates of the amount and timing of costs. For ongoing operations, adjustments to the liability result in an adjustment to the corresponding asset. For idle operations, adjustments to the liability are recognized as income or expense in the period the adjustment is recorded. Any difference between the recorded obligation and the actual cost of reclamation is recorded in profit or loss in the period the obligation is settled. See additional discussion in Note
16
, “
Asset Retirement Obligations
.”
Loss Contingencies
The Company accrues for cost related to contingencies when a loss is probable and the amount is reasonably determinable. Disclosure of contingencies is 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 already accrued 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, the minimum amount in the range.
Derivative Instruments
The 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 fair value. Certain coal contracts may meet 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 by the Company over a reasonable period in the normal course of business, they are not recognized on the balance sheet.
Certain derivative instruments are designated as the hedge instrument in a hedging relationship. In a fair value hedge, the Company hedges the risk of changes 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 of a 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 future 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 cash flow hedge are recorded in other comprehensive income or loss. Amounts in other comprehensive income or loss are reclassified to earnings when the hedged transaction affects earnings and are classified in a manner consistent with the transaction being hedged. The Company formally documents the relationships between hedging instruments and the respective hedged items, as well as its risk management objectives for hedge transactions.
The Company evaluates the effectiveness of its hedging relationships both at the hedge’s inception and on an ongoing basis. Any ineffective portion of the 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. The ineffective 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 cumulative change 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 Value
Fair 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 between market participants at a given measurement date. Valuation techniques used must maximize the use of observable inputs and minimize the use of unobservable inputs. See Note
17
, “
Fair Value Measurements
” for further disclosures related to the Company’s recurring fair value estimates.
Income Taxes
Deferred income taxes are provided for temporary differences arising from differences between the financial statement and tax basis of assets and liabilities 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. A valuation 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 its deferred tax assets annually in the fourth quarter or when circumstances indicate that the ability to realize deferred tax assets has changed. In determining the need for a valuation allowance, the Company considers projected realization of tax benefits based on expected levels of future taxable income, available tax planning 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 be sustained 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 the largest 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 Plans
The Company has non-contributory defined benefit pension plans covering most of its salaried and hourly employees. On January 1, 2015 the Company’s cash balance and excess pension plans were amended to freeze new service credits for any new or active employee. The Company also currently provides certain postretirement medical and life insurance coverage for eligible employees. The cost of providing these benefits is determined on an actuarial basis and accrued over the employee’s period of active service.
The Company recognizes the overfunded or underfunded status of these plans as determined on an actuarial basis on the balance sheet and the changes in the funded status are recognized in other comprehensive income. The Company amortizes actuarial gains and losses over the remaining service attribution periods of the employees using the corridor method. See Note
21
, “
Employee Benefit Plans
” for additional disclosures relating to these obligations.
Stock-Based Compensation
The compensation cost of all stock-based awards is determined based on the grant-date fair value of the award, and is recognized over the requisite service 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 for forfeitures as they occur. See further discussion in Note
19
, “
Stock-Based Compensation and Other Incentive Plans
.”
Recently Adopted Accounting Guidance
In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Compensation - Stock Compensation (Topic 718) ("ASU 2016-09"). ASU 2016-09 identifies areas for simplification involving several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, an option to recognize gross stock compensation expense with actual forfeitures recognized as they occur, as well as certain classifications on the statement of cash flows. The Company adopted all provisions of this new accounting standard in the first quarter of 2017 and changed its forfeiture policy to recognize the impact of forfeitures when they occur from estimating expected forfeitures in determining stock-based compensation expense. There was no material impact to the Company's financial statements.
Recent Accounting Guidance Issued Not Yet Effective
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 is a comprehensive revenue recognition standard that will supersede nearly all existing revenue recognition guidance under current U.S. GAAP and replace it with a principle based approach for determining revenue recognition. ASU 2014-09 requires that companies recognize revenue based on the value of transferred goods or services as they occur in the contract. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2017. The Company’s primary source of revenue is from the sale of coal through both short-term and long-term contracts with utilities, industrial customers and steel producers whereby revenue is currently recognized when risk of loss has passed to the customer. During the fourth quarter of 2017, the Company finalized its assessment related to the new standard by analyzing certain contracts representative of the majority of the Company’s coal sales and determined that the timing of revenue recognition related to the Company’s coal sales will remain consistent between the new standard and the current standard. The Company also reviewed other sources of revenue, and concluded the current basis of accounting for these items is in accordance with the new standard. The Company has concluded its adoption, using the modified retrospective method, will not have a material impact on its consolidated financial statements and there will be no cumulative adjustment to retained earnings. The Company also reviewed the disclosure requirements under the new standard and is compiling information needed for the expanded disclosures required 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 lease liability, 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 for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early adoption is permitted. The Company has both operating and capital leases. We expect the adoption of this standard to result in the recognition of right-of-use assets and lease liabilities not currently recorded on the Company’s financial statements. The Company is currently in the process of accumulating all contractual lease arrangements in order to determine 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 the classification of certain cash receipts and cash payments in the statement of cash flows to reduce diversity in practice. The new guidance will be effective for fiscal years beginning after December 15, 2017 and the interim periods therein, with early adoption permitted. The amendments in the classification should be applied retrospectively to all periods presented, unless deemed impracticable, in which case, the prospective application is permitted. The Company plans to 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 cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning period and end of period total amounts shown on the statement of cash flows. ASU 2016-18 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early adoption is permitted. The Company plans to adopt the guidance in this standard during the first quarter of 2018.
In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” 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 line item(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 to present the other components of net periodic benefit cost, if the components are not presented separately in the income statement. Additionally, only the service cost component will be eligible for capitalization in assets. ASU 2017-07 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal year; early adoption is permitted. The Company plans to adopt the guidance in this standard during the first quarter of 2018.
In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” The new guidance provides targeted improvements to the accounting for hedging activities to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedging results. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early adoption is permitted. The Company anticipates early adopting the standard in the first quarter of 2018, although we do not expect a significant impact to the Company’s financial results.
3.
Emergence from Bankruptcy and Fresh Start Accounting
On January 11, 2016 (the “Petition Date”), Arch and substantially all of its wholly owned domestic subsidiaries (the “Filing Subsidiaries” and, together with Arch, the “Debtors”) filed voluntary petitions for reorganization (collectively, the “Bankruptcy Petitions”) under Chapter 11 of Title 11 of the U.S. Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Eastern District of Missouri (the “Court”). The Debtor’s Chapter 11 Cases (collectively, the “Chapter 11 Cases”) were jointly administered under the caption
In re Arch Coal, Inc., et al.
Case No. 16-40120 (lead case). During the bankruptcy proceedings, each Debtor operated its business as a “debtor in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Court.
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 are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings have been recorded in a reorganization line item on the Consolidated Statement of Operations. In addition, the pre-petition obligations that may be impacted by the bankruptcy reorganization 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 Reorganization under Chapter 11 of the Bankruptcy Code dated as of September 11, 2016 (the “Plan”), which order was amended on September 15, 2016, Docket No. 1334.
On October 5, 2016, Arch Coal satisfied the closing conditions contemplated by the Plan, which became effective on that date (the “Effective Date”).
On the Plan Effective Date, the Company applied fresh start accounting which required the Company to allocate its reorganization value to the fair value of assets and liabilities in conformity with the guidance for the acquisition method of accounting for business combinations. In addition to fresh start accounting, the Company’s consolidated financial statements reflect all impacts of the transactions contemplated by the Plan. Under the provisions of fresh start accounting, a new entity has been created for financial reporting purposes. The Company selected an accounting convenience date of October 1, 2016 for purposes of applying fresh start accounting as the activity between the convenience date and the Effective Date does not result in a material difference in the results. References to “Successor” in the financial statements and accompanying footnotes are in reference to reporting dates on or after October 2, 2016; references to “Predecessor” in the financial statements and accompanying footnotes are in reference to reporting dates through October 1, 2016 which includes the impact of the Plan provisions and the application of fresh start accounting. As such, the Company’s financial statements for the Successor will not be comparable in many respects to its financial statements for periods prior to the adoption of fresh start accounting and prior to the accounting for the effects of the Plan.
The following is a summary of certain provisions of the Plan, as confirmed by the Bankruptcy Court pursuant to the Confirmation Order, and is not intended to be a complete description of the Plan.
Treatment of Claims
The Plan contemplates that:
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•
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Holders of allowed administrative expense claims, priority claims (other than administrative expense claims and priority tax claims) and secured claims (other than claims arising under priority claims, the prepetition first lien credit facility and prepetition second lien notes) will be paid in full.
|
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|
|
|
•
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Holders of allowed claims arising under the Debtors’ prepetition first lien credit facility (“First Lien Credit Facility”) will receive their pro rata distribution of (i) total cash payments equal to the greater of (A)
$144.8 million
less the amount of the adequate protection payments and (B)
$30 million
; (ii)
$326.5 million
in principal amount of New First Lien Debt Facility; and (iii)
94%
of the common stock of Reorganized 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 A Common 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 calculated based on a total equity capitalization of
$1.425 billion
(
$57
per share) and (b) the issuance of New Common
|
Stock 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”).
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|
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•
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Holders of allowed claims on account of prepetition second lien or unsecured notes (the “Prepetition Notes”) will receive their pro rata distribution 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 of the New Warrants and pursuant to the Management Incentive Plan).
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|
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•
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Holders of allowed general unsecured claims against Debtors (other than claims on account of the First Lien Credit Facility or Prepetition Notes) will receive their pro rata distribution of
$7.364 million
cash, less fees and expenses incurred by any professionals retained by a claims oversight committee up to
$200,000
.
|
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|
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•
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The Reorganized Debtors will waive and release any claims or causes of action that they have, had, or may have that are based on sections 502(d), 544, 545, 547, 548, 549, 550, 551, 553(b) and 724(a) of the Bankruptcy Code and analogous non-bankruptcy law for all purposes against (i) prepetition trade creditors and (ii) officers, directors, employees or representatives of the Debtors or the Reorganized Debtors and all agents and representatives of all of the foregoing. However, the Reorganized Debtors will retain the right to assert any said claims as defenses or counterclaims in any cause of action brought by any creditor.
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Warrant Agreement
On the Effective Date, the Company entered into a warrant agreement (the “Warrant Agreement”) with American Stock Transfer & Trust Company, LLC as 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 Common Stock, 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). Each Warrant 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. The Warrants 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-dilution adjustments for stock splits, reverse stock splits, stock dividends, dividends and distributions of cash, other securities or other property, spin-offs and tender and 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 or other transaction that results in a change to the Class A Common Stock (each, a “Transaction”), (i) the Transaction is consummated prior to the fifth anniversary of the Effective Date and the Transaction consideration to holders of Class A Common Stock is
90%
or more listed common stock or common stock of a company that provides publicly available financial reporting, and holds management calls regarding the same, no less than quarterly (“Reporting Stock”) or (ii) regardless of the consideration, the Transaction is consummated on or after the fifth anniversary of the Effective Date, the Warrants will be assumed 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 each Warrant 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 Stock underlying the Warrant
minus
(y) the exercise price per share then in effect
multiplied by
the number of shares of Class A Common Stock underlying the Warrant 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%
Reporting Stock, a portion of the Warrants corresponding to the portion of the Transaction consideration that is Reporting Stock will be assumed by the surviving company and will become exercisable for the Reporting Stock consideration that the holders of Class A Common Stock receive in such Transaction, and the portion of the Warrants corresponding to the portion of the Transaction consideration that is not Reporting Stock will, at the option of each holder, (i) be assumed by the surviving company and will become exercisable for the consideration that the holders of Class A Common Stock receive in such Transaction or (ii) be redeemed by Arch Coal for cash in an amount equal to the Black Scholes Payment (as defined in the Warrant Agreement).
Termination of Material Definitive Agreements
On the Effective Date, by operation of the Plan, all outstanding obligations under the following notes issued by Arch Coal and guaranteed by certain subsidiary guarantors, (collectively, the “Cancelled Notes”) were cancelled and the indentures governing such obligations were cancelled except as necessary to (a) enforce the rights, claims and interests of the applicable
trustee vis-a-vis any parties other than the Debtors, (b) allow each trustee to receive distributions under the Plan and to distribute them to the holders of the Cancelled Notes in accordance with the terms of the applicable indenture, (c) preserve any rights of the applicable trustee to compensation, reimbursement and indemnification under each of the applicable indentures solely as against any money or property distributable to holders of Cancelled Notes, (iv) permit each of the trustees to enforce any obligation owed to them under the Plan and (v) permit each of the trustees to appear in the Chapter 11 cases or in any proceeding in the Bankruptcy Court or any other court:
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|
|
•
|
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 National Association, as trustee, and the guarantors named therein, as amended, supplemented or revised thereafter;
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|
|
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•
|
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 National Association, as trustee, and the guarantors named therein, as amended, supplemented or revised thereafter;
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|
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•
|
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 National Association, as trustee, and the guarantors named therein, as amended, supplemented or revised thereafter;
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|
|
|
•
|
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 Bank National Association, as trustee, and the guarantors named therein, as amended, supplemented or revised thereafter; and
|
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|
|
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•
|
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 named therein, 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 relating to the Prepetition Credit Agreement were cancelled and the Prepetition Credit Agreement was cancelled except as necessary to (i) enforce the rights, claims and 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 allow the Prepetition Agent to receive distributions under the Plan and to distribute them to the lenders under the Prepetition Credit Agreement and (iii) preserve any rights of the Prepetition Agent and any predecessor thereof as against any money or property distributable to holders of claims arising out of the Prepetition Credit Agreement or any related transaction documents, including any priority in respect of payment and the right to exercise any charging lien:
|
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|
|
•
|
Amended and Restated Credit Agreement, dated as of June 14, 2011 (as amended by the First Amendment, dated as of May 16, 2012, the Second Amendment, dated as of November 20, 2012, the Third Amendment, dated as of November 21, 2012 and the Fourth Amendment, dated as of December 17, 2013), among Arch Coal, Inc., as borrower, the lenders from time to time party thereto, Wilmington Trust, National Association, in its capacities as term loan facility administrative agent (as successor to Bank of America, N.A. in such capacity) and collateral agent (as successor to PNC 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/or unliquidated obligations were paid in cash in full, all commitments under the DIP Credit Agreement and the related transaction documents referred to therein as the “Loan Documents” were terminated, all liens on property of the Debtors arising out of or related to the DIP Facility terminated and the Loan Documents were cancelled except with respect to (a) contingent and and/or unliquidated obligations under the Loan Documents which survive the Effective Date 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 DIP Credit Agreement, as applicable, including but not limited to, those provisions relating to the rights of the DIP Agent and the lenders to expense reimbursement, indemnification and other similar amounts, certain reinstatement obligations set forth in the DIP Credit Agreement and any provisions that may 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 and Amendment 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, and Amendment No. 7, dated as of September
|
28, 2016) among Arch Coal, Inc., as borrower, certain subsidiaries of Arch Coal, Inc., as guarantors, the lenders from time to time party there and Wilmington Trust, National Association, in its capacity as administrative agent and as collateral agent (in such capacities, the “DIP Agent”).
Equity Securities
Under 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 Common Stock” and together with Class A Common Stock, “Common Stock”) were distributed to the secured lenders and to certain holders of general unsecured claims 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
shares of Class A Common Stock. Arch Coal relied, based on the confirmation order it received from the Bankruptcy Court, on Section 1145(a)(1) of the U.S. Bankruptcy Code to exempt from the registration requirements of the Securities Act of 1933, as amended (i) the offer and sale of Common Stock to the secured lenders and to the general unsecured creditors, (ii) the offer and sale of the Warrants to the holders of claims arising under the Cancelled Notes and (iii) the offer and sale of the Class A Common Stock issuable upon exercise of the Warrants. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under a plan of
reorganization from registration under Section 5 of the Securities Act and state laws if three principal requirements are satisfied:
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•
|
the securities must be offered and sold under a plan of reorganization and must be securities of the debtor, of an affiliate participating in a joint plan of reorganization with the debtor or of a successor to the debtor under the plan of reorganization;
|
|
|
|
|
•
|
the recipients of the securities must hold claims against or interests in the debtor; and
|
|
|
|
|
•
|
the securities must be issued in exchange, or principally in exchange, for the recipient’s claim against or interest in the debtor.
|
Reorganization Value
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 date selected for financial reporting purposes. In conjunction with the bankruptcy proceedings, a third party financial advisor provided an enterprise value of the Company of approximately
$650 million
to
$950 million
. The final equity value of
$687.5 million
was based upon the approximate high end of the enterprise 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 Facility of
$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) discounted cash flow analysis (“DCF”) and (iii) sum-of-the-parts analysis. The comparable public company analysis is based on the enterprise value of selected publicly traded companies that have operating and financial characteristics comparable in certain respects to the Company, for example, operational requirements and risk and profitability characteristics. Selected companies are comprised of coal mining companies with primary operations in the United States. Under this methodology, certain financial multiples and ratios that measure financial performance and value are calculated for each selected company and then applied to 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 present value 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 variety of 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 third party forward pricing curves adjusted for the quality of products sold by the Company. While the Company considers such estimates and assumptions reasonable, they are inherently subject to significant business, economic and competitive uncertainties, many of which are beyond the Company’s control and, therefore, may not be realized. Changes in these estimates and assumptions may have a significant effect on the determination of the Company’s enterprise value. The assumptions used in the calculations for the DCF analysis included projected revenue, cost and cash flows for the years ending
December 31, 2016
through each respective mine life and represented the Company’s best estimates at the time the analysis was prepared. The DCF analysis was completed using discount rates at a range of estimated weighted average costs of capital ranging from
13.25%
to
15.25%
. The DCF analysis involves complex considerations and judgments concerning appropriate discount rates. Due to the unobservable inputs to the valuation, the fair value would be considered Level 3 in the fair value hierarchy.
The sum-of-the-parts analysis is a more detailed market multiples approach the values each part of a company’s business separately based upon the enterprise values of selected publicly traded companies that have operating and financial characteristics comparable in certain respects to each part of the reorganized Company. Under this methodology, certain financial multiples and ratios that measure financial performance and value are calculated for each selected 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 Emergence
Upon emergence in accordance with ASC 852, the Company applied fresh start accounting to its consolidated financial statements as of October 1, 2016 because (i) the reorganization value of the assets of the emerging entity immediately before the date of confirmation was less than the total of all postpetition liabilities and allowed claims and (ii) the holders of the existing voting shares immediately before confirmation received less than
50 percent
of the voting shares of the emerging entity. Upon adoption of fresh start accounting, the Company became a new entity for financial reporting purposes reflecting the Successor capital structure. As such, a new accounting basis in the identifiable assets and liabilities assumed was established with no retained earnings or accumulated 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 the opening balance sheet of the Successor company.
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|
|
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|
|
|
|
|
|
|
|
|
As of October 1, 2016 (In thousands)
|
Predecessor (a)
|
|
Effect of Plan (b)
|
|
Fresh Start Adjustments (c)
|
|
Successor
|
|
Assets
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
400,205
|
|
|
$
|
(199,718
|
)
|
(d)
|
$
|
—
|
|
|
$
|
200,487
|
|
|
Short term investments
|
111,451
|
|
|
—
|
|
|
—
|
|
|
111,451
|
|
|
Restricted cash
|
81,563
|
|
|
—
|
|
|
—
|
|
|
81,563
|
|
|
Trade accounts receivable
|
165,522
|
|
|
—
|
|
|
—
|
|
|
165,522
|
|
|
Other receivables
|
17,227
|
|
|
—
|
|
|
779
|
|
(j)
|
18,006
|
|
|
Inventories
|
159,410
|
|
|
—
|
|
|
(21,078
|
)
|
(k)
|
138,332
|
|
|
Prepaid royalties
|
4,805
|
|
|
—
|
|
|
—
|
|
|
4,805
|
|
|
Deferred income taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Coal derivative assets
|
2,180
|
|
|
—
|
|
|
—
|
|
|
2,180
|
|
|
Other current assets
|
36,960
|
|
|
6,367
|
|
|
53,851
|
|
(l)
|
97,178
|
|
|
Total current assets
|
979,323
|
|
|
(193,351
|
)
|
|
33,552
|
|
|
819,524
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
3,434,941
|
|
|
—
|
|
|
(2,363,829
|
)
|
(m)
|
1,071,112
|
|
|
Other assets
|
|
|
|
|
|
|
|
|
|
|
Prepaid royalties
|
20,997
|
|
|
—
|
|
|
(20,997
|
)
|
(n)
|
—
|
|
|
Equity investments
|
164,232
|
|
|
—
|
|
|
(61,606
|
)
|
(o)
|
102,626
|
|
|
Other noncurrent assets
|
58,569
|
|
|
34,495
|
|
(e)
|
37,503
|
|
(p)
|
130,567
|
|
|
Total other assets
|
243,798
|
|
|
34,495
|
|
|
(45,100
|
)
|
|
233,193
|
|
|
Total 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)
|
$
|
74,345
|
|
|
Accrued expenses and other current liabilities
|
225,739
|
|
|
(36,331
|
)
|
(f)
|
26,644
|
|
(r)
|
216,052
|
|
|
Current maturities of debt
|
3,397
|
|
|
3,265
|
|
(g)
|
—
|
|
|
6,662
|
|
|
Total current liabilities
|
303,731
|
|
|
(33,066
|
)
|
|
26,394
|
|
|
297,059
|
|
|
Long-term debt
|
30,037
|
|
|
323,235
|
|
(g)
|
—
|
|
|
353,272
|
|
|
Asset retirement obligations
|
394,699
|
|
|
—
|
|
|
(60,570
|
)
|
(s)
|
334,129
|
|
|
Accrued pension benefits
|
23,716
|
|
|
—
|
|
|
24,565
|
|
(t)
|
48,281
|
|
|
Accrued other postretirement benefits
|
87,123
|
|
|
—
|
|
|
24,836
|
|
(t)
|
111,959
|
|
|
Accrued workers’ compensation
|
119,828
|
|
|
—
|
|
|
74,520
|
|
(u)
|
194,348
|
|
|
Deferred income taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other noncurrent liabilities
|
96,410
|
|
|
—
|
|
|
888
|
|
(v)
|
97,298
|
|
|
Total liabilities not subject to compromise
|
1,055,544
|
|
|
290,169
|
|
|
90,633
|
|
|
1,436,346
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities subject to compromise
|
5,278,612
|
|
|
(5,278,612
|
)
|
(h)
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
6,334,156
|
|
|
(4,988,443
|
)
|
|
90,633
|
|
|
1,436,346
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’ equity (deficit)
|
|
|
|
|
|
|
|
|
|
|
Common stock, predecessor
|
2,145
|
|
|
(2,145
|
)
|
(i)
|
—
|
|
|
—
|
|
|
Common stock, successor
|
—
|
|
|
250
|
|
(b)
|
—
|
|
|
250
|
|
|
Paid-in capital, predecessor
|
3,056,307
|
|
|
(3,056,307
|
)
|
(i)
|
—
|
|
|
—
|
|
|
Paid-in capital, successor
|
—
|
|
|
687,233
|
|
(b)
|
—
|
|
|
687,233
|
|
|
Treasury 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
|
)
|
|
687,483
|
|
|
Total liabilities and stockholders’ equity (deficit)
|
$
|
4,658,062
|
|
|
$
|
(158,856
|
)
|
|
$
|
(2,375,377
|
)
|
|
$
|
2,123,829
|
|
|
|
|
|
(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 to compromise through a combination of cash payments, the issuance of new common stock and warrants and the issuance of new debt. The following is the calculation of the total pre-tax gain on the settlement of the liabilities subject to compromise:
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
Liabilities subject to compromise
|
|
$
|
5,278,612
|
|
|
Less 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 thousands
|
|
Payment to secured lenders
|
|
$
|
43,496
|
|
|
Payments to unsecured creditors
|
|
42,399
|
|
|
Final adequate protection payment
|
|
36,331
|
|
|
Collateral requirements
|
|
31,665
|
|
|
Professional fees
|
|
31,630
|
|
|
Other
|
|
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 the following:
|
|
|
|
|
|
|
|
|
|
Previously Reported Balance Sheet Line
|
|
In thousands
|
|
Debt
|
|
$
|
5,026,806
|
|
|
Accrued expenses and other current liabilities
|
|
136,295
|
|
|
Accounts payable
|
|
106,297
|
|
|
Other noncurrent liabilities
|
|
9,214
|
|
|
|
|
|
|
Total liabilities subject to compromise
|
|
$
|
5,278,612
|
|
|
|
|
|
(i)
|
Reflects the impacts of the reorganization adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
Total pre-tax gain on settlement of claims
|
|
$
|
4,142,104
|
|
|
Cancellation of predecessor common stock
|
|
2,145
|
|
|
Cancellation of predecessor paid-in capital
|
|
3,056,307
|
|
|
Cancellation 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 coverage for 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 prices less the sum of selling costs, shipping costs and a reasonable profit allowance for the selling effort offset by a
$28.4 million
reduction in critical spare parts inventory. During fresh start accounting, the Company changed its accounting policy with respect to critical spare parts with long lead times; previously these items were valued within inventory, but prospectively, these items will be capitalized within property, plant and equipment when 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 prepaid balances. The fair value of sales contracts was estimated using a discounted cash flow model and will be amortized into earnings as the coal is shipped 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
Fresh Start Adjustments
|
Successor
|
|
(in thousands)
|
|
|
|
|
Net Coal Properties
|
$
|
2,358,779
|
|
$
|
(1,971,314
|
)
|
$
|
387,465
|
|
|
Net Plant & Equipment
|
812,888
|
|
(405,259
|
)
|
407,629
|
|
|
Net Deferred Charges
|
263,274
|
|
12,744
|
|
276,018
|
|
|
|
|
|
|
|
|
$
|
3,434,941
|
|
$
|
(2,363,829
|
)
|
$
|
1,071,112
|
|
The fair value of coal properties was established at
$387.5 million
utilizing a discounted cash flow model and the market approach. The market approach was used to provide a starting value of the coal mineral reserves without consideration for economic obsolescence. The DCF model was based on assumptions market participants would use in the pricing of these assets as well as projections of revenues and expenditures that would be incurred to mine or maintain these coal reserves through the life of mine. The basis of the DCF analysis was the Company’s prepared projections which included a variety of 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 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 to estimate the value of assets where detailed information for the asset was available and an active market was identified with a sufficient number of sales of comparable property that could be independently verified through reliable sources. The cost approach was utilized where there were limitations in the secondary equipment market to derive values from. The first step in the cost approach is the estimation of the cost required to replace the asset via construction or purchasing a new asset with similar utility adjusting for depreciation due to physical deterioration, functional obsolescence due to technology changes and economic obsolescence due to external factors such as regulatory changes. Useful lives were assigned to all assets based on remaining future economic benefit of each asset.
The 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 on market 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; and Dominion Terminal Associates which operates a ground storage-to-vessel coal trans-loading facility in Newport News, Virginia. Equity investments were fair valued in a manner similar to the Company’s wholly-owned subsidiaries using a discounted cash flow model and comparable company approach. The discount rate selected was
14%
and due to the unobservable nature of the inputs, the fair values are considered Level 3 in the fair value 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 receivable related to insurance coverage for self-insured workers’ compensation obligations partially offset by
$13.2 million
in reductions related to prepaid balances. The fair value of sales contracts was estimated using a discounted cash flow model and will be amortized into earnings as the coal is shipped 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 offset by fair value adjustments to establish the current portion of pension, postretirement and workers’ compensation liabilities. The fair value of sales contracts was estimated using a discounted cash flow model and will be amortized into earnings as the coal is shipped throughout the term of the associated contracts.
|
|
|
|
|
(s)
|
Represents the fair value adjustment related to the Company’s asset retirement obligations which was calculated using discounted cash flow models based on current mine plans using the guidance provided within Accounting Standard Codification 410-20, “Asset Retirement Obligations.” The discount 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 benefit obligations were computed using the applicable October 1, 2016 discount rates. In conjunction with fresh start accounting, the Company updated its mortality rate table assumptions and corridor assumption.
|
|
|
|
|
(u)
|
Represents fair value adjustments for workers’ compensation benefits, including occupational disease benefits, that were actuarially determined using the guidance provided within Accounting Standard Codification 712, “Non-retirement Post-employment Benefits.” Upon emergence, the Company’s accounting policy is to actuarially calculate this liability. Prior to emergence, the Company had accounted for its liability based on outstanding 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 partially offset by
$3.1 million
reduction in miscellaneous noncurrent liabilities. The fair value of sales contracts was estimated using a discounted cash flow model and will be amortized into earnings as the coal is shipped throughout the term of the associated contracts.
|
Reorganization Items, Net
In 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 business shall be reported separately as reorganization items.
The Company’s reorganization items, net for the respective periods are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 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 directly attributable to the reorganization.
Contractual Interest Expense During Bankruptcy
Upon the filing of bankruptcy, the Company discontinued recording interest expense on unsecured debt that was classified as a liability subject to compromise. Actual interest expense recorded on the Predecessor debt subsequent to the Petition Date was
$135.9 million
for the period
January 1 through October 1, 2016
; contractual interest during this time was
$300.9 million
.
4.
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
|
|
|
563
|
|
|
Amounts reclassified from accumulated other comprehensive income (loss)
|
(316
|
)
|
|
(1,363
|
)
|
|
1,225
|
|
|
(454
|
)
|
|
Fresh start accounting adjustment
|
129
|
|
|
2,084
|
|
|
(507
|
)
|
|
1,706
|
|
|
October 1, 2016
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Successor Company
|
|
|
|
|
|
|
|
|
Unrealized gains (losses)
|
—
|
|
|
24,067
|
|
|
387
|
|
|
24,454
|
|
|
Amounts reclassified from accumulated other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
December 31, 2016
|
$
|
—
|
|
|
$
|
24,067
|
|
|
$
|
387
|
|
|
$
|
24,454
|
|
|
Unrealized 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
|
|
|
$
|
—
|
|
|
$
|
20,367
|
|
The 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.
The following amounts were reclassified out of accumulated other comprehensive income (loss) during the respective periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Details about accumulated
other comprehensive income components
|
|
Successor
|
Predecessor
|
|
Line Item in the
Consolidated Statement of Operations
|
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
Coal hedges
|
|
$
|
—
|
|
|
$
|
—
|
|
$
|
397
|
|
|
Revenues
|
|
Interest 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 tax
|
|
1
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.
|
5.
Divestitures
On September 14, 2017, the Company closed on its’ definitive agreement to sell Lone Mountain Processing LLC, an operating mine complex within the Company’s metallurgical coal segment, and
two
idled mining companies, Cumberland River Coal LLC and Powell Mountain Energy LLC to Revelation Energy LLC. The Company received
$8.3 million
of proceeds offset by
$1.4 million
in disbursements related to landholder consent fees and professional fees; 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 Consolidated Statement 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 Costs
The following table summarizes the amounts reflected on the line “
Asset impairment and mine closure costs
” in the consolidated statements of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
Description
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
(In thousands)
|
|
|
|
|
|
|
|
Coal lands and mineral rights
|
$
|
—
|
|
|
$
|
—
|
|
$
|
74,144
|
|
|
$
|
2,210,488
|
|
|
Plant and equipment
|
—
|
|
|
—
|
|
—
|
|
|
199,107
|
|
|
Deferred development
|
—
|
|
|
—
|
|
—
|
|
|
159,474
|
|
|
Prepaid royalties
|
—
|
|
|
—
|
|
3,406
|
|
|
41,990
|
|
|
Equity investments
|
—
|
|
|
—
|
|
40,920
|
|
|
21,325
|
|
|
Inventories
|
—
|
|
|
—
|
|
—
|
|
|
66
|
|
|
Other
|
—
|
|
|
—
|
|
10,797
|
|
|
(4,147
|
)
|
|
Total
|
$
|
—
|
|
|
$
|
—
|
|
$
|
129,267
|
|
|
$
|
2,628,303
|
|
January 1 Through October 1, 2016 Impairment Charges
During the period January 1 through October 1, 2016, the Company recorded the following to “Asset impairment and mine closure costs” in the Consolidated Statements of Operations:
$74.1 million
recorded in the first quarter related to the impairment of coal reserves and surface land in Kentucky that 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 portion of 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 the first quarter related to an other-than-temporary-impairment charge on an available-for-sale security; a
$38.0 million
impairment recorded in the second quarter related to the Company’s equity investment in a brownfield bulk commodity terminal on the Columbia River in Longview, Washington as the Company relinquished its ownership rights in exchange for future throughput rights;
$7.2 million
of severance expense related to headcount reductions during the first half of the year; a
$3.6 million
curtailment charge related to the Company’s pension, postretirement health and black lung actuarial liabilities due to headcount reductions in the first half of the year.
2015 Impairment Charges
In 2015, as a result of the continued deterioration in thermal and metallurgical coal markets and projections for a muted pricing recovery, certain of the Company’s mine complexes have incurred and are expected to continue to incur operating losses. The Company determined that the further weakening of the pricing 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 to determine if the undiscounted cash flows exceeded the current asset values for certain operating complexes in the Company’s Appalachia segment. For multiple operating complexes, the undiscounted cash flows did not exceed the carrying value of the long-lived assets. Discounted cash flows were utilized to reduce the carrying value of those assets to fair value. The discount rate used reflected the then current financial difficulties present in the commodities sector in 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 buying or selling coal mining assets. Additionally, the Company determined that the then current market conditions represented an indicator of impairment for certain undeveloped coal properties that were acquired in times of significantly
higher coal prices. The then current prices and the significant capital outlay that would have been required to develop these reserves indicated that the carrying 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
$2.1 billion
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 recorded to the Company’s Appalachia segment, with the remaining
$0.4 billion
recorded to the Company’s Other operating segment. There is no fair value remaining related to the impaired assets.
During the second quarter of 2015, the Company recorded
$19.1 million
to “Asset impairment and mine closure costs” in the Consolidated Statements of Operations. 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 Mountain Laurel, Spruce and Briar Branch operations that was determined would not be recouped based on estimates of sales volume and pricing through the March 2017 recoupment period. Additionally, the Company recorded a
$5.6 million
impairment charge related to the closure of a higher-cost mining complex serving the metallurgical coal markets.
7.
Losses from disposed operations resulting from Patriot Coal bankruptcy
On December 31, 2005, Arch entered into a purchase and sale agreement with Magnum to sell certain operations. On July 23, 2008, Patriot acquired Magnum. On May 12, 2015, Patriot and certain of its wholly owned subsidiaries (“Debtors”), including Magnum, filed voluntary petitions for reorganization under 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 of Reorganization 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 Coal Industry Retiree Health Benefit Act of 1992 for certain retirees of Magnum who retired prior to October 1, 1994. In addition, the Company had provided surety 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 surety bonds 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
|
|
|
$
|
37,268
|
|
|
Repair 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
$0.0 million
at
December 31, 2016
.
9.
Investments in Available-for-Sale Securities
The Company has invested primarily in highly liquid investment-grade corporate bonds. These investments are held in the custody of a major financial institution. 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 bonds
|
92,038
|
|
|
—
|
|
|
(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 securities
|
1,749
|
|
|
388
|
|
|
—
|
|
|
2,137
|
|
|
—
|
|
|
2,137
|
|
|
Total Investments
|
$
|
89,910
|
|
|
$
|
388
|
|
|
$
|
(89
|
)
|
|
$
|
90,209
|
|
|
$
|
88,072
|
|
|
$
|
2,137
|
|
The 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
at
December 31, 2017
and
2016
, respectively. The aggregate fair value of investments with unrealized losses that have been owned for over a year was
$0.0 million
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 2018
through the
second quarter of 2019
. The Company classifies its investments as current based on the nature of the investments and their availability to provide cash for use in current operations, if needed.
10.
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 the ability to exercise significant influence, but not control, over the entity. Equity method investments are reviewed for impairment whenever events or changes in 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
|
|
Total
|
|
Predecessor Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2015
|
|
$
|
158,477
|
|
|
$
|
13,738
|
|
|
$
|
40,223
|
|
|
$
|
20,740
|
|
|
$
|
2,664
|
|
|
$
|
235,842
|
|
|
Advances 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
|
)
|
|
7,979
|
|
|
Impairment 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
|
)
|
|
201,877
|
|
|
Advances 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
|
)
|
|
5,314
|
|
|
Impairment 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
|
|
|
102,625
|
|
|
Successor Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Advances to (distributions from) affiliates, net
|
|
(9,076
|
)
|
|
822
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,254
|
)
|
|
Equity in comprehensive income (loss)
|
|
2,569
|
|
|
(841
|
)
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
|
1,703
|
|
|
December 31, 2016
|
|
$
|
87,493
|
|
|
$
|
8,581
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
96,074
|
|
|
Investments in affiliates
|
|
—
|
|
|
7,158
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,158
|
|
|
Advances 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 March 2017, 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 and handling agreement with DTA, each partner is charged its share of cash operating and debt-service costs in exchange for the right to use the facility’s loading capacity and is required to make periodic cash advances to DTA to fund such costs.
The Company previously held a
38%
ownership interest in Millennium Bulk Terminals-Longview, LLC (“Millennium”), the owner of a brownfield bulk commodity terminal on the Columbia River near Longview, Washington. Millennium continues to work on obtaining the required approvals and necessary permits to complete dredging and other upgrades to ship coal, alumina and cementitious material from the terminal. During the second quarter of 2016, the Company recorded an impairment charge of
$38.0 million
representing the entire value of its equity investment as the Company relinquished its ownership rights 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 River was formed to develop and construct a railway line near Miles City, Montana and the Otter Creek reserves formerly controlled by the Company. The Company had the right, upon the receipt of permits and approval for construction or under other prescribed circumstances, to require the other investors to purchase 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 distributions received. During the third quarter of 2015, the Company recorded an impairment charge of
$21.3 million
representing the entire value of the Company’s investment in the project; the impairment charge is included on the line “Asset impairment and mine closure costs.”
The Company is not required to make any future contingent payments related to development financing for any of its equity investees.
11.
Sales Contracts
The 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
|
|
|
$
|
64,658
|
|
|
Balance 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 management
The Company has entered into some interest rate swaps to reduce the variability of cash outflows associated with interest payments on its variable rate term loan. These swaps have been designated as cash flow hedges. For additional information on these arrangements, see Note
14
, “
Debt and Financing Arrangements
” 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 approximately
42
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 for its operations, the Company uses forward physical diesel purchase contracts and purchased heating oil call options. At
December 31, 2017
, the Company had heating 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 coal prices. 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 fair value 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
|
|
Total
|
|
Coal sales
|
|
1,706
|
|
|
159
|
|
|
1,865
|
|
|
Coal purchases
|
|
747
|
|
|
—
|
|
|
747
|
|
The Company may also enter into natural gas options to protect the Company from decreases in natural gas prices, which could impact thermal coal demand. These options are not designated as hedges. Additionally, the Company may enter into nominal quantities of foreign currency options protecting for decreases in the Australian to United States dollar exchange rate, which could impact metallurgical coal demand. These options are not designated as hedges.
Coal 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 is exposed 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 are expected 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 in a 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 consolidated balance sheets. The amounts shown in the table below represent the fair value position of individual contracts, and not the net position presented in the accompanying 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 Hedging Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal
|
|
$
|
942
|
|
|
$
|
(2,146
|
)
|
|
|
|
|
$
|
—
|
|
|
$
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives Not Designated as Hedging Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating oil -- diesel purchases
|
|
5,354
|
|
|
—
|
|
|
|
|
|
4,646
|
|
|
—
|
|
|
|
|
|
Coal held for trading purposes, exchange traded 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 the balance sheets
|
|
$
|
5,508
|
|
|
$
|
(7,217
|
)
|
|
$
|
(1,709
|
)
|
|
$
|
4,908
|
|
|
$
|
(101
|
)
|
|
$
|
4,807
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
|
Net derivatives as reflected on the balance sheets
|
|
|
|
|
|
|
|
|
|
Heating oil
|
|
Other current assets
|
|
$
|
5,354
|
|
|
$
|
4,646
|
|
|
Coal
|
|
Other current assets
|
|
154
|
|
|
262
|
|
|
|
|
Accrued expenses and other 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 accompanying consolidated balance sheets.
The 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)
|
|
|
|
Successor
|
Predecessor
|
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Coal sales
|
(1)
|
$
|
(2,127
|
)
|
|
$
|
—
|
|
$
|
(672
|
)
|
|
12,816
|
|
|
Coal purchases
|
(2)
|
942
|
|
|
—
|
|
536
|
|
|
(6,718
|
)
|
|
|
|
$
|
(1,185
|
)
|
|
$
|
—
|
|
$
|
(136
|
)
|
|
$
|
6,098
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (Losses) Reclassified from Other Comprehensive Income into Income
(Effective Portion)
|
|
|
|
Successor
|
Predecessor
|
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Coal sales
|
|
$
|
—
|
|
|
$
|
—
|
|
$
|
1,634
|
|
|
$
|
18,635
|
|
|
Coal 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 the results of operations in the respective periods.
Derivatives Not Designated as Hedging Instruments (in thousands)
For the noted periods,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Recognized
|
|
|
|
Successor
|
Predecessor
|
|
|
|
Year Ended December 31, 2017
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Coal — unrealized
|
(3)
|
$
|
(4,648
|
)
|
$
|
(408
|
)
|
$
|
(1,662
|
)
|
|
$
|
(3,883
|
)
|
|
Coal — realized
|
(4)
|
$
|
—
|
|
$
|
116
|
|
$
|
(476
|
)
|
|
$
|
3,236
|
|
|
Heating oil — diesel purchases
|
(4)
|
$
|
(1,057
|
)
|
$
|
827
|
|
$
|
826
|
|
|
$
|
(8,294
|
)
|
|
Natural gas
|
|
$
|
(774
|
)
|
$
|
(91
|
)
|
$
|
(463
|
)
|
|
$
|
878
|
|
|
Foreign currency
|
|
$
|
—
|
|
$
|
(9
|
)
|
$
|
(451
|
)
|
|
$
|
(867
|
)
|
Location 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 period
October 2 through December 31, 2016
; net unrealized and realized
losses
of
$0.9 million
for the period
January 1 through October 1, 2016
; and net unrealized and realized
gains
of
$5.7 million
during the year ended
December 31, 2015
, respectively, related to its trading portfolio, which are included in the caption “Change in fair value of coal derivatives and coal trading activities, net” in the accompanying consolidated statements of operations, and are not included 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 be reclassified from other comprehensive income into earnings during the next twelve months are losses of
$1.2 million
.
13.
Accrued Expenses and Other Current Liabilities
Accrued expenses and other current liabilities consist of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
|
(In thousands)
|
|
|
|
|
|
Payroll and employee benefits
|
|
$
|
53,149
|
|
|
$
|
58,468
|
|
|
Taxes other than income taxes
|
|
77,017
|
|
|
92,733
|
|
|
Interest
|
|
246
|
|
|
8,032
|
|
|
Sales contracts
|
|
934
|
|
|
5,114
|
|
|
Workers’ compensation
|
|
18,782
|
|
|
15,184
|
|
|
Asset retirement obligations
|
|
19,840
|
|
|
19,515
|
|
|
Other
|
|
14,193
|
|
|
6,194
|
|
|
|
|
$
|
184,161
|
|
|
$
|
205,240
|
|
14.
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)
|
|
$
|
—
|
|
|
$
|
325,684
|
|
|
Other
|
|
36,514
|
|
|
37,195
|
|
|
Debt issuance costs
|
|
(7,032
|
)
|
|
—
|
|
|
|
|
325,917
|
|
|
362,879
|
|
|
Less current maturities of debt
|
|
15,783
|
|
|
11,038
|
|
|
Long-term debt
|
|
$
|
310,134
|
|
|
$
|
351,841
|
|
Term Loan Facility
On 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 at
99.50%
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, among Arch Coal as borrower, the lenders from time to time party thereto, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent.
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 also resets 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 interbank offered 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 term loans 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 interests on substantially all assets of the Loan Parties, including
100%
of the voting equity interests of directly owned domestic subsidiaries and
65%
of the voting equity 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 made with 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 or dispositions, subject to customary thresholds, exceptions and reinvestment rights.
The New Term Loan Debt Facility contains customary affirmative covenants and representations.
The New Term Loan Debt Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) indebtedness, (ii) liens, (iii) liquidations, mergers, consolidations and acquisitions, (iv) disposition of assets or subsidiaries, (v) affiliate transactions, (vi) creation or ownership of certain subsidiaries, partnerships and joint ventures, (vii) continuation of or change in business, (viii) restricted payments, (ix) prepayment of subordinated and junior lien indebtedness, (x) restrictions in agreements on dividends, intercompany loans and granting liens on 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 to comply with any covenant, subject to customary grace periods in the case of certain affirmative covenants, (iv) cross-events of default to indebtedness of at least
$50 million
, (v) cross-events of default to surety, reclamation or similar bonds securing obligations with an aggregate face amount of at least
$50 million
, (vi) uninsured judgments in excess of
$50 million
, (vii) any loan document shall cease to be a legal, valid and binding agreement, (viii) uninsured losses 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 insolvency proceedings 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 credit agreement, dated as of October 5, 2016, among the Company, as borrower, the lender party thereto and Wilmington Trust, National Association, as administrative agent and collateral agent (the “Previous First Lien Debt Facility”), other than indemnification and other contingent obligations, were paid in cash in full and the related transaction documents were terminated (other than with respect to certain provisions that customarily survive termination); there was
no
gain or loss recognized on the extinguishment of the previously existing term loan credit agreement. All liens on property of the Company and the guarantors thereunder arising out of or related to the Previous First Lien Debt Facility were terminated.
Accounts Receivable Securitization Facility
On April 27, 2017, the Company extended and amended its existing trade accounts receivable securitization facility provided to Arch Receivable Company, 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 the borrowing capacity from
$200 million
to
$160 million
and extends the maturity date to the date that is three years after the Securitization Facility Closing Date. Pursuant to the Extended Securitization Facility, Arch Receivable also agreed to a revised schedule of fees payable to the administrator and the providers 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 60 consecutive days, the date that is the 364th day after the first day of such 60 consecutive day period and (iii) the occurrence of certain predefined events substantially consistent with the existing transaction documents. Under the Extended Securitization Facility, Arch Receivable, the Company and certain of its subsidiaries party to the Extended Securitization Facility have granted to the administrator of the Extended Securitization Facility a first priority security interest in eligible trade accounts receivable generated by such parties from the sale of coal and all proceeds thereof. As of
December 31, 2017
, letters of credit totaling
$85.0 million
were outstanding under the facility with no additional availability for borrowings.
Inventory-Based Revolving Credit Facility
On April 27, 2017, the Company and certain subsidiaries of Arch Coal entered into a new 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 and swingline lender (in such capacities, the “ Lender ”) and as letter of credit issuer. Availability under the New Inventory 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%
of Arch Coal’s Eligible Cash (defined in the New Inventory Facility), 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 Inventory Facility 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 with the 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, if any, 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 base rate 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 the case 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 to the 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-borrowers under or guarantors of the New Inventory Facility (collectively with the Company, the “Loan Parties”). The New Inventory Facility is secured by first priority security interests in the ABL Priority Collateral (defined in the New Inventory Facility) of the Loan Parties and second priority security interests in substantially all other assets of the Loan Parties, subject to customary exceptions (including an exception for the collateral that secures the Extended Securitization 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 without premium 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 the applicable 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 or dispositions, subject to customary thresholds, exceptions (including exceptions for required prepayments under the Company’s term loan facility) and reinvestment rights.
The New Inventory Facility contains certain customary affirmative and negative covenants; events of default, subject to customary thresholds and exceptions; and representations, including certain cash management and reporting requirements that are customary for asset-based credit facilities. The New Inventory Facility also includes a requirement to maintain Liquidity equal to or exceeding
$175 million
at all times. As of
December 31, 2017
, letters of credit totaling
$29.0 million
were outstanding under the facility with
$1.1 million
additional availability for borrowings.
Interest Rate Swaps
During 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 the term 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 are recorded 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 of accumulated other comprehensive income and the ineffective portion reported in earnings. As interest payments are made on the term loan, amounts in accumulated other comprehensive income will be reclassified into earnings through interest expense to reflect a net interest on the term loan equal to the effective 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 is terminated prior to maturity, gains or losses in accumulated other comprehensive income will remain deferred and reclassified into earnings in the periods which the hedged forecasted transaction affects earnings.
Below is a summary of the Company’s outstanding interest rate swap agreements designated as hedges as of
December 31, 2017
:
|
|
|
|
|
|
|
|
|
Notional Amount (in millions)
|
Effective Date
|
Fixed Rate
|
Receive Rate
|
Expiration Date
|
|
|
|
|
|
|
|
$250.0
|
June 30, 2017
|
1.372%
|
1-month LIBOR
|
June 29, 2018
|
|
$250.0
|
June 29, 2018
|
1.662%
|
1-month LIBOR
|
June 28, 2019
|
|
$200.0
|
June 28, 2019
|
1.952%
|
1-month LIBOR
|
June 30, 2020
|
|
$150.0
|
June 30, 2020
|
2.182%
|
1-month LIBOR
|
June 30, 2021
|
The 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 offset to accumulated other comprehensive income on the Company’s Consolidated Balance Sheet. The Company realized
$0.1 million
of
losses
during the year ended
December 31, 2017
related to settlements of the interest rate swaps which was recorded to interest expense on the Company’s Consolidated Statement of Operations. The interest rate swaps are classified as level 2 within the fair value hierarchy.
Debt Maturities
The contractual maturities of debt as of
December 31, 2017
are as follows:
|
|
|
|
|
|
|
|
|
Year
|
|
(In thousands)
|
|
2018
|
|
$
|
16,809
|
|
|
2019
|
|
11,119
|
|
|
2020
|
|
11,442
|
|
|
2021
|
|
8,853
|
|
|
2022
|
|
3,130
|
|
|
Thereafter
|
|
282,911
|
|
|
|
|
$
|
334,264
|
|
Financing Costs
The 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 conjunction with 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 the period ended
December 31, 2017
and
January 1 through October 1, 2016
, respectively. Additionally, the Company incurred
$24.2 million
of legal fees and financial advisory fees associated with debt restructuring activities during 2015. During the year ended
December 31, 2015
the Company wrote off
$3.7 million
of deferred financing costs related to the termination of the revolver facility. All amounts have been reflected in the line, “
Net loss resulting from early retirement and refinancing of debt
” in the Consolidated Statement of Operations.
15.
Taxes
In 2016, under the Plan of bankruptcy reorganization, the Company’s pre-petition equity, bank related debt and certain other obligations were cancelled and extinguished. Absent an exception, a debtor recognizes cancellation of debt income (CODI) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. In accordance with Internal Revenue Code (IRC) Section 108, the Company excluded the amount of discharged indebtedness from taxable income since the IRC provides that a debtor in a bankruptcy case may exclude CODI from income but must reduce certain tax attributes by the amount of CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less than the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued, and (iii) the fair market 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 gross federal 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 purposes of 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 capital loss carryforwards generated before the ownership change against future taxable income. The Company’s annual limit under IRC section 382 is estimated to be
$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 the ownership change, therefore, certain built-in gains recognized within five years after the ownership change will increase the annual IRC section 382 limit for the five year recognition period beginning October 1, 2016 through September 30, 2021. There is uncertainty surrounding which assets with built-in gain will be realized within the five year period following the Company’s emergence from bankruptcy and allow the Company to realize the incremental net operating 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 losses and 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 to examination 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
(In thousands)
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
Federal
|
$
|
835
|
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
—
|
|
|
State
|
31
|
|
|
(252
|
)
|
7
|
|
|
3
|
|
|
Total current
|
866
|
|
|
(252
|
)
|
7
|
|
|
3
|
|
|
Deferred:
|
|
|
|
|
|
|
|
Federal
|
(36,162
|
)
|
|
1,352
|
|
(4,720
|
)
|
|
(329,393
|
)
|
|
State
|
41
|
|
|
56
|
|
87
|
|
|
(43,990
|
)
|
|
Total deferred
|
(36,121
|
)
|
|
1,408
|
|
(4,633
|
)
|
|
(373,383
|
)
|
|
|
$
|
(35,255
|
)
|
|
$
|
1,156
|
|
$
|
(4,626
|
)
|
|
$
|
(373,380
|
)
|
A reconciliation of the statutory federal income tax provision (benefit) at the statutory rate to the actual provision for (benefit from) income taxes follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 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 taxes
|
7,002
|
|
|
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
|
|
|
865,146
|
|
|
Impact of Tax Cuts and Jobs Act of 2017
|
332,345
|
|
|
—
|
|
—
|
|
|
—
|
|
|
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 the financial 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
|
|
|
$
|
376,293
|
|
|
Tax credit carryforwards
|
29,736
|
|
|
22,798
|
|
|
Investment in tax partnerships & corporations
|
308,653
|
|
|
604,914
|
|
|
Other
|
28,321
|
|
|
39,251
|
|
|
Gross deferred tax assets
|
638,115
|
|
|
1,043,256
|
|
|
Valuation allowance
|
(610,571
|
)
|
|
(1,021,553
|
)
|
|
Total deferred tax assets
|
27,544
|
|
|
21,703
|
|
|
Deferred tax liabilities:
|
|
|
|
|
Plant and equipment
|
3,674
|
|
|
7,332
|
|
|
Other
|
1,351
|
|
|
14,258
|
|
|
Total deferred tax liabilities
|
5,025
|
|
|
21,590
|
|
|
Net deferred tax asset
|
22,519
|
|
|
113
|
|
The Company has gross federal net operating loss carryforwards for regular income tax purposes of
$980.2 million
at
December 31, 2017
that will expire between
2022
and
2037
. The Company has an alternative minimum tax credit carryforward of
$23.9 million
at
December 31, 2017
, which has no expiration date 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 limited under 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 mining operations 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 in ASC 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 other net taxable temporary differences before the expiration of the attribute.
At December 31, 2015, additional losses were realized relating primarily to financial conditions and asset impairment charges. As a result, the expected reversal of taxable temporary differences were not sufficient to support the future realization of the deferred tax assets and an additional
$865.1 million
valuation 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 the Predecessor entity. As a result, the expected reversal of taxable temporary differences were not sufficient to support the future realization of the deferred tax assets and an additional
$1,185 million
valuation allowance was recorded to the provision. Offsetting this increase was a net reduction in the valuation allowance 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 the IRC 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, the elimination of the corporate alternative minimum tax regime effective for tax years beginning after December 31, 2017, implementation of a process whereby corporations with unused alternative minimum tax credits will be refunded during 2018-2022, the transition of U.S. international taxation from a worldwide tax 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, and limitations 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 Company anticipates 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 to reverse in the future was
$330.9 million
of income tax expense, with an offsetting valuation allowance adjustment. Finalization of the remeasurement 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 expense related to the mandatory deemed repatriation of foreign earnings was
$1.5 million
based on cumulative foreign earnings of
$4.2 million
. The deemed repatriation tax is completely offset with net operating loss carryforwards, with an offsetting valuation allowance adjustment and will not result in a cash tax liability. Finalization of 2017 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 may be subject to a sequestration reduction rate of approximately
6.6%
. The Company has provisionally determined that it will receive a refund of existing AMT credits of approximately
$22.4 million
after an estimated sequestration reduction of
$1.5 million
. The valuation allowance previously recorded against these credits has been released and a tax benefit of
$22.4 million
was recorded. The Company’s accounting policy regarding the balance 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 of the credit, at which time the amount will be presented as a tax receivable.
|
Finalization of the AMT credit balance will occur upon finalization of 2017 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 and expanded the number of employees to which the limit applies. The Company recorded a provisional amount of
$0.2 million
of tax expense, with an offsetting valuation allowance adjustment. The Act contains transitional rules, the implementation of which is uncertain at this time. The Company is still analyzing related aspects of the Act including the impact of the transitional rules. The provisional amount detailed above may change when further 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 intangible low-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 percentage depletion. A
$35.7 million
benefit was recorded from the release of valuation allowance offsetting alternative minimum tax credits that have become refundable 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 previously paid alternative minimum taxes. At December 31, 2017 a
$610.5 million
valuation allowance fully offsets all net deferred tax assets, other than alternative minimum tax credits.
A reconciliation of the beginning and ending amounts of gross unrecognized tax benefits follows:
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Balance at
|
January 1, 2015
|
$
|
34,709
|
|
|
Additions based on tax positions related to the current year
|
4,168
|
|
|
Balance at
|
December 31, 2015
|
38,877
|
|
|
Additions based on tax positions related to the current year
|
2,979
|
|
|
Additions for tax positions of prior years
|
2,709
|
|
|
Reductions as a result of lapses in the statute of limitations
|
(37,110
|
)
|
|
Balance at
|
December 31, 2016
|
7,455
|
|
|
Additions for tax positions of prior years
|
—
|
|
|
Additions for tax positions related to the current year
|
3,928
|
|
|
Reductions as a result of bankruptcy
|
—
|
|
|
Balance at
|
December 31, 2017
|
$
|
11,383
|
|
If 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 to bankruptcy. As a result, the Company has released
$37.1 million
of gross unrecognized tax benefits for years 2015 and prior. These gross unrecognized tax benefits 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 and penalties 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 benefits are expected to be reduced due to the expiration of the statute of limitations.
16.
Asset Retirement Obligations
The Company’s asset retirement obligations arise from the Federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The required reclamation activities to be performed are outlined in the Company’s mining permits. These activities include reclaiming the pit and support acreage at surface mines, sealing portals at underground mines, reclaiming refuse areas and slurry ponds and water treatment.
The following table describes the changes to the Company’s asset retirement obligation liability:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
(In thousands)
|
|
|
|
|
|
Balance at beginning of period (including current portion)
|
$
|
356,742
|
|
|
$
|
354,326
|
|
$
|
410,454
|
|
|
Accretion expense
|
30,209
|
|
|
7,634
|
|
24,321
|
|
|
Obligations of divested operations
|
(12,569
|
)
|
|
—
|
|
(14,702
|
)
|
|
Adjustments to the liability from changes in estimates
|
(23,215
|
)
|
|
—
|
|
3,003
|
|
|
Liabilities settled
|
(22,472
|
)
|
|
(5,218
|
)
|
(11,087
|
)
|
|
Fresh start accounting adjustment
|
—
|
|
|
—
|
|
(57,663
|
)
|
|
Balance at period end
|
$
|
328,695
|
|
|
$
|
356,742
|
|
$
|
354,326
|
|
|
Current portion included in accrued expenses
|
(19,840
|
)
|
|
(19,515
|
)
|
(17,290
|
)
|
|
Noncurrent liability
|
$
|
308,855
|
|
|
$
|
337,227
|
|
$
|
337,036
|
|
As of
December 31, 2017
, the Company had
$531.7 million
in surety bonds outstanding and
$7.4 million
in letters of credit to secure reclamation bonding obligations. Additionally, the Company has posted
$2.6 million
in cash as collateral related to reclamation surety bonds; this amount is recorded within “Noncurrent assets” on the Consolidated Balance Sheet.
17.
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. The levels of the hierarchy, as defined below, give the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest 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 equity securities, 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 market data for substantially the full term of the assets or liabilities. The Company’s level 2 assets and liabilities include U.S. government agency securities, coal commodity contracts and interest rate swaps with fair values derived from quoted prices in over-the-counter markets or from prices received from direct broker quotes.
·
Level 3 is defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. These include the Company’s commodity option contracts (coal and heating oil) valued using modeling techniques, such as Black-Scholes, that require the use of inputs, particularly volatility, that are rarely observable. Changes in the unobservable inputs would not have had a significant impact on the reported Level 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 consolidated balance 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
|
|
|
5,354
|
|
|
Total assets
|
|
$
|
163,185
|
|
|
$
|
64,100
|
|
|
$
|
93,731
|
|
|
$
|
5,354
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
—
|
|
|
4,646
|
|
|
Total assets
|
|
$
|
95,117
|
|
|
$
|
2,399
|
|
|
$
|
88,072
|
|
|
$
|
4,646
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
$
|
101
|
|
|
$
|
(8
|
)
|
|
$
|
—
|
|
|
$
|
109
|
|
The Company’s contracts with its counterparties allow for the settlement of contracts in an asset position with contracts in a liability position in the event of default or termination. For classification purposes, the Company records the net fair value of all the positions with these counterparties as a net asset or liability. 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.
The following table summarizes the change in the fair values of financial instruments categorized as level 3.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
(In thousands)
|
|
|
|
|
|
|
|
Balance, beginning of period
|
|
|
$
|
4,537
|
|
|
$
|
3,842
|
|
$
|
2,432
|
|
|
Realized and unrealized (gains) losses recognized in earnings, net
|
|
|
(2,305
|
)
|
|
926
|
|
(1,686
|
)
|
|
Included in other comprehensive income
|
|
|
—
|
|
|
—
|
|
—
|
|
|
Purchases
|
|
|
4,910
|
|
|
1,225
|
|
5,021
|
|
|
Issuances
|
|
|
(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 on
December 31, 2017
.
Cash and Cash Equivalents
At
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 fall into Level 2 in the fair value hierarchy.
18.
Capital Stock
Dividends
The Company declared and paid cash dividends per share during the periods presented below:
|
|
|
|
|
|
|
|
|
|
|
2017:
|
Dividends per share
|
Amount (in thousands)
|
|
1st quarter
|
$
|
—
|
|
$
|
—
|
|
|
2nd quarter
|
0.35
|
|
8,563
|
|
|
3rd quarter
|
0.35
|
|
8,200
|
|
|
4th quarter
|
0.35
|
|
7,606
|
|
|
Total cash dividends declared and paid
|
$
|
1.05
|
|
$
|
24,369
|
|
Future dividend declarations will be subject to ongoing Board review and authorization will be based on a number of factors, including business and market conditions, the Company’s future financial performance and other capital priorities.
Share Repurchase Program
During 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. In October 2017, the Company’s Board of Directors approved an incremental
$200 million
increase to the share repurchase program bringing the total authorization to
$500 million
. Below is a table showing the share repurchase activity in
2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
Number of Shares
|
Average Repurchase Price per Share
|
Amount (in thousands)
|
|
1st quarter
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|
2nd quarter
|
710,701
|
|
$
|
71.82
|
|
51,043
|
|
|
3rd quarter
|
2,208,133
|
|
$
|
75.49
|
|
166,685
|
|
|
4th quarter
|
1,058,381
|
|
$
|
79.73
|
|
84,381
|
|
|
Total shares repurchased
|
3,977,215
|
|
$
|
75.96
|
|
$
|
302,109
|
|
The timing of any future share repurchases, and the ultimate number of shares purchased, will depend on a number of factors, including business and market conditions, the Company’s future financial performance and other capital priorities. The shares will be acquired in the open market or through private transactions in accordance with the Securities and Exchange Commission requirements. The share repurchase program has no termination date, but may be amended, suspended or discontinued at any time and does not commit the Company to repurchase shares of its common stock. The actual number and value of the shares to be purchased will depend on the performance of the Company’s stock price and other market conditions.
Outstanding Warrants
During
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 of settlement to one share of Company stock subject only to remote contingency adjustment factors designed to assure the relative value in terms of shares remains fixed.
19.
Stock-Based Compensation and Other Incentive Plans
Under the Company’s 2016 Omnibus Incentive Plan (the “Incentive Plan”),
3.0 million
shares of the Company’s common stock were reserved for awards to officers and other selected key management employees of the Company. The Incentive Plan provides the Board of Directors with the flexibility to grant stock options, stock appreciation rights, restricted stock awards, restricted stock units, performance stock or units, phantom stock awards and rights to acquire stock through purchase under a stock purchase program (“Awards”). Awards the Board of Directors elects to pay out in cash do not impact the shares authorized in the Incentive Plan. Shares available for award under the plan were
2.4 million
at
December 31, 2017
.
Restricted Stock Unit Awards
The Company may issue restricted stock and restricted stock units, which require no payment from the employee. Restricted stock cliff-vests at various dates 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 fair value on the grant date and is recorded ratably over the vesting period utilizing the straight-line recognition method. The employee receives cash compensation 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
year period 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 price at the date of grant. The performance awards grant date fair value was determined using a Black-Scholes Monte Carlo simulation. A volatility of
50%
and
60%
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time Based Awards
|
|
Performance Based Awards
|
|
|
Restricted Stock Units
|
Weighted Average Grant-Date Fair Value
|
|
Restricted Stock Units
|
Weighted Average Grant-Date Fair Value
|
|
(Shares in thousands)
|
|
|
|
|
|
|
Outstanding at January 1, 2017
|
159
|
|
$
|
78.60
|
|
|
225
|
|
$
|
67.34
|
|
|
Granted
|
92
|
|
81.91
|
|
|
86
|
|
101.38
|
|
|
Forfeited/Canceled
|
(2
|
)
|
78.60
|
|
|
—
|
|
—
|
|
|
Vested
|
(9
|
)
|
78.60
|
|
|
—
|
|
—
|
|
|
Unvested outstanding at December 31, 2017
|
240
|
|
$
|
79.87
|
|
|
311
|
|
$
|
76.75
|
|
The 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 period October 2, 2016 through December 31, 2016. As of
December 31, 2017
, there was
$32.4 million
of unrecognized share-based compensation expense which is expected to be recognized over a weighted-average period of approximately
three
years.
Long-Term Incentive Compensation
The Company has a long-term incentive program that allows for the award of performance units. The total number of units earned by a participant is based on financial and operational performance measures, and may be paid out in cash or in shares of the Company’s common stock. The Company recognizes compensation expense over the
three
year term of the grant. The liabilities are remeasured quarterly. The Company recognized expense of
$0.7 million
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 1 through October 1, 2016
and
$7.9 million
for the year ended
December 31, 2015
, respectively. The expense is included primarily in “Selling, general and administrative 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.
20.
Workers’ Compensation Expense
The Company is liable under the Federal Mine Safety and Health Act of 1969, as subsequently amended, to provide for pneumoconiosis (occupational disease) 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 occupational disease 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, loss development factors and discounted based on a risk free rate of
2.43%
. Traumatic workers’ compensation claims are insured with varying retentions/deductibles, or through state-sponsored workers’ compensation programs.
Workers’ compensation expense consists of the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Self-insured occupational disease benefits:
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
6,320
|
|
|
$
|
1,583
|
|
$
|
3,465
|
|
|
$
|
4,282
|
|
|
Interest cost
|
|
4,651
|
|
|
1,126
|
|
3,184
|
|
|
3,944
|
|
|
Net amortization
|
|
—
|
|
|
—
|
|
4,325
|
|
|
6,973
|
|
|
Total occupational disease
|
|
$
|
10,971
|
|
|
$
|
2,709
|
|
$
|
10,974
|
|
|
$
|
15,199
|
|
|
Traumatic injury claims and assessments
|
|
3,208
|
|
|
3,162
|
|
6,628
|
|
|
16,781
|
|
|
Total workers’ compensation expense
|
|
$
|
14,179
|
|
|
$
|
5,871
|
|
$
|
17,602
|
|
|
$
|
31,980
|
|
The table below reconciles changes in the occupational disease liability for the respective period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
(In thousands)
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Beginning of period
|
$
|
111,159
|
|
|
$
|
119,710
|
|
$
|
90,836
|
|
|
Service cost
|
6,320
|
|
|
1,583
|
|
3,465
|
|
|
Interest cost
|
4,651
|
|
|
1,126
|
|
3,184
|
|
|
Curtailments
|
(5,433
|
)
|
|
—
|
|
4,156
|
|
|
Actuarial (gain) loss
|
12,242
|
|
|
(9,675
|
)
|
—
|
|
|
Benefit and administrative payments
|
(6,513
|
)
|
|
(1,585
|
)
|
(3,728
|
)
|
|
Fresh start accounting adjustment
|
—
|
|
|
—
|
|
21,797
|
|
|
|
$
|
122,426
|
|
|
$
|
111,159
|
|
$
|
119,710
|
|
The following table provides the assumptions used to determine the projected occupational disease obligation:
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
(Percentages)
|
|
|
|
|
|
Occupational Disease Benefit
|
|
|
|
|
|
Discount rate
|
3.66
|
|
4.31
|
3.80
|
|
Cost escalation rate
|
N/A
|
|
N/A
|
N/A
|
Summarized below is information about the amounts recognized in the accompanying consolidated balance sheets for workers’ compensation benefits:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2017
|
|
Year Ended December 31, 2016
|
|
(In thousands)
|
|
|
|
|
Occupational disease costs
|
$
|
122,426
|
|
|
$
|
111,159
|
|
|
Traumatic and other workers’ compensation claims
|
81,191
|
|
|
88,593
|
|
|
Total obligations
|
203,617
|
|
|
199,752
|
|
|
Less amount included in accrued expenses
|
18,782
|
|
|
15,184
|
|
|
Noncurrent obligations
|
$
|
184,835
|
|
|
$
|
184,568
|
|
As of
December 31, 2017
, the Company had
$123.0 million
in surety bonds and letters of credit outstanding to secure workers’ compensation obligations.
The Company’s recorded liabilities include
$20.3 million
of obligations that are reimbursable under various insurance policies purchased by the company. 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 Plans
The 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 statutory funding 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 employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The Company offers a subsidy to eligible retirees based on age and years of service at retirement and contain other cost-sharing features such as deductibles and coinsurance. 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.
Obligations 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
|
|
|
Successor
|
Predecessor
|
|
Successor
|
Predecessor
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
CHANGE IN BENEFIT OBLIGATIONS
|
|
|
|
|
|
|
|
|
|
|
Benefit obligations at beginning of period
|
$
|
313,629
|
|
|
$
|
341,427
|
|
$
|
301,292
|
|
|
$
|
111,867
|
|
|
$
|
120,311
|
|
$
|
103,460
|
|
|
Service cost
|
—
|
|
|
—
|
|
—
|
|
|
671
|
|
|
180
|
|
393
|
|
|
Interest cost
|
11,169
|
|
|
2,768
|
|
9,338
|
|
|
4,150
|
|
|
978
|
|
3,223
|
|
|
Divestitures (see Note 5 to the Consolidated Financial Statements)
|
(29,097
|
)
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
—
|
|
|
Settlements
|
(1,532
|
)
|
|
(135
|
)
|
—
|
|
|
—
|
|
|
—
|
|
—
|
|
|
Curtailments
|
—
|
|
|
—
|
|
454
|
|
|
(520
|
)
|
|
—
|
|
714
|
|
|
Benefits paid
|
(38,197
|
)
|
|
(11,009
|
)
|
(8,699
|
)
|
|
(8,152
|
)
|
|
(1,962
|
)
|
(8,273
|
)
|
|
Other-primarily actuarial (gain) loss
|
14,126
|
|
|
(19,422
|
)
|
—
|
|
|
2,503
|
|
|
(7,640
|
)
|
—
|
|
|
Fresh start accounting adjustments
|
—
|
|
|
—
|
|
39,042
|
|
|
—
|
|
|
—
|
|
$
|
20,794
|
|
|
Benefit obligations at end of period
|
$
|
270,098
|
|
|
$
|
313,629
|
|
$
|
341,427
|
|
|
$
|
110,519
|
|
|
$
|
111,867
|
|
$
|
120,311
|
|
|
CHANGE IN PLAN ASSETS
|
|
|
|
|
|
|
|
|
|
|
Value of plan assets at beginning of period
|
$
|
274,225
|
|
|
$
|
292,726
|
|
$
|
273,499
|
|
|
$
|
—
|
|
|
$
|
—
|
|
$
|
—
|
|
|
Actual return on plan assets
|
39,689
|
|
|
(7,899
|
)
|
27,811
|
|
|
|
|
—
|
|
—
|
|
|
Employer contributions
|
429
|
|
|
407
|
|
115
|
|
|
8,152
|
|
|
1,962
|
|
8,273
|
|
|
Benefits 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 COMPONENT OF NET PERIODIC BENEFIT COST
|
|
|
|
|
|
|
|
|
|
|
Prior service credit (cost)
|
$
|
—
|
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
$
|
—
|
|
|
Accumulated gain
|
16,178
|
|
|
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 Benefits
The 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 no amortization recorded into net periodic benefit cost during
2018
.
Other Postretirement Benefits
Due to the Company adopting the corridor method of amortizing actuarial gains (losses) during fresh start accounting, it is anticipated there will be no amortization recorded into net periodic benefit cost during
2018
.
Components of Net Periodic Benefit Cost
. The following table details the components of pension and postretirement benefit costs (credits):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
|
Successor
|
Predecessor
|
|
Successor
|
Predecessor
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
$
|
—
|
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
9
|
|
|
$
|
671
|
|
|
$
|
180
|
|
$
|
393
|
|
|
$
|
866
|
|
|
Interest cost
|
11,169
|
|
|
2,768
|
|
9,338
|
|
|
14,604
|
|
|
4,150
|
|
|
978
|
|
3,223
|
|
|
1,904
|
|
|
Curtailments
|
—
|
|
|
—
|
|
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 service credits
|
—
|
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(7,854
|
)
|
|
(8,335
|
)
|
|
Amortization of other actuarial losses (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 service attribution 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 benefit obligations for the respective periods.
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
(Percentages)
|
|
|
|
|
|
Pension Benefits
|
|
|
|
|
|
Discount rate
|
3.49/3.27
|
|
3.95
|
3.39
|
|
Rate of compensation increase
|
N/A
|
|
N/A
|
N/A
|
|
|
|
|
|
|
|
Other Postretirement Benefits
|
|
|
|
|
|
Discount rate
|
3.49
|
|
3.93
|
3.37
|
|
Rate of compensation increase
|
N/A
|
|
N/A
|
N/A
|
The following table provides the weighted average assumptions used to determine net periodic benefit cost for the respective periods.
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
(Percentages)
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
|
|
|
|
|
Discount rate
|
3.77
|
|
3.39/3.95
|
4.59/3.80
|
|
4.15/4.61/4.41/4.60
|
|
Rate of compensation increase
|
N/A
|
|
N/A
|
N/A
|
|
N/A
|
|
Expected return on plan assets
|
6.20
|
|
6.85
|
6.85
|
|
7.00
|
|
|
|
|
|
|
|
|
|
Other Postretirement Benefits
|
|
|
|
|
|
|
|
Discount rate
|
3.85
|
|
3.37
|
4.57/3.80
|
|
3.91
|
|
Rate of compensation increase
|
N/A
|
|
N/A
|
N/A
|
|
N/A
|
|
Expected return on plan assets
|
N/A
|
|
N/A
|
N/A
|
|
N/A
|
The discount rates used in 2017, 2016 and 2015 were reevaluated during the year for settlements and curtailments. The obligations are remeasured at an updated 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 on the underlying mix of invested assets. The Company utilizes modern portfolio theory modeling techniques in the development of its return assumptions. This technique projects rates of return that can be generated through various asset allocations that lie within the risk tolerance set forth by members of the Company’s pension committee (the “Pension Committee”). The risk assessment provides a link between a pension plan’s risk capacity, management’s willingness 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-point increase in the health care cost trend rate would increase the postretirement benefit obligation at
December 31, 2017
by
$11.6 million
and the net periodic postretirement benefit cost for the year ended
December 31, 2017
by
$0.4 million
.
Plan Assets
The Pension Committee is responsible for overseeing the investment of pension plan assets. The Pension Committee is responsible for determining and monitoring appropriate asset allocations and for selecting or replacing investment managers, trustees and custodians. The pension plan’s current investment targets are
39%
equity and
61%
fixed income securities. The Pension Committee reviews the actual asset allocation in light of these targets on a periodic basis and rebalances among investments as necessary. The Pension Committee evaluates the performance of investment managers as compared to the performance of specified benchmarks and peers and monitors the investment managers to ensure adherence to their stated investment style and to the plan’s investment guidelines.
The Company’s pension plan assets at
December 31, 2017
and
2016
, respectively, are categorized below according to the fair value hierarchy as defined in 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-cap
|
22,640
|
|
|
29,687
|
|
|
6,017
|
|
|
9,422
|
|
|
16,623
|
|
|
20,265
|
|
|
—
|
|
|
—
|
|
|
U.S. large-cap
|
43,232
|
|
|
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 mortgage backed 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 government securities
(F)
|
3,829
|
|
|
6,406
|
|
|
—
|
|
|
—
|
|
|
3,829
|
|
|
6,406
|
|
|
—
|
|
|
—
|
|
|
Other investments
(I)
|
27,057
|
|
|
26,151
|
|
|
—
|
|
|
—
|
|
|
8,457
|
|
|
6,910
|
|
|
18,600
|
|
|
19,241
|
|
|
Total
|
$
|
240,028
|
|
|
$
|
252,278
|
|
|
$
|
92,783
|
|
|
$
|
77,022
|
|
|
$
|
128,645
|
|
|
$
|
156,015
|
|
|
$
|
18,600
|
|
|
$
|
19,241
|
|
|
Other 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 are valued using quoted market prices multiplied by the number of shares owned. Investments in mutual funds are valued at the net asset value per share multiplied 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 technique with 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 that includes various valuation techniques and sources such as discounted cash flows models, benchmark yields and securities, reported trades, issuer trades and/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 and are 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 valued utilizing a market approach that includes various valuation techniques and sources such as value generation models, broker quotes, benchmark yields and securities, 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 of shares 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 valued at the net asset value per share multiplied by the number of shares held as of the measurement date.
(I)
Other investments include cash, forward contracts, derivative instruments, credit default swaps, interest rate swaps and mutual funds. Investments in interest rate swaps are valued utilizing a market approach that includes various valuation techniques and sources such as value generation models, broker quotes in active and non-active markets, benchmark yields and securities, reported trades, issuer trades and/or other applicable data. Forward contracts and derivative instruments 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 share multiplied 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 for Progress in the 21st Century Act (MAP-21). MAP-21 does not reduce the Company’s obligations under the plan, but redistributes the timing of required payments 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
|
|
|
$
|
12,381
|
|
|
2019
|
17,834
|
|
|
12,549
|
|
|
2020
|
18,174
|
|
|
12,990
|
|
|
2021
|
18,635
|
|
|
13,239
|
|
|
2022
|
19,235
|
|
|
13,423
|
|
|
Next 5 years
|
83,071
|
|
|
62,854
|
|
|
|
$
|
174,563
|
|
|
$
|
127,436
|
|
Other Plans
The Company sponsors savings plans which were established to assist eligible employees in providing for their future retirement needs. The Company’s expense, 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 through December 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 net income per share is computed using the weighted average number of common shares and the effect of potentially dilutive securities outstanding during the period. Potentially dilutive securities may consist of warrants, restricted stock units or other contingently issuable shares. The dilutive effect of outstanding warrants, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
|
Year Ended December 31, 2017
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
Year Ended December 31, 2015
|
|
(In Thousands)
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
Basic weighted average shares outstanding
|
23,725
|
|
25,002
|
|
21,293
|
|
21,285
|
|
|
Effect of dilutive securities
|
515
|
|
467
|
|
20
|
|
—
|
|
|
|
|
|
|
|
|
Diluted weighted average shares outstanding
|
24,240
|
|
25,469
|
|
21,313
|
|
21,285
|
|
23.
Leases
The Company leases equipment, land and various other properties under non-cancelable long-term leases, expiring at various dates. Certain leases contain 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
|
|
|
$
|
3,582
|
|
|
2019
|
4,655
|
|
|
5,926
|
|
|
2020
|
2,260
|
|
|
6,953
|
|
|
2021
|
1,985
|
|
|
7,216
|
|
|
2022
|
2,024
|
|
|
7,003
|
|
|
Thereafter
|
8,292
|
|
|
34,371
|
|
|
|
$
|
25,152
|
|
|
$
|
65,051
|
|
The 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
,
$5.0 million
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 of the Company’s significant leases are paid on the percentage of gross selling price basis. Royalty expense, including production royalties, was
$167.4 million
in
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
$227.7 million
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 Concentrations
Credit Risk and Major Customers
The Company has a formal written credit policy that establishes procedures to determine creditworthiness and credit limits for trade customers and counterparties in the over-the-counter coal market. Generally, credit is extended based on an evaluation of the customer’s financial condition. Collateral is not 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 steel producers. 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
$99.4 million
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 transactions at 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 the Company. The Company’s foreign revenues by geographical
location are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
(In thousands)
|
|
|
|
|
|
|
|
Europe
|
$
|
388,926
|
|
|
$
|
61,408
|
|
$
|
113,888
|
|
|
$
|
170,314
|
|
|
Asia
|
264,503
|
|
|
55,634
|
|
68,536
|
|
|
96,523
|
|
|
North America
|
88,145
|
|
|
43,831
|
|
56,594
|
|
|
40,315
|
|
|
Central and South America
|
30,982
|
|
|
13,224
|
|
41,861
|
|
|
55,323
|
|
|
Africa
|
14,901
|
|
|
—
|
|
—
|
|
|
—
|
|
|
Brokered Sales
|
6,137
|
|
|
—
|
|
—
|
|
|
32,848
|
|
|
Total
|
$
|
793,594
|
|
|
$
|
174,097
|
|
$
|
280,879
|
|
|
$
|
395,323
|
|
The Company is committed under long-term contracts to supply steam coal that meets certain quality requirements at specified prices. These prices are generally 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 the customer based on their requirements. The Company sold approximately
98.2 million
tons of coal in
2017
. Approximately
66%
of this tonnage (representing approximately
55%
of the Company’s revenues) was sold under long-term contracts (contracts having a term of greater than one year). Long-term contracts range in remaining life from
one
to
four
years.
Third-party sources of coal
The Company purchases coal from third parties that it sells to customers. Factors beyond the Company’s control could affect the availability of coal purchased by the Company. Disruptions in the quantities of coal purchased by the Company could impair its ability to fill customer orders or require it to purchase coal from other sources at prevailing market prices in order to satisfy those orders.
Transportation
The Company depends upon barge, rail, truck and belt transportation systems to deliver coal to its customers. Disruption of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair the Company’s ability to supply coal to its customers In the past, disruptions in rail service have resulted in missed shipments and production interruptions.
25.
Commitments and Contingencies
The Company accrues for cost related to contingencies when a loss is probable and the amount is reasonably determinable. Disclosure of contingencies is 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 already accrued 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 ultimate resolution 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 reserve acquisitions, and is also a party to transportation capacity commitments. The future commitments under these agreements total
$97.2 million
in
2018
, and is immaterial thereafter. The Company recognized expense relating to transportation capacity agreements of
$1.6 million
during the period
January 1 through October 1, 2016
; and
$52.9 million
during the year ended December 31,
2015
, respectively.
26.
Subsequent Events
On 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 of record 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 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 the Company’s marketing and operations management. Mining operations are evaluated based on Adjusted EBITDAR, per-ton cash operating costs (defined as including all mining costs except depreciation, depletion, amortization, accretion on asset retirement obligations, and pass-through transportation expenses), and on other non-financial measures, such as safety and environmental performance. Adjusted EBITDAR is not a measure of financial performance in accordance with generally accepted accounting principles, and items excluded from Adjusted EBITDAR are significant in understanding and assessing our financial condition. Therefore, Adjusted EBITDAR should not be considered in isolation, nor as an alternative to net income, income from operations, cash flows from operations or as a measure of our profitability, liquidity or performance under generally accepted accounting principles. The Company uses Adjusted EBITDAR to measure the operating performance of its segments and allocate resources 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 other companies. The Company reports its results of operations primarily through the following reportable segments: Powder River Basin (PRB) segment containing the Company’s primary thermal operations in Wyoming; the Metallurgical (MET) segment, containing the Company’s metallurgical operations in West Virginia, Kentucky, and Virginia, and the Other Thermal segment containing the Company’s supplementary thermal operations in Colorado, Illinois, and 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 the Company’s metallurgical coal segment. Through this transaction the Company divested all active operations in the states of Kentucky and Virginia. For further 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 periods
January 1 through October 1, 2016
and the year ended December 31,
2015
are presented below. The Company measures its segments based on “adjusted earnings before interest, taxes, depreciation, depletion, amortization, accretion on asset retirements obligations, and reorganization items, net (Adjusted EBITDAR).” Adjusted EBITDAR does not reflect mine closure or impairment costs, since those are not reflected in the operating income reviewed by management. See
Note 6
, “
Impairment Charges and Mine Closure Costs
” for discussion of these costs. The Corporate, Other and Eliminations grouping includes 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
PRB
|
|
MET
|
|
Other Thermal
|
|
Corporate,
Other and
Eliminations
|
|
Consolidated
|
|
Successor Year Ended
|
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
1,024,197
|
|
|
$
|
887,839
|
|
|
$
|
396,504
|
|
|
$
|
16,083
|
|
|
$2,324,623
|
|
Adjusted EBITDAR
|
|
158,882
|
|
|
243,616
|
|
|
102,006
|
|
|
(86,747
|
)
|
|
417,757
|
|
|
Depreciation, depletion and amortization
|
|
36,349
|
|
|
70,896
|
|
|
13,588
|
|
|
1,631
|
|
|
122,464
|
|
|
Accretion on asset retirement obligation
|
|
20,160
|
|
|
2,000
|
|
|
2,161
|
|
|
5,888
|
|
|
30,209
|
|
|
Total Assets
|
|
390,665
|
|
|
548,476
|
|
|
134,397
|
|
|
906,094
|
|
|
1,979,632
|
|
|
Capital expenditures
|
|
6,212
|
|
|
32,678
|
|
|
11,901
|
|
|
8,414
|
|
|
59,205
|
|
|
Successor Period
|
October 2 through December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
275,703
|
|
|
$
|
200,377
|
|
|
$
|
97,382
|
|
|
$
|
2,226
|
|
|
$575,688
|
|
Adjusted EBITDAR
|
|
55,765
|
|
|
30,819
|
|
|
31,159
|
|
|
(23,246
|
)
|
|
94,497
|
|
|
Depreciation, depletion and amortization
|
|
9,949
|
|
|
18,287
|
|
|
3,911
|
|
|
457
|
|
|
32,604
|
|
|
Accretion on asset retirement obligation
|
|
5,049
|
|
|
528
|
|
|
540
|
|
|
1,517
|
|
|
7,634
|
|
|
Total assets
|
|
446,775
|
|
|
576,793
|
|
|
129,602
|
|
|
983,427
|
|
|
2,136,597
|
|
|
Capital expenditures
|
|
934
|
|
|
13,329
|
|
|
684
|
|
|
267
|
|
|
15,214
|
|
|
Predecessor Period
|
January 1 through October 1, 2016
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
726,747
|
|
|
$
|
437,069
|
|
|
$
|
213,052
|
|
|
$
|
21,841
|
|
|
$1,398,709
|
|
Adjusted EBITDAR
|
|
113,185
|
|
|
11,851
|
|
|
31,448
|
|
|
(69,181
|
)
|
|
87,303
|
|
|
Depreciation, depletion and amortization
|
|
100,151
|
|
|
55,311
|
|
|
32,310
|
|
|
3,809
|
|
|
191,581
|
|
|
Accretion on asset retirement obligation
|
|
16,940
|
|
|
1,765
|
|
|
1,988
|
|
|
3,628
|
|
|
24,321
|
|
|
Total assets
|
|
456,711
|
|
|
619,154
|
|
|
131,173
|
|
|
916,791
|
|
|
2,123,829
|
|
|
Capital expenditures
|
|
612
|
|
|
17,296
|
|
|
3,895
|
|
|
60,631
|
|
|
82,434
|
|
|
Predecessor Year Ended
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
$
|
1,448,440
|
|
|
$
|
637,941
|
|
|
$
|
428,809
|
|
|
$
|
58,070
|
|
|
$
|
2,573,260
|
|
|
Adjusted EBITDAR
|
|
281,039
|
|
|
70,450
|
|
|
42,734
|
|
|
(110,426
|
)
|
|
283,797
|
|
|
Depreciation, depletion and amortization
|
|
176,257
|
|
|
133,463
|
|
|
47,786
|
|
|
21,839
|
|
|
379,345
|
|
|
Accretion on asset retirement obligation
|
|
22,156
|
|
|
2,267
|
|
|
2,658
|
|
|
6,599
|
|
|
33,680
|
|
|
Total assets
|
|
1,648,916
|
|
|
772,439
|
|
|
366,610
|
|
|
2,253,916
|
|
|
5,041,881
|
|
|
Capital expenditures
|
|
21,228
|
|
|
24,787
|
|
|
11,277
|
|
|
61,732
|
|
|
119,024
|
|
A reconciliation of segment Adjusted EBITDAR to consolidated income (loss) from continuing operations before income taxes follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
Predecessor
|
|
(In thousands)
|
|
Year Ended December 31, 2017
|
|
October 2 through December 31, 2016
|
January 1 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
$
|
203,195
|
|
|
$
|
34,605
|
|
$
|
1,237,455
|
|
|
$
|
(3,286,522
|
)
|
|
Interest expense, net
|
|
24,256
|
|
|
10,754
|
|
133,235
|
|
|
393,549
|
|
|
Depreciation, depletion and amortization
|
|
122,464
|
|
|
32,604
|
|
191,581
|
|
|
379,345
|
|
|
Accretion on asset retirement obligations
|
|
30,209
|
|
|
7,634
|
|
24,321
|
|
|
33,680
|
|
|
Amortization of sales contracts, net
|
|
53,985
|
|
|
796
|
|
(728
|
)
|
|
(8,811
|
)
|
|
Asset impairment and mine closure costs
|
|
—
|
|
|
—
|
|
129,267
|
|
|
2,628,303
|
|
|
Losses from disposed operations resulting from Patriot Coal bankruptcy
|
|
—
|
|
|
—
|
|
—
|
|
|
116,343
|
|
|
Gain on sale of Lone Mountain Processing, Inc.
|
|
(21,297
|
)
|
|
—
|
|
—
|
|
|
—
|
|
|
Net loss resulting from early retirement of debt and debt restructuring
|
|
2,547
|
|
|
—
|
|
2,213
|
|
|
27,910
|
|
|
Reorganization 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
|
|
|
$
|
283,797
|
|
28.
Quarterly Selected Financial Data
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2017
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
$
|
600,975
|
|
|
$
|
549,866
|
|
|
$
|
613,538
|
|
|
560,244
|
|
|
Gross profit
|
$
|
85,747
|
|
|
$
|
62,577
|
|
|
$
|
65,100
|
|
|
62,937
|
|
|
Income from operations
|
$
|
66,264
|
|
|
$
|
42,692
|
|
|
$
|
72,489
|
|
|
$
|
50,951
|
|
|
Reorganization items, net
|
$
|
(2,828
|
)
|
|
$
|
(21
|
)
|
|
$
|
(43
|
)
|
|
$
|
494
|
|
|
Net income
|
$
|
51,668
|
|
|
$
|
37,160
|
|
|
$
|
68,351
|
|
|
$
|
81,271
|
|
|
Diluted income per common share
|
$
|
2.03
|
|
|
$
|
1.48
|
|
|
$
|
2.83
|
|
|
$
|
3.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
Successor
|
|
Year Ended December 31, 2016
|
March 31
|
|
June 30
|
|
September 30
|
|
October 1
|
October 2 through December 31, 2016
|
|
|
(a) (b)
|
|
(a) (b)
|
|
(b)
|
|
(b)
|
|
|
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
$
|
428,106
|
|
|
$
|
420,298
|
|
|
$
|
550,305
|
|
|
$
|
—
|
|
$
|
575,688
|
|
|
Gross profit (loss)
|
$
|
(53,325
|
)
|
|
$
|
(56,469
|
)
|
|
$
|
31,042
|
|
|
$
|
—
|
|
$
|
64,458
|
|
|
Asset impairment and mine closure costs
|
$
|
85,520
|
|
|
$
|
43,701
|
|
|
$
|
46
|
|
|
$
|
—
|
|
$
|
—
|
|
|
Income (loss) from operations
|
$
|
(158,412
|
)
|
|
$
|
(110,521
|
)
|
|
$
|
11,795
|
|
|
$
|
—
|
|
$
|
46,118
|
|
|
Reorganization items, net
|
$
|
(3,875
|
)
|
|
$
|
(21,271
|
)
|
|
$
|
(20,904
|
)
|
|
$
|
1,676,091
|
|
$
|
(759
|
)
|
|
Net income (loss)
|
$
|
(206,702
|
)
|
|
$
|
(175,887
|
)
|
|
$
|
(51,421
|
)
|
|
$
|
1,676,091
|
|
$
|
33,449
|
|
|
Diluted 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 method subsidiaries and severance expense in 2016. See further discussion in Note
6
, “
Impairment Charges and Mine Closure Costs
“ and Note
10
, “
Equity Method Investments 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
, “
Emergence from Bankruptcy and Fresh Start Accounting
.”