CTRA 10-K Annual Report Dec. 31, 2018 | Alphaminr
ALPHAMINR

CTRA 10-K Fiscal year ended Dec. 31, 2018

Balance Sheet
Cash Flow
Income Statement
Debt
10-K 1 contura12312018financials.htm 10-K Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018

OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from           to

Commission File Number 001-38735
image0a11.jpg
CONTURA ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware
81-3015061
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification Number)
340 Martin Luther King Jr. Blvd.
Bristol, Tennessee 37620
(Address of principal executive offices, zip code)
(423) 573-0300
(Registrant’s telephone number, including area code)

Securities registered or to be registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Stock, par value $0.01 per share
New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
¨ Yes x No

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No



Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Sec.232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes ¨ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer
¨
Accelerated filer
¨
Non-accelerated filer
x
(Do not check if a smaller reporting company)
Smaller reporting company
¨
Emerging growth company
¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

The registrant was not a public company as of the last business day of its most recently completed second fiscal quarter and therefore cannot calculate the aggregate market value of its voting and nonvoting common equity held by nonaffiliates as of such date.

Number of shares of the registrant’s Common Stock, $0.01 par value, outstanding as of March 12, 2019: 19,085,339

DOCUMENTS INCORPORATED BY REFERENCE

Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2018 annual meeting of stockholders (the “Proxy Statement”), which will be filed no later than 120 days after the close of the registrant’s fiscal year ended December 31, 2018.



TABLE OF CONTENTS

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CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements”. These statements, which involve risks and uncertainties, relate to analyses and other information that are based on forecasts of future results and estimates of amounts not yet determinable and may also relate to our future prospects, developments and business strategies. We have used the words “anticipate”, “believe”, “could”, “estimate”, “expect”, “intend”, “may”, “plan”, “predict”, “project”, “should” and similar terms and phrases, including references to assumptions, in this report to identify forward-looking statements. These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those matters expressed in or implied by these forward-looking statements.

The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

•
the financial performance of the company following the Merger with Alpha Natural Resources Holdings, Inc. and ANR, Inc. (the “Merger” or the “Alpha Merger”);
•
our liquidity, results of operations and financial condition;
•
depressed levels or declines in coal prices;
•
worldwide market demand for coal, steel, and electricity, including demand for U.S. coal exports, and competition in coal markets;
•
the imposition or continuation of barriers to trade, such as tariffs;
•
utilities switching to alternative energy sources such as natural gas, renewables and coal from basins where we do not operate;
•
reductions or increases in customer coal inventories and the timing of those changes;
•
our production capabilities and costs;
•
inherent risks of coal mining beyond our control;
•
changes in, interpretations of, or implementations of domestic or international tax or other laws and regulations, including the Tax Cuts and Jobs Act and its related regulations;
•
changes in domestic or international environmental laws and regulations, and court decisions, including those directly affecting our coal mining and production, and those affecting our customers’ coal usage, including potential climate change initiatives;
•
our relationships with, and other conditions affecting, our customers, including the inability to collect payments from our customers if their creditworthiness declines;
•
changes in, renewal or acquisition of, terms of and performance of customers under coal supply arrangements and the refusal by our customers to receive coal under agreed contract terms;
•
our ability to obtain, maintain or renew any necessary permits or rights, and our ability to mine properties due to defects in title on leasehold interests;
•
attracting and retaining key personnel and other employee workforce factors, such as labor relations;
•
funding for and changes in employee benefit obligations;
•
cybersecurity attacks or failures, threats to physical security, extreme weather conditions or other natural disasters;
•
reclamation and mine closure obligations;
•
our assumptions concerning economically recoverable coal reserve estimates;
•
our ability to negotiate new United Mine Workers of America wage agreements on terms acceptable to us, increased unionization of our workforce in the future, and any strikes by our workforce;
•
disruptions in delivery or changes in pricing from third party vendors of key equipment and materials that are necessary for our operations, such as diesel fuel, steel products, explosives, tires and purchased coal;
•
inflationary pressures on supplies and labor and significant or rapid increases in commodity prices;
•
railroad, barge, truck and other transportation availability, performance and costs;
•
disruption in third party coal supplies;
•
the consummation of financing or refinancing transactions, acquisitions or dispositions and the related effects on our business and financial position;
•
our indebtedness and potential future indebtedness;
•
our ability to generate sufficient cash or obtain financing to fund our business operations; and
•
our ability to obtain or renew surety bonds on acceptable terms or maintain our current bonding status.

The factors identified above are not exhaustive. We caution readers not to place undue reliance on any forward-looking statements, which are based only on information currently available to us and speak only as of the dates on which they are made. When considering these forward-looking statements, you should keep in mind the cautionary statements in this report.

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We do not undertake any responsibility to release publicly any revisions to these forward-looking statements to take into account events or circumstances that occur after the date of this report. Additionally, we do not undertake any responsibility to update you on the occurrence of any unanticipated events, which may cause actual results to differ from those expressed or implied by the forward-looking statements contained in this report.

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Part I

Item 1. Business
Unless otherwise indicated or the context otherwise requires, references in this “Business” section to “the combined company,” “we,” “us” and other similar terms refer to Contura Energy, Inc. and its consolidated subsidiaries after giving effect to the Merger.
Our Company
We are a large scale, diversified provider of met and thermal coal to a global customer base. We operate high-quality, cost-competitive coal mines across coal basins in Virginia, West Virginia and Pennsylvania, complemented by a Trading and Logistics business. Our portfolio of mining operations consists of twenty-three underground mines, nine surface mines and twelve coal preparation plants. To supplement mining operations, we operate a Trading and Logistics business that focuses on the sale of third-party coal into the international market. We own a 65.0% interest in the Dominion Terminal Associates (“DTA”), a coal export terminal in eastern Virginia. DTA provides us with the ability to fulfill a broad range of customer coal quality requirements through coal blending, while also providing storage capacity and transportation flexibility.
We produce a diverse mix of coal products, which enables us to satisfy a broad range of customer needs across all our operations. In the Central Appalachia (“CAPP”) coal basin, we predominantly produce low-ash metallurgical (“met”) coal, including High-Vol. A, High-Vol. B, Mid-Vol., and Low-Vol., which are shipped to domestic and international coke and steel producers. In the CAPP coal basin, we also produce low sulfur, high British thermal unit (“BTU”) thermal coal for electricity generation, as well as specialty coal for industrial customers. In the Northern Appalachia (“NAPP”) coal basin, we produce primarily high-BTU thermal coal. This thermal coal has metallurgical properties, but it is higher in sulfur content than typical products sold in the metallurgical coal market. Limited volumes can be placed in the metallurgical coal market where customers have the flexibility to accommodate quantities of higher sulfur coal in their coking coal blends. Our thermal coal is primarily sold to the domestic power generation industry.
We have four reportable segments: CAPP - Met, CAPP - Thermal, NAPP, and Trading and Logistics. See Note 28 for more information about our reportable segments.
We have a substantial reserve base of 885.5 million tons of proven reserves and approximately 462.9 million tons of probable reserves, which we believe could support current production levels for more than 35 years based on our 2018 production levels. Our reserve base in CAPP - Met consists of 438.9 million tons of proven and 207.7 million tons of probable reserves, of which 94% is met coal. Our reserve base in CAPP - Thermal consists of 26.7 million tons of proven and 23.1 million tons of probable reserves, of which 76% is thermal coal. Our reserve base in NAPP consists of 419.9 million tons of proven and 232.1 million tons of probable reserves, of which 93% is thermal coal.
Through our operations and reserves in two major U.S. coal producing basins, we are able to source coal from multiple mines to meet the needs of a long-standing global customer base, many of which have been served by us or our predecessors for over a decade. We are continuously evaluating opportunities to strategically cultivate current relationships to drive new business in our target growth markets that include India and Southeast Asia, among others. In addition, our experienced management team continues to analyze acquisitions, joint ventures and other opportunities that would be accretive and synergistic to its existing asset portfolio.
We have also identified organic met coal growth opportunities that can be developed in supportive pricing environments. Opportunities identified include:
•
Deep Mine #42 in CAPP - Met, which could provide an incremental 1.0-1.5 million tons per year of Mid-Vol. met coal;
•
Freeport mine in NAPP, which could provide an incremental 2.5-3.5 million tons per year of primarily High-Vol. B met coal; and
•
Road Fork 52 in CAPP - Met, which is primarily a reserve replacement mine, but could potentially provide incremental production of Low-Vol. met coal in the near term.

Production at these adjacent mines provides embedded growth potential while leveraging existing infrastructure. In addition, our operational footprint in multiple U.S. coal basins provides significant opportunities for potential synergies from domestic acquisitions.

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Our History
We were formed to acquire and operate certain of Alpha Natural Resources, Inc.’s (“Alpha”) core coal operations, as part of the Alpha Restructuring. We began operations on July 26, 2016 and currently operate mines in the Northern Appalachia and Central Appalachia regions.
On December 8, 2017, we closed a transaction with Blackjewel L.L.C. (“Buyer” or “Blackjewel”) to sell the Eagle Butte and Belle Ayr mines located in the Powder River Basin (“PRB”), Wyoming, along with related coal reserves, equipment, infrastructure and other real properties. The PRB results of operations and financial position are reported as discontinued operations in the Consolidated Financial Statements. The historical information in the accompanying Notes to the Consolidated Financial Statements has been restated to reflect the effects of the PRB operations being reported as discontinued operations in the Consolidated Financial Statements. See Note 4 for further information on discontinued operations.

We merged with Alpha Natural Resources Holdings, Inc. and ANR, Inc. on November 9, 2018. Refer to Note 3 for information on terms of the Merger Agreement. Upon the consummation of the transactions contemplated by a definitive merger agreement (the “Merger Agreement”), our common stock began trading on the New York Stock Exchange under the ticker “CTRA.” Previously, our shares traded on the OTC market under the ticker “CNTE.”

Alpha Restructuring

On August 3, 2015, Alpha Natural Resources, Inc. (“Predecessor Alpha”) and each of its wholly-owned domestic subsidiaries other than ANR Second Receivables Funding LLC (collectively, the “Alpha Debtors”) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Virginia (the “Bankruptcy Court”). The Bankruptcy Court approved the Alpha Debtors’ Plan of Reorganization on July 7, 2016. On July 26, 2016, a consortium of former creditors of the Alpha Debtors acquired Contura common stock in exchange for a partial release of their creditor claims pursuant to the Alpha Debtors’ bankruptcy settlement. The Alpha Debtors, collectively, were a coal producer with operations in Central Appalachia, Northern Appalachia, and the PRB.

Contura entered into various settlement agreements with the Alpha Debtors, their bankruptcy successor, and third parties as part of the Alpha Debtors’ bankruptcy reorganization process. Contura assumed acquisition-related obligations through those settlement agreements, which became effective on July 26, 2016, the effective date of the Alpha Debtors’ Plan of Reorganization. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Contura—Liquidity and Capital Resources—Acquisition-Related Obligations.”

ANR and Holdings were each incorporated in Delaware on June 13, 2016 in accordance with the Plan of Reorganization. On July 26, 2016, the effective date of the Plan of Reorganization, the Alpha Debtors emerged from bankruptcy, and ANR (in which Holdings held an equity investment) became the parent entity under the Plan of Reorganization. On October 23, 2017, Alpha transferred certain idle real properties and related assets located in Kentucky, Tennessee and West Virginia to Lexington Coal Company, LLC, pursuant to the terms of a Membership Interest and Asset Purchase Agreement.

Operations and Properties

The following tables present a summary of our mining operations by reportable segment:
Number & Type of Mines as of December 31, 2018
Segment
Location
Preparation Plants / Shipping Points as of December 31, 2018
Underground
Surface
Total
CAPP - Met
VA, WV
McClure, Toms Creek, Bandmill, Kepler, Kingston, Litwar, Marfork, Power Mountain, Pax, Marmet, Delbarton
20
5
25
CAPP - Thermal
WV
Delbarton, Inman/Homer III, Mammoth, Marmet
2
4
6
NAPP
PA
Cumberland, Labelle
1
—
1

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Segment
Coal Qualities
Transportation
2018 Production of Saleable Tons (in thousands) (1)
CAPP - Met
High-Vol. Met
Truck, CSX Transportation, Norfolk Southern Railway Company, Barge
5,091

CAPP - Thermal
Thermal
Truck, CSX Transportation, Norfolk Southern Railway Company, Barge
596

NAPP
Thermal
Truck, CSX Transportation, Norfolk Southern Railway Company, Barge
6,423

12,110

(1) Includes coal purchased from third-party producers that was processed at our preparation plants in 2018.
We consider Deep Mine 41 and Road Fork 52 in CAPP - Met and Cumberland Mine in NAPP to be individually material mines. Road Fork 52 is primarily a reserve replacement mine, but could potentially provide incremental production of Low-Vol. met coal in the near term.

CAPP - Met

Our CAPP - Met operations consist of high-quality met coal mines, including Deep Mine 41 and Road Fork 52. The coal produced by CAPP - Met operations is predominantly met coal with some amounts of thermal coal being produced as a byproduct of mining. For the fiscal year ended December 31, 2018, our CAPP met coal quality was composed of 39.7% Mid-Vol., 40.9% High-Vol. A, 16.9% High-Vol. B, 2.4% Low-Vol., and 0.1% High-Vol. C. In the year ended December 31, 2017, our CAPP - Met coal quality was composed of 42.9% Mid-Vol., 44.0% High-Vol. A and 13.1% High-Vol. B. During the years ended December 31, 2018 and 2017, we shipped 4.0 million tons and 2.9 million tons, respectively, of our met coal production from our CAPP - Met operations internationally to customers in Europe, Asia and the Americas, with the remaining met coal production sold into the domestic market. See Item 2. Properties, Costs & Calculations, for the two-year historical sales price ranges.
Deep Mine 41, associated with the McClure Prep Plant, is located in Dickenson County, Virginia on property subject to a lease dated April 1, 2003. Contura can automatically extend the lease until March 31, 2063. The McClure Plant is a 1000 ton per hour plant that is located on owned property in Dickenson County, Virginia. It was built in 1979 and upgraded in 1998.

Road Fork #52 Mine is located in Wyoming County, West Virginia on property subject to a lease dated August 25, 1997. After expiration of the initial 10-year term, the lease automatically extended for successive 5-year periods. The current 5-year period expires August 24, 2022 and shall be renewed for another 5-year period unless a 90-day termination notice is provided by the lessee.

The Kepler Plant is a 850 ton per hour plant located in Wyoming County, West Virginia on surface property subject to a lease dated August 25, 1997. After expiration of the initial 10-year term, the lease automatically extended for successive 5-year periods, not to exceed four such renewals. The current 5-year period (the third) expires August 24, 2022 and shall be renewed for another 5-year period (the fourth).

CAPP - Thermal

Our CAPP - Thermal operations consist of surface and underground thermal coal mines. The coal produced by CAPP - Thermal operations is predominantly thermal coal with some met coal byproduct. For the fiscal year ended December 31, 2018, our CAPP - Thermal coal quality was composed of low sulfur, high BTU coal. During the year ended December 31, 2018, we shipped 0.6 million tons of our thermal coal production from our CAPP - Thermal operations domestically to utility and industrial customers.

NAPP

Our NAPP operations consist of the large-scale, high-margin and high-quality Cumberland mine. Cumberland is located in Greene County, Pennsylvania and operates one highly efficient longwall supported by four continuous miner sections for longwall panel development. Our NAPP operations also include the idled Emerald mine complex, which is currently being used as an underground water treatment and holding facility, allowing Cumberland to realize significant cost savings on water management expenditures. We are also able to sell part of our Cumberland coal production (0.7 and 0.2 million tons for the years ended 2018 and 2017, respectively) into the met coal market as High-Vol. B, achieving higher realized pricing than if

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sold as thermal coal. The coal produced by the Cumberland mine is from the Pittsburgh 8 seam, which is recognized for its high-BTU, low chlorine content and desirable ash fusion properties. This makes Cumberland coal ideal for boilers and, accordingly, most of the domestic customer base for this mine consists of base load, scrubbed coal-fired power plants. Additionally, NAPP offers transportation optionality through rail and barge, allowing us to reach a broader customer base. We enter into long-term supply agreements, typically ranging from one to three years, to contract our thermal coal production in advance, thereby reducing the risks associated with our thermal coal portfolio in future years.
The Cumberland Mine is on property owned by our subsidiaries, as well as on property subject to a lease dated December 4, 1980 (the “Greene Manor Lease”). We can extend the Greene Manor Lease for successive ten-year periods. The Cumberland Plant (associated with Cumberland Mine) is a 1600 ton per hour plant located on owned property in Greene County, Pennsylvania. It was built in 1978 and upgraded in 1996.
Trading and Logistics
Our Trading and Logistics business purchases met coal from domestic producers and sells into international markets. Such purchases are predominantly made pursuant to long-term agreements, but we also purchase coal on the spot market when it is advantageous to our business. A strategic cornerstone of our Trading and Logistics business is our interest in the DTA coal export terminal. In March 2017, we increased our stake in the DTA coal export terminal from 40.6% to 65.0%, which provides us with 14 million tons of export capacity. Purchasing coal produced by various CAPP operators allows us to leverage our export capacity at DTA. Our Trading and Logistics platform complements our met coal operations by blending captive and third-party coal at DTA to achieve a broader portfolio of coal qualities. We typically build in margin for transportation fees, overhead, risk and profit when purchasing third-party coal. Additionally, we sell capacity to third-party operators via throughput contracts. The Trading and Logistics business provides us with a larger presence in international markets and further diversifies and expands our revenue sources.
PRB
Our PRB operations formerly consisted of the Belle Ayr and Eagle Butte mines, located in Wyoming. On December 8, 2017, we sold these, along with related coal reserves, equipment, infrastructure and other real properties. See Note 4 for further information on discontinued operations.
Financial Information About Reportable Segments and Geographic Areas
See     Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 8. Financial Statements and Supplementary Data, Note 27 Concentration of Credit Risk and Major Customers, and Note 28 Segment Information for financial information about reportable segments and geographic areas.
Mine Life
The following table provides a summary of mine life for our active mines by segment, as of December 31. 2018:
Segment
Location
Estimated Years
CAPP - Met (1)
Virginia, West Virginia
1 to 23
CAPP - Thermal
West Virginia
9 to 37
NAPP (2)
Pennsylvania
18
(1) Includes Deep Mine 41 with an estimated mine life of 23 years.
(2) Includes Cumberland with an estimated mine life of 18 years. Cumberland mine includes all of the Cumberland Reserve block and a portion of the Greene Manor Reserve block. The remaining portion of the Greene Manor Reserve block and the CNG and Consol Trade Area reserve blocks are located adjacent to the area included in the Cumberland mine life area .

Coal Mining Techniques
We use five different mining techniques to extract coal from the ground: longwall mining, room-and-pillar mining, truck-and-shovel mining, truck and front-end loader mining, contour mining and highwall mining. We do not use mountaintop removal mining and currently have no plans to do so in the future.

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Longwall Mining

At our Cumberland mine, we utilize longwall mining techniques, which are the most productive underground mining methods used in the United States. A rotating drum is trammed mechanically across the face of coal. A hydraulic system supports the roof of the mine while the drum advances through the coal. Chain conveyors then move the loosened coal to a standard underground mine conveyor system for transport to the surface. Continuous miners are used to develop access to long rectangular blocks of coal which are then mined with longwall equipment, allowing controlled subsidence behind the advancing machinery. Longwall mining is highly productive and most effective for large blocks of medium to thick coal seams. High capital costs associated with longwall mining demand large, contiguous reserves. Ultimate seam recovery of in-place reserves using longwall mining is much higher than the room-and-pillar mining underground technique. All of the coal mined at our longwall mines is processed in preparation plants to remove rock and impurities before it becomes saleable clean coal.

Room-and-Pillar Mining

Certain of our mines in CAPP use room-and-pillar mining methods. In this type of mining, main airways and transportation entries are developed and maintained while remote-controlled continuous miners extract coal from the seam, leaving pillars to support the roof. Shuttle cars or battery coal haulers are used to transport coal from the continuous miner to the conveyor belt for transport to the surface. This method is more flexible than longwall mining and often used to mine smaller coal blocks or thinner seams of coal. Ultimate seam recovery of in-place reserves is less than that achieved with longwall mining. All of this production is also processed in preparation plants to remove rock and impurities before it becomes saleable clean coal.

Truck-and-Shovel Mining and Truck and Front-End Loader Mining

We utilize truck/shovel and truck/front-end loader mining methods at some of our CAPP surface mines. These methods are similar and involve using large, electric or hydraulic-powered shovels or diesel-powered front-end loaders to remove earth and rock (overburden) covering a coal seam which is later used to refill the excavated coal pits after the coal is removed. The loading equipment places the coal into trucks for transportation to a preparation plant or loadout area. Ultimate seam recovery of in-place reserves on average exceeds 90%. Depending on geology and market destination, surface-mined coal may need to be processed in a preparation plant before sale. In the case of some metallurgical grade coals, as much as 80% of surface mined coal may need to be processed in a preparation plant to enhance the sales value of the coal. Productivity depends on overburden and coal thickness (strip ratio), equipment utilized and geologic factors.

Contour Mining

We use contour mining in our CAPP mines which limits the overburden removal from above a coal seam or series of coal seams. In contour mining, surface mining machinery follows the contours of a coal seam or seams around a ridge, excavating the overburden and recovering the coal seam or seams as a “contour bench” around the ridge is created. This contour bench is then backfilled and graded in accordance with an approved reclamation plan. Highwall mining methods are used in connection with some Contour Mining operations. Depending on geology and market destination coal mined by contour mining may need to be processed in preparation plants to remove rock and impurities before it becomes a saleable clean coal.

Highwall Mining

We utilize highwall mining methods at our CAPP surface mines. A highwall mining system consists of a remotely controlled continuous miner, which extracts coal and conveys it via augers or belt conveyors to the surface. The cut is typically a rectangular, horizontal opening in the highwall (the unexcavated face of exposed overburden and coal in a surface mine) 9-feet or 11-feet wide and reaching depths of up to 1,000 feet. Multiple parallel openings are driven into the highwall, separated by narrow pillars that extend the full depth of the hole. All of the coal mined at our highwall mining operations is processed in preparation plants to remove rock and impurities before it becomes saleable clean coal.

Marketing, Sales and Customer Contracts

We market coal produced at our operations and purchase and resell coal mined by others. We have coal supply commitments with a wide range of electric utilities, steel and coke manufacturers and industrial customers. Our marketing efforts are centered on customer needs and requirements. By offering coal of various types and grades to provide specific qualities of heat content, sulfur and ash and other characteristics relevant to its customers, we are able to serve a global customer base. Through this global platform, our coals are shipped to customers on five continents. This diversity allows us to

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adjust to changing market conditions. Many of our larger customers are well-established public utilities and steel manufacturers.
Our captive coal volumes include coal produced and processed by us as well as small volumes purchased from third-party producers to blend with our produced coal in order to meet customer specifications. These volumes are processed by us, meaning that we washed, crushed or blended the coal at one of our preparation plants or loading facilities prior to resale. Our T&L coal volumes solely include those volumes purchased from third-party producers and sold through our Trading and Logistics business.
Our export shipments serviced customers through shipping ports in 23 and 22 countries during the years ended 2018 and 2017, respectively. Europe was our largest export market during these periods, with coal sales to Europe accounting for approximately 40% and 44%, respectively, of total export coal revenues (excluding freight and handling revenues) and 32% of total coal revenues (excluding freight and handling revenues) for both years. All of our sales are made in U.S. dollars. See Item 8. Financial Statements and Supplementary Data, Note 28 Segment Information for additional export coal revenue information.
Our metallurgical coal sales are typically made with customers with whom we have a long-term relationship. However, defined pricing and volume in our sales agreements tend to be short-term in nature. Domestic metallurgical customers typically enter into one-year agreements with a fixed price for the entire contract year. Any longer-term agreement would generally have a renegotiation of price every subsequent contract year. Export sales are generally made on an annual, quarterly, or spot cargo basis. Annual and quarterly agreements typically have market indexed pricing that changes with the market monthly. Any export agreement with a term greater than one-year would generally have a renegotiation of pricing terms for each subsequent contract year. Future volume for future years is generally contingent on both parties agreeing to a pricing mechanism to cover the contract year.

We enter into long-term contracts (typically ranging from one to three years) with our thermal coal customers. Terms of these agreements may address coal quality requirements, quantity parameters, flexibility and adjustment mechanisms, permitted sources of supply, treatment of environmental constraints, options to extend, force majeure, suspension, termination and assignment issues, the allocation between the parties of the cost of complying with future governmental regulations and many other matters.
Generally, our long-term thermal coal agreements contain committed volumes and fixed prices for a period or a certain number of periods pursuant to which thermal coal will be delivered under these agreements. After a fixed price period elapses, the long-term agreement may provide for a price negotiation/determination period prior to the commencement of the pending unpriced contract period. The price negotiations generally consider either then current market prices and/or relevant market indices. Provisions of this sort increase the difficulty of predicting the exact prices a coal supplier will receive for its coal during the course of the long-term agreement. During the years ended 2018 and 2017, approximately 75% and 86%, respectively, of our thermal coal sales volume were delivered pursuant to long-term contracts.
Distribution and Transportation
Coal consumed domestically is usually sold at the mine and transportation costs are normally borne by the purchaser. Export coal is usually sold at the loading port, with purchasers responsible for further transportation.
For our export sales, we negotiate transportation agreements with various providers, including railroads, trucks, barge lines, and terminal facilities to transport shipments to the relevant loading port. We coordinate with customers, mining facilities and transportation providers to establish shipping schedules that meet each customer’s needs. Our captive coal is loaded from our preparation plants, loadout facilities, and in certain cases directly from our mines. The coal we purchase is loaded in some cases directly from mines and preparation plants operated by third parties or from an export terminal. Virtually all of our coal is transported from the mine to our preparation plants by truck or belt conveyor systems. It is transported from preparation plants and loading facilities to the customer by means of railroads, trucks, barge lines, and lake-going and ocean-going vessels from terminal facilities. We depend upon rail, barge, trucking and other systems to deliver coal to markets. In the years ended 2018 and 2017, our produced coal was transported from the mines and to the customer primarily by rail, with the main rail carriers being CSX Transportation and Norfolk Southern Railway Company. Rail shipments constituted approximately 55% and 41% of total shipments of captive coal volume from our mines to a vessel loading point or customer location during the years ended 2018 and 2017, respectively. The balance was shipped from our preparation plants, loadout facilities or mines via truck or barge. Our export sales are primarily shipped to DTA and Pier 6 (Lamberts Point) shipping ports in the Hampton Roads area of Virginia. Contura will ship limited export quantiles through other US ports when warranted by logistics and economics. We own a 65.0% interest in the DTA coal export terminal at Newport News, Virginia.

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Equipment
Our equipment, including underground and surface, is of varying age and in good and operational condition. It is regularly maintained and serviced by a dedicated maintenance workforce and third-party suppliers, including scheduled preventive maintenance.
Procurement
Principal goods and services used in our business include mining equipment, replacement parts and materials such as explosives, diesel fuel, tires, conveyance structure, ventilation supplies, lubricants, steel, magnetite and other raw materials, maintenance and repair services, electricity, and roof control and support items. We rely on third-party suppliers to provide mining materials and equipment. Although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies, we believe adequate substitute suppliers are available. For further discussion of our sources and availability of materials, see Item 1A “Risk Factors-Risks Related to Our Operations- Decreased availability or increased costs of key equipment and materials, including certain items mandated by regulations, could impact our cost of production and decrease our profitability .”

We incur substantial expenses per year to procure goods and services in support of our respective business activities in addition to capital expenditures. We use suppliers for a significant portion of our equipment rebuilds and repairs both on- and off-site, as well as construction and reclamation activities.
We have a centralized sourcing group, which sets sourcing policy and strategy focusing primarily on major supplier contract negotiation and administration, including but not limited to the purchase of major capital goods in support of the mining operations. We promote competition between suppliers and seek to develop relationships with suppliers that focus on lowering our costs while improving quality and service. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.
Competition
The coal industry is highly competitive, both in the U.S. and internationally. In the metallurgical coal market, of the approximately 70 million tons currently produced annually in the U.S., Contura produces approximately 12 million tons, or 17%. A significant portion of U.S. metallurgical coal production is shipped internationally, where it competes directly with international sources of production. Approximately 60% of Contura’s metallurgical coal production is shipped internationally.

In the thermal market, of the approximately 710 million tons currently produced annually in the U.S., Contura produces approximately 12.5 million tons, or 2%. Only a small portion of overall U.S. thermal production is shipped internationally, but there is strong competition in the domestic market. Approximately 4% of Contura’s thermal coal production is shipped internationally. We compete for U.S. sales with numerous coal producers in the Appalachian region and the Illinois basin, and in some cases with western coal producers. The key factors of this competition are delivered coal price, coal quality and characteristics, transportation costs from the mine to the customer and the reliability of supply. Competition from coal with lower production costs shipped from other coal basins has resulted in increased competition for coal sales in the Appalachian region.

Demand for met coal and the prices that we are able to obtain for it depend to a large extent on the demand and price for steel in the U.S. and internationally. This demand is influenced by factors beyond our control, including overall economic activity and the availability and relative cost of substitute materials. In the export met coal market, we compete with producers from Australia and Canada and with other international producers on many of the same factors as in the U.S. market. Competition in the export market is also impacted by fluctuations in relative foreign exchange rates and costs of inland and ocean transportation, among other factors.
Demand for thermal coal and the prices that we are able to obtain for it are closely linked to coal consumption patterns of the domestic electric generation industry. These coal consumption patterns are influenced by many factors beyond our control, including the demand for electricity, which is significantly dependent upon summer and winter temperatures, and commercial and industrial outputs in the U.S., environmental and other government regulations, technological developments and the location, availability, quality and price of competing sources of power. These competing sources include natural gas, nuclear, fuel oil and increasingly, renewable sources such as solar and wind power. Demand for thermal coal and the prices that we are able to obtain for it are affected by each of the above factors.

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Employees
As of December 31, 2018, we had approximately 4,420 employees, with the United Mine Workers of America (“UMWA”) representing approximately 16% of these employees. Certain of our subsidiaries have wage agreements with the UMWA that are subject to termination by either the employer or the UMWA, without cause, on July 31, 2020. Relations with organized labor are important to our success, and we believe we have good relations with our employees.
Legal Proceedings
We could become party to legal proceedings from time to time. These proceedings, as well as governmental examinations, could involve various business units and a variety of claims including, but not limited to, contract disputes, personal injury claims, property damage claims (including those resulting from blasting, subsidence, trucking and flooding), environmental and safety issues, and employment matters. While some legal matters may specify the damages claimed by the plaintiffs, many seek an unquantified amount of damages. Even when the amount of damages claimed against us or our subsidiaries is stated, (i) the claimed amount may be exaggerated or unsupported; (ii) the claim may be based on a novel legal theory or involve a large number of parties; (iii) there may be uncertainty as to the likelihood of a class being certified or the ultimate size of the class; (iv) there may be uncertainty as to the outcome of pending appeals or motions; and/or (v) there may be significant factual issues to be resolved. As a result, if such legal matters arise in the future we may be unable to estimate a range of possible loss for matters that have not yet progressed sufficiently through discovery and development of important factual information and legal issues. We record accruals based on an estimate of the ultimate outcome of these matters, but these estimates can be difficult to determine and involve significant judgment.

ENVIRONMENTAL AND OTHER REGULATORY MATTERS
Federal, state and local authorities regulate the U.S. coal mining industry and the industries it serves with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water quality, plant and wildlife protection, the reclamation of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining, and the effects of mining on groundwater quality and availability. These laws and regulations, which are extensive, subject to change, and have tended to become stricter over time, have had, and will continue to have, a significant effect on our production costs and our competitive position relative to certain other sources of electricity generation. Future legislation, 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 to us and delays, interruptions, or a termination of operations, the extent of which we cannot predict. We intend to continue to comply with these regulatory requirements as they evolve by timely implementing necessary modifications to facilities or operating procedures. Future legislation, regulations, orders or regional or international arrangements, agreements or treaties, as well efforts by private organizations, including those relating to global climate change, may continue to cause coal to become more heavily regulated.
We endeavor to conduct our mining operations in compliance with all applicable federal, state, and local laws and regulations. We have certain procedures in place that are designed to enable us to comply with these laws and regulations. However, due to the complexity and interpretation of these laws and regulations, we cannot guarantee that we have been or will be at all times in complete compliance, and violations are likely to occur from time to time. None of the violations or the monetary penalties assessed upon us have been material. Future liability under or compliance with environmental and safety requirements could, however, have a material adverse effect on our operations or competitive position. Under some circumstances, substantial fines and penalties, including revocation, denial or suspension of mining permits, may be imposed under the laws described below.
Monetary sanctions, expensive compliance measures and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.
As of December 31, 2018 , we had accrued $228.4 million for reclamation liabilities and mine closures, including $24.8 million of current liabilities.
Mining Permits and Approvals
Numerous governmental permits or approvals are required for mining operations pursuant to certain federal, state and local laws applicable to our operations. When we apply for these permits and approvals, we may be required to prepare and present data to federal, state or local authorities pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment and measures we will take to minimize and mitigate those impacts. The requirements imposed

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by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations.
In order to obtain mining permits and approvals from federal and state regulatory authorities, mine operators, including us, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior or better condition, productive use or other permitted condition. Typically, we submit the necessary permit applications several months, or even years, before we plan to begin mining a new area. Mining permits generally are approved many months or even years after a completed application is submitted. Therefore, we cannot be assured that we will obtain future mining permits in a timely manner.
Permitting requirements also require, under certain circumstances, that we obtain surface owner consent if the surface estate has been severed from the mineral estate. This requires us to negotiate with third parties for surface rights that overly coal we control or intend to control. These negotiations can be costly and time-consuming, lasting years in some instances, which can create additional delays in the permitting process. If we cannot successfully negotiate for surface rights, we could be denied a permit to mine coal we already control.
We are in the process of transferring certain permits for the PRB operations sold to Blackjewel. During the permit transfer process, Blackjewel will conduct mining operations under such permits in accordance with a permit operating agreement between the parties. The Powder River Basin Resource Council filed objections to the permit transfer with the Wyoming Environmental Quality Council on November 16, 2018. The objections are scheduled to be heard on May 15 and 16, 2019. We currently believe the objections are without merit, but there can be no assurance that such transfers will be completed on a timely basis, or at all. There are also a small number of permits that were sold by Alpha and the transfers have not yet been approved.
Surface Mining Control and Reclamation Act
SMCRA, which is administered by the Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes mining, environmental protection, reclamation, and closure standards for all aspects of surface mining as well as many aspects of underground mining that effect surface expressions. Mine operators must obtain SMCRA permits and permit renewals from the OSM or from the applicable state agency if the state agency has obtained primary control of administration and enforcement of the SMCRA program, or primacy. A state agency may obtain primacy if OSM concludes that the state regulatory agency’s mining regulatory program is no less stringent than the federal mining program under SMRCA. States where we have active mining operations have achieved primacy and issue permits in lieu of OSM. OSM maintains oversight of how the states administer their programs.
SMCRA permit provisions include a complex set of requirements which include: coal prospecting; mine plan development; topsoil or growth medium removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance, including outside the permit area; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation and reclamation.
The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes, but is not limited to, surveys of cultural and historical resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology, and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures associated with the coal that we will mine. We develop mining and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mining and reclamation plan incorporates the provisions of SMCRA, the state programs, and the complementary environmental programs that affect coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land, and documents required of the OSM’s Applicant Violator System (“ACS”), including the mining and compliance history of officers, directors and principal owners of the entity.
Regulations under SMCRA and its state analogues provide that a mining permit or modification can, under certain circumstances, be delayed, refused or revoked if we or any entity that owns or controls us or is under common ownership or control with us have unabated permit violations or have been the subject of permit or reclamation bond revocation or suspension. These regulations define certain relationships, such as owning over 50% of stock in an entity or having the authority to determine the manner in which the entity conducts mining operations, as constituting ownership and control. Certain other relationships are presumed to constitute ownership or control, including being an officer or director of an entity or owning between 10% and 50% of the mining operator. This presumption, in some cases, can be rebutted where the person or entity can demonstrate that it in fact does not or did not have authority directly or indirectly to determine the manner in which

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the relevant coal mining operation is conducted. Thus, past or ongoing violations of federal and state mining laws by us or by coal mining operations owned or controlled by our significant stockholders, directors or officers or certain other third-party affiliates could provide a basis to revoke existing permits and to deny the issuance of additional permits or modification or amendment of existing permits. This is known as being “permit-blocked.” In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.
Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice of the proposed permit is given that also provides for a comment period before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and may take many months or even years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.
The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed or abandoned prior to SMCRA’s adoption in 1977. The current fee is $0.28 per ton on surface-mined coal and $0.12 per ton on deep-mined coal. For the fiscal years ended 2018 and 2017, we recorded $1.6 million and $1.4 million, respectively, of expense related to these fees.
While SMCRA is a comprehensive statute, SMCRA does not supersede the need for compliance with other major environmental statutes, including the Endangered Species Act; Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act (“RCRA”) and Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”).
Surety Bonds
Federal and state laws require us to obtain surety bonds or other approved forms of security to cover the costs of certain long-term obligations including mine closure or reclamation costs under SMCRA, federal and state workers’ compensation costs, coal leases and other miscellaneous obligations. As of December 31, 2018 and 2017, our posted third-party surety bond amount in all states where we operate, less portions attributable to discontinued operations, was approximately $344.3 million and $166.0 million, respectively, which was used to primarily secure the performance of our reclamation or lease obligations.
Posting of a bond or other security with respect to the performance of reclamation obligations is a condition to the issuance of a permit under SMCRA. Under the terms of agreements, we and Alpha entered into in connection with the Alpha Restructuring, we and Alpha were required to replace Alpha’s self-bonds with surety bonds, collateralized bonds, or other financial assurance mechanisms, over time and under applicable regulations. Self-bonding may not be available to us as a means to comply with our reclamation bonding obligations for the foreseeable future. In August 2016, OSM announced its decision to pursue a rulemaking to evaluate self-bonding for coal mines, including eligibility standards. OSM has not yet issued a proposed rule to address this issue.
Clean Air Act
The Clean Air Act and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emission control requirements relating to particulate matter, which may include controlling fugitive dust. The Clean Air Act indirectly affects coal mining operations by extensively regulating air emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired electricity generating plants or the use of met coal in connection with steelmaking operations. In recent years, Congress has considered legislation that would require increased reductions in emissions of sulfur dioxide, nitrogen oxide, and mercury. The general effect of emission regulations on coal-fired power plants could be to reduce demand for coal.
In addition to the greenhouse gas (“GHG”) issues discussed below, the air emissions programs that may materially and adversely affect our operations, financial results, liquidity, and demand for coal, directly or indirectly, include, but are not limited to, the following:
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Acid Rain. Title IV of the Clean Air Act requires reductions of sulfur dioxide emissions by electric utilities. Affected electricity generators have sought to meet these requirements by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading sulfur dioxide emission allowances. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years.

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NAAQS for Criteria Pollutants. The Clean Air Act requires the EPA to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for six common air pollutants, including nitrogen oxide, sulfur dioxide, particulate matter, and ozone. Areas that are not in compliance (referred to as “non- attainment areas”) with these standards must take steps to reduce emissions levels. Over the past several years, the EPA has revised its NAAQS for nitrogen oxide, sulfur dioxide, particulate matter and ozone, in each case making the standards more stringent. As a result, some states will be required to amend their existing individual state implementation plans (“SIPs”) to achieve compliance with the new air quality standards. Other states will be required to develop new plans for areas that were previously in “attainment,” but do not meet the revised standards.
For example, in October 2015, the EPA finalized the NAAQS for ozone pollution and reduced the limit to 70 parts per billion (ppb) from the previous 75 ppb standard. The EPA made the majority of area designations related to this rule on November 16, 2017 and June 4, 2018 and finalized designations for the remaining regions of the country on July 25, 2018. Under the revised NAAQS for ozone in particular, significant additional emissions control expenditures may be required at coal-fired power plants. The final rules and new standards may impose additional emissions control requirements on our customers in the electric generation, steelmaking, and coke industries. Although coal mining and processing operations may emit certain criteria pollutants, we operate in material compliance with our permits. However, our operations could be impacted if the attainment status of the areas in which we operate changes in the future.
A suit by industry challenging the EPA’s 2015 Ozone NAAQS ( Murray Energy Corp. v. EPA) is currently pending in the D.C. Circuit. In April 2017, the D.C. Circuit Court granted EPA’s motion to indefinitely delay any decision on the challenges pending the EPA’s possible reconsideration of the rule. In July 2018, the D.C. Circuit Court returned the matter to its active docket and in August 2018, the EPA indicated to the court that it would not be revising the 2015 standards at this time.
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NOx SIP Call. The NOx SIP Call program was established by the EPA in October of 1998 to reduce the transport of nitrogen oxide and ozone on prevailing winds from the Midwest and South to states in the Northeast, which said they could not meet federal air quality standards because of migrating pollution. The program is designed to reduce nitrogen oxide emissions by one million tons per year in 22 eastern states and the District of Columbia. As a result of the program, many power plants have been or will be required to install additional emission control measures, such as selective catalytic reduction devices. Installation of additional emission control measures will make it more costly to operate coal-fired power plants, potentially making coal a less attractive fuel. On February 26, 2019, EPA published a final rule amending the NOx SIP Call regulations to allow states to establish alternative monitoring and reporting requirements for certain sources.
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Cross-State Air Pollution Rule. In June 2011, the EPA finalized the CSAPR, which required 28 states in the Midwest and eastern seaboard of the U.S. to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Nitrogen oxide and sulfur dioxide emission reductions were scheduled to commence in 2012, with further reductions effective in 2014. However, implementation of CSAPR’s requirements were delayed due to litigation. In October 2014, the EPA issued an interim final rule reconciling the CSAPR rule with the Court’s order, which called for Phase 1 implementation in 2015 and Phase 2 implementation in 2017.
In September 2016, the EPA finalized an update to the CSAPR ozone season program by issuing the Final CSAPR Update. The Final CSAPR Update rule is the subject of a pending legal challenge in the D.C. Circuit by five states. For states to meet their requirements under CSAPR, a number of coal-fired electric generating units will likely need to be retired, rather than retrofitted with the necessary emission control technologies, reducing demand for thermal coal.
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Mercury and Hazardous Air Pollutants. In February 2012, the EPA formally adopted a rule to regulate emissions of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal- and oil-fired power plants, referred to as “MATS.” In March 2013, the EPA finalized reconsideration of the MATS rule as it pertains to new power plants, principally adjusting emissions limits for new coal- fired units to levels considered attainable by existing control technologies. In subsequent litigation, the U.S. Supreme Court struck down the MATS rule based on the EPA’s failure to take costs into consideration. The D.C. Circuit allowed the current rule to stay in place until the EPA issued a new finding. In April 2016, the EPA issued a final finding that it is appropriate and necessary to set standards for emissions of air toxics from coal- and oil-fired power plants. However, in April 2017, the EPA indicated in a court filing that it may reconsider this finding, and on April 27, 2017, the D.C. Circuit stayed the litigation. In August 2018, the EPA stated that it plans on sending a draft proposal to the White House questioning the EPA’s earlier finding and intends to reevaluate the MATS rule itself.

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On December 27, 2018, EPA issued a proposed revised Supplemental Cost Finding for MATS, as well as the Clean Air Act required “risk and technology review.” After taking account of both the cost to coal- and oil-fired power plants of complying with the MATS rule and the benefits attributable to regulating hazardous air pollutant (HAP) emissions from these power plants, EPA proposed to determine that it is not “appropriate and necessary” to regulate HAP emissions from power plants under Section 112 of the Clean Air Act. The emission standards and other requirements of the MATS rule, first promulgated in 2012, would remain in place, however, since EPA did not propose to remove coal- and oil-fired power plants from the list of sources that are regulated under Section 112 of the Act. Comments on the proposed rule are due on or before April 17, 2019.
Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed. Regulation of mercury emissions by the EPA, states, Congress, or pursuant to an international treaty may further decrease the demand for coal. Like CSAPR, MATS and other similar future regulations could accelerate the retirement of a significant number of coal-fired power plants, in addition to the significant number of plants and units that have already been retired as a result of environmental and regulatory requirements and uncertainties adversely impacting coal-fired generation. Such retirements would likely adversely impact our business.
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Regional Haze, New Source Review and Methane. The EPA’s regional haze program is intended to protect and improve visibility at and around national parks, national wilderness areas and international parks. In December 2011, the EPA issued a final rule under which the emission caps imposed under CSAPR for a given state would supplant the obligations of that state with regard to visibility protection. In May 2012, the EPA finalized a rule that allows the trading programs in CSAPR to serve as an alternative to determining source-by-source Best Available Retrofit Technology (“BART”). This rule provides that states in the CSAPR region can substitute participation in CSAPR for source-specific BART for sulfur dioxide and/or nitrogen oxides emissions from power plants. 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 result in additional coal plant closures and affect the future market for coal. A final Regional Haze rule was published on January 10, 2017 and is currently being reevaluated by the EPA.
In addition, the EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringent air emissions control equipment required of new plants. Under the proposed Affordable Clean Energy rule (“ACE Rule”), however, the way in which emissions increases are calculated would change so that modifications to power plants would, as a general matter, be less likely to trigger new source review. Federal legislation to reform new source review has been reintroduced and regulatory reform is being considered by the EPA.
Litigation seeking to force the EPA to list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the CAA and establish standards to reduce emissions from sources of methane and other emissions related to coal mines was dismissed by the D.C. Circuit in May 2014. In that case, the Court denied a rulemaking petition citing agency discretion and budgetary restrictions, and ruled the EPA has reasonable discretion to carry out its delegated responsibilities, which includes determining the timing and relative priority of its regulatory agenda. In July 2014, the D.C. Circuit denied a petition seeking a rehearing of the case en banc. Litigation regarding these issues may continue and could result in the need for additional air pollution controls for coal fired units and our operations.
Global Climate Change
Global climate change initiatives and public perceptions have resulted, and are expected to continue to result, in decreased coal-fired power plant capacity and utilization, phasing out and closing many existing coal-fired power plants, reducing or eliminating construction of new coal-fired power plants in the United States and certain other countries, increased costs to mine coal and decreased demand and prices for thermal coal.
There are three important sources of GHGs associated with the coal industry: first, the end use of our coal by our customers in electricity generation, coke plants, and steelmaking is a source of GHGs; second, combustion of fuel for mining equipment used in coal production; and third, coal mining can release methane, a GHG, directly into the atmosphere. GHG emissions from coal consumption and production are subject to pending and proposed regulation as part of initiatives to address global climate change.

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The Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (the “Kyoto Protocol”) became effective in 2005 and bound those developed countries that ratified it (which the U.S. did not do) to reduce their global GHG emissions. In December 2015, the United States and almost 200 nations agreed to the Paris Agreement, which entered into force on November 4, 2016 and has the long-term goal to limit global warming to below two degrees Celsius by 2100 from temperatures in the pre-industrial era. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. On June 1, 2017, the Trump administration announced that the U.S. will withdraw from the Paris Agreement. Nevertheless, numerous U.S. governors, mayors and businesses have pledged their commitments to the goals of the Paris Agreement. These commitments could further reduce demand and prices for our coal.
In 2009, the EPA issued a finding that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment. The EPA has since adopted regulations under existing provisions of the CAA pursuant to this finding. For example, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the U.S., including coal-fired electric power plants and steel-making operations. The EPA has also promulgated the Tailoring Rule, which requires that all new or modified stationary sources of GHGs that will emit more than 75,000 tons of carbon dioxide per year and are otherwise subject to CAA regulation, and any other facilities that will emit more than 100,000 tons of carbon dioxide per year, to undergo prevention of significant deterioration (“PSD”) permitting, which requires that the permitted entity adopt the best available control technology.
In June 2014, the U.S. Supreme Court addressed whether the EPA’s regulation of GHG emissions from new motor vehicles properly triggered GHG permitting requirements for stationary sources under the CAA as well as the validity of the Tailoring Rule under the CAA. The decision reversed, in part, and affirmed, in part, a 2012 D.C. Circuit decision that upheld the Tailoring Rule. Specifically, the Court held that the EPA exceeded its statutory authority when it interpreted the CAA to require PSD and Title V permitting for stationary sources based on their potential GHG emissions. However, the Court also held that the EPA’s determination that a source already subject to the PSD program due to its emission of conventional pollutants may be required to limit its GHG emissions by employing the “best available control technology” was permissible. As a result, the EPA is now requiring new sources already subject to the PSD program, including coal-fired power plants, to undergo control technology reviews for GHGs (predominately carbon dioxide) as a condition of permit issuance. These reviews may impose limits on GHG emissions, or otherwise be used to compel consideration of alternative fuels and generation systems, as well as increase litigation risk for-and so discourage development of-coal-fired power plants.
On August 3, 2015, the EPA released a final rule establishing New Source Performance Standards (“NSPS”) for emissions of carbon dioxide for new, modified and reconstructed fossil fuel-fired electric generating units (“Power Plant NSPS”). The final rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for carbon dioxide of 1,400 lb CO 2 /MWh-gross. The standard is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture and storage (“CCS”). Modified and reconstructed fossil fuel fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance.
Reconstructed units must implement the most efficient generating technology based on the size of the unit (supercritical steam conditions for larger units, to meet a standard of 1,800 lb CO 2 /MWh-gross, and subcritical conditions for smaller units to meet a standard of 2,000 lb CO 2 /MWh-gross). Numerous legal challenges to the final rule are currently pending. There is a risk that CCS technology may not be commercially practical in limiting emissions as otherwise required by the rule or similar rules that may be proposed in the future. If such legislative or regulatory programs are adopted or maintained, and economic, commercially available carbon capture technology for power plants is not developed or adopted in a timely manner, it would negatively affect our customers and would further reduce the demand for coal as a fuel source, causing coal prices and sales of our coal to decline, perhaps materially.
In August 2015, the EPA issued the Clean Power Plan (“CPP”), a final rule that establishes carbon pollution standards for existing power plants, called CO 2 emission performance rates. The EPA expected each state to develop implementation plans for power plants in its state to meet the individual state targets established in the CPP. In response to legal challenges, on February 9, 2016, the U.S. Supreme Court granted a stay of the implementation of the CPP before the D.C. Circuit even issued a decision. By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the D.C. Circuit Court and the Supreme Court through the denial of any certiorari petition or a decision, if the petition is granted. The Supreme Court’s stay applies only to the CPP and does not affect the Power Plant NSPS.
President Trump’s March 2017 Executive Order directed the EPA to review the Power Plant NSPS and the CPP and, if appropriate, take steps to suspend, revise or rescind the rules through the rulemaking process to ensure consistency with the goals of energy independence, economic growth and cost-effective environmental regulation. On April 4, 2017, the EPA announced in the Federal Register that it is initiating its review of the Power Plant NSPS and CPP. On April 28, 2017, the D.C.

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Circuit paused legal challenges to both the CPP and the Power Plant NSPS for 60 days to allow parties in each of those cases to brief the court on whether the case should be remanded to the agency or kept on hold, and in a series of orders since, has continued to hold the cases in abeyance while EPA rulemaking regarding CPP continues. In October 2017, EPA issued a proposed rule to rescind the CPP, and on August 31, 2018, published the ACE Rule, a proposed replacement of the CPP. In contrast to the CPP, which called for the shifting of electricity generation away from coal-fired sources towards natural gas and renewables, the ACE Rule would focus on reducing GHG emissions from existing coal-fired plants by requiring states to mandate the implementation of a range of technologies at power plants designed to improve their heat rate (i.e., decrease the amount of fuel necessary to generate the same amount of electricity). The outcome of these rulemakings is uncertain and likely to be subject to extensive notice and comment and litigation. More stringent standards for carbon dioxide emissions as a result of these rulemakings could further reduce demand for coal, and our business would be adversely impacted.
Various states and regions have adopted GHG initiatives and certain governmental bodies, including the states of Virginia and California, have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities. A number of states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. For example, on September 10, 2018 California adopted a law that requires all electricity consumed by the state to be generated from renewable sources such as solar, wind and hydropower by 2045.
In addition, certain banks and other financing sources have taken actions to limit available financing for the development of new coal-fueled power plants, which also may adversely impact the future global demand for coal. Further, there have been recent efforts by members of the general financial and investment communities, such as investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to divest themselves and to promote the divestment of securities issued by companies involved in the fossil fuel extraction market, such as coal producers. Those entities also have been pressuring lenders to limit financing available to such companies. These efforts may adversely affect the market for our securities and our ability to access capital and financial markets in the future.
Furthermore, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation. These efforts, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, could cause coal prices and sales of our coal to materially decline and possibly increase our operating costs.
These and other current or future global climate change laws, regulations, court orders or other legally enforceable mechanisms, or related public perceptions regarding climate change, are expected to require additional controls on coal-fired power plants and industrial boilers and may cause some users of coal to further switch from coal to alternative sources of fuel, thereby depressing demand and pricing for coal.
Clean Water Act
The CWA and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the U.S. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. Legislation that seeks to clarify the scope of CWA jurisdiction has also been considered by Congress. Recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements.
CWA requirements that may directly or indirectly affect our operations include the following:
Wastewater Discharge
Prior to discharging any pollutants into waters of the United States, coal mining companies must obtain a National Pollutant Discharge Elimination System (“NPDES”) permit from the appropriate state or federal permitting authority. Section 402 of the CWA creates a process for establishing effluent limitations for discharges to streams that are protective of water quality standards through the NPDES program, and corresponding programs implemented by state regulatory agencies. 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 U.S. Failure to comply with the CWA or NPDES permits can lead to the imposition of significant penalties, litigation, compliance costs and delays in coal production. Furthermore, the imposition of future restrictions on the discharge of certain pollutants into waters of the U.S. could increase the difficulty of obtaining and complying with NPDES permits, which could impose additional time and cost burdens on our operations. For instance, waters that states have designated as impaired (i.e., as not meeting present water quality standards) are subject to Total Maximum Daily Load regulations, which may lead to the adoption of more stringent discharge standards for our coal mines and could require more costly treatment.

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In addition, when water quality in a receiving stream is of high quality, states are required to conduct an anti-degradation review before approving discharge permits. Anti-degradation policies may increase the cost, time and difficulty associated with obtaining and complying with NPDES permits and may also require more costly treatment.
On March 5, 2014, EPA, the U.S. Department of Justice (“DOJ”), West Virginia Department of Environmental Protection, the Pennsylvania Department of Environmental Protection and the Kentucky Energy and Environment Cabinet filed a Complaint against Alpha and its permit holding subsidiaries in Kentucky, Pennsylvania, Tennessee, Virginia and West Virginia alleging that Alpha’s mining affiliates in those states and in Tennessee and Virginia exceeded certain water discharge permit limits during the period of 2006 to 2013 and simultaneously entered into a Consent Decree with Alpha resolving their claims. The Consent Decree was entered by the Southern District of West Virginia on November 26, 2014 and amended on June 12, 2016 and again on February 28, 2018 (the “Alpha Consent Decree”). As part of the Alpha Consent Decree, Alpha agreed to implement an integrated environmental management system and an expanded auditing/reporting protocol, install selenium and osmotic pressure treatment facilities at specific locations, and certain other measures. The Alpha Consent Decree required Alpha to pay $27.5 million in civil penalties, to be divided among the federal government and state agencies. All required water treatment systems have been constructed, the environmental management system has been implemented, and the other terms and conditions of the Alpha Consent Decree have been substantially satisfied. We remain subject to the Alpha Consent Decree and pay stipulated penalties to the U.S. government and the state of West Virginia when water discharge permit limitations are exceeded. We have been and are currently in material compliance with our obligations under the Alpha Consent Decree. Discussions continue with EPA and DOJ to terminate the Alpha Consent Decree based upon satisfactory compliance.
Dredge and Fill Permits
Many mining activities, including the development of settling ponds and the construction of certain sediment control structures, valley fills and surface impoundments, require permits from the U.S. Army Corps of Engineers (“COE”) under Section 404 of the CWA. Generally speaking, these Section 404 permits allow the placement of dredge and fill materials into navigable waters of the U.S., including wetlands, streams, and other regulated areas. The COE has issued 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 Permits 5, 21, 49 and 50 generally authorize the disposal of dredged or fill material from surface coal mining activities into waters of the U.S., subject to certain restrictions. Nationwide Permits are typically reissued for a five-year period and require appropriate mitigation, and permit holders must receive explicit authorization from the COE before proceeding with proposed mining activities. The COE reauthorized use of nationwide permits for surface and underground coal mines in January 2017. Expansion of our mining operations into new areas may trigger the need for individual COE approvals which could be more costly and take more time to obtain.
In June 2015, the EPA and the COE published a new, more expansive, definition of “waters of the United States,” (“WOTUS”) now known as the Clean Water Rule (“CWR”) under the CWA. The CWR is the subject of extensive ongoing litigation and administrative proceedings and its current and future impact on our operations are the subject of significant uncertainty. The U.S. Court of Appeals for the Sixth Circuit has stayed the CWR nationwide pending further action of the court. In response to this decision, the EPA and the COE resumed nationwide use of the agencies’ prior regulations defining WOTUS. On January 22, 2018, the Supreme Court reversed the Sixth Circuit's decision, ruling that jurisdiction over challenges to the CWR rests with the federal district courts and not with the appellate courts, which was followed by the dissolution of the stay by the Sixth Circuit. On February 6, 2018, the EPA and COE published a rule that delayed applicability of the CWR for two years. However, on August 16, 2018, the federal court in South Carolina enjoined the rule, effectively reinstating the CWR in Virginia and Pennsylvania (where we have operations) and in 24 other states. The injunction is being challenged on appeal. However, our West Virginia operations remain unaffected by the CWR, due to separate injunctions issued by federal courts in Georgia and North Dakota applicable to West Virginia and 23 other states. On February 28, 2017, while challenges to the CWR were pending, President Trump signed an executive order directing the EPA and the COE to review the CWR for consistency with the goals of “promoting economic growth and minimizing regulatory uncertainty” and to consider a new rule that reflects Justice Scalia’s plurality opinion in the 2006 Supreme Court decision, Rapanos v. United States , that CWA jurisdiction attaches only to “navigable waters” and other waters with a relatively permanent flow, such as rivers or lakes. On March 6, 2017, the EPA and the COE published a Notice of Intent to review and rescind or revise the rule and on June 29, 2018 the EPA and the COE published a supplemental notice indicating their intention to repeal the CWR and providing a variety of reasons to support such a repeal. The EPA published a proposed new definition of WOTUS on February 14, 2019. The process to undo and replace the CWR will likely be subject to continued extensive notice, comment and litigation.
Cooling Water Intake
In May 2014, the EPA issued a new final rule pursuant to Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment. The rule is expected to affect over 500 power

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plants. These requirements could increase our customers’ costs and may adversely affect the demand for coal, which may materially impact our results or operations.
Effluent Guidelines
On November 3, 2015, the EPA published the final rule for Effluent Limitations Guidelines and Standards (“ELGS”), revising the regulations for the Steam Electric Power Generating category which became effective on January 4, 2016. It establishes the first federal limits on the levels of arsenic, mercury, selenium and nitrate-nitrites in flue gas desulfurization that can be discharged as wastewater from power plants, based on technology improvements over the last three decades. On April 25, 2017 the EPA stayed the implementation of the rule indefinitely to allow for reconsideration. This stay is the subject of legal challenges. EPA is currently reviewing the rule and is expected to issue updated ELGS sometime in 2019.
Endangered Species Act
The ESA and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and mine plan modifications and approvals, and may include restrictions on timber harvesting, road building and other mining activities in areas containing the affected species or their habitats. We may also need to obtain additional permits or approvals if the incidental take of these species in the course of otherwise lawful activity may occur, which could take more time, be more costly and have adverse effects on operations. A number of species indigenous to properties we control or surrounding areas are protected under the ESA. Certain other sensitive species which are not currently protected by the ESA may also require protection and mitigation efforts consistent with federal and state requirements. ESA regulatory review is currently underway at the U.S. Fish and Wildlife Agency (“FWS”) and on July 25, 2018 the FWS issued proposed regulatory amendments that are considered to be favorable to our industry.
After the Stream Protection Rule and the accompanying 2016 Biological Opinion were repealed in February 2017, OSM issued a Section 7(d) determination that reinitiated consultation with the FWS to develop a new Biological Opinion. A new Biological Opinion could make compliance with the ESA more difficult and expensive.
Resource Conservation and Recovery Act
RCRA affects coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. The EPA determined that coal combustion residuals (“CCR”) do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state hazardous waste laws do not regulate CCR as hazardous wastes. The EPA also concluded that beneficial uses of CCR, other than for mine filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as minefill. In December 2014, the EPA finalized regulations that address the management of coal ash as a non-hazardous solid waste under Subtitle D. The rules impose engineering, structural and siting standards on surface impoundments and landfills that hold coal combustion wastes and mandate regular inspections. The rules also require fugitive dust controls and impose various monitoring, cleanup, and closure requirements. In July 2018, the EPA published a final rule extending certain deadlines under the original rules, granting certain authority to states with authorized CCR programs and establishing groundwater protection standards for certain constituents. EPA and OSM plan additional rulemaking relating to CCR.
There have also been several legislative proposals that would require the EPA to further regulate the storage of CCR. For example, in December 2016, Congress passed the Water Infrastructure Improvements for the Nation Act, which allows states to establish permit programs to regulate the disposal of CCR units in lieu of the EPA’s CCR regulations. These requirements, as well as any future changes in the management of CCR, could increase our customers’ operating costs and potentially reduce their ability or need to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, can lead to material liability for our customers under RCRA or other federal or state laws and potentially further reduce the demand for coal.
Comprehensive Environmental Response, Compensation and Liability Act
CERCLA and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances into the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on hazardous substance generators, site owners, transporters, lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA currently excludes most wastes generated by coal mining and processing operations from the primary hazardous waste laws. The disposal, release or spilling of some products used by

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coal companies in operations, such as chemicals, could trigger the liability provisions of CERCLA or similar state laws. Thus, we may be subject to liability under CERCLA and similar state laws for our current or former owned, leased or operated coal mines and property or those of our predecessors. We may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination and natural resource damages at sites where we control surface rights. These liabilities could be significant and materially and adversely impact our financial results and liquidity.
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 regulatory requirements. For example, pursuant to a rule issued by the U.S. Department of Homeland Security (“DHS”) in 2007, facilities in possession of chemicals of interest (including ammonium nitrate at certain threshold levels) are required to complete a screening review. In 2011, the DHS published proposed regulations of ammonium nitrate under the Ammonium Nitrate Security Rule. Many of the requirements of the proposed regulations would be duplicative of those in place under the Bureau of Alcohol Tobacco and Firearms, including registration and background checks, and DHS has moved its 2011 rulemaking to a non-active status because the approach proposed was unlikely to deliver appreciable security benefits.
Additional requirements may include tracking and verifications for each transaction related to ammonium nitrate. A final rule has yet to be issued. In December 2014, the OSM announced its decision to pursue a rulemaking to revise regulations under SMCRA which will address all blast generated fumes and toxic gases. OSM has not yet issued a proposed rule to address these blasts. The outcome of these rulemakings could materially adversely impact our cost or ability to conduct our mining operations.
Other Environmental Laws
We are required to comply with numerous other federal, state and local environmental laws and regulations in addition to those previously discussed. These additional laws include, for example, the Safe Drinking Water Act, and the Toxic Substances Control Act and transportation laws adopted to ensure the appropriate transportation of our coal both nationally and internationally. Laws, regulations, and treaties of other countries may also adversely impact our export sales by reducing demand for our coal as a source of power generation in those countries.
Federal and State Nuclear Material Regulations
Many of our operations use equipment with radioactive sources primarily for coal density measurement. Use of this equipment must be approved by the U. S. Nuclear Regulatory Authority or the state agency that has been delegated this authority.
Mine Safety and Health
Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 (“Mine Act”) significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. All of the states in which we operate also have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive and pervasive systems for protection of employee health and safety affecting any segment of U.S. industry. The Mine Act is a strict liability statute that requires mandatory inspections of surface and underground coal mines and preparation plants and requires the issuance of enforcement action when it is believed that a standard has been violated. While this regulation has a significant effect on our operating costs, our U.S. competitors are subject to the same degree of regulation.
In 2006, in response to underground mine accidents, Congress enacted the Mine Improvement and New Emergency Response Act (the “MINER Act”). The MINER Act significantly amended the Mine Act, requiring, among other items, improvements in mine safety practices, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection and enforcement activities. Since passage of the MINER Act enforcement scrutiny has increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and severity of enforcement actions and related penalties. Various states also have enacted their own new laws and regulations addressing many of these same subjects. The U.S. Mine Safety and Health Administration (“MSHA”) continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards. For example, the second phase of MSHA’s respirable coal mine dust rule went into effect in February 2016 and requires increased sampling frequency and the use of continuous personal dust monitors. In August 2016, the third and final phase of the rule became effective, reducing the overall respirable dust standard in coal mines from 2.0 to 1.5 milligrams per cubic meter of air. Our compliance with these or any other new mine health and safety regulations could

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increase our mining costs. If we were found to be in violation of these regulations we could face penalties or restrictions that may materially and adversely affect impact our operations, financial results and liquidity. Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, 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. Effective January 1, 2019, the trust fund is funded by an excise tax on production of up to $0.50 per ton for deep-mined coal and up to $0.25 per ton for surface-mined coal, neither amount to exceed 2% of the gross sales price. The excise tax does not apply to coal shipped outside the United States. For the fiscal years ended December 31, 2018 and 2017, we recorded $6.4 million and $7.7 million, respectively, of expense related to this excise tax.
The Patient Protection and Affordable Care Act (“PPACA”) introduced significant changes to the federal black lung program, including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim, and established a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association with the federal black lung program. For former mining employees meeting statutory eligibility standards for Federal Black Lung benefits, we maintain a trust fund and insurance coverage to cover the cost of present and future claims. We may also be liable under state laws for black lung claims that are covered through the trust and insurance policies. The liability associated with present and future claims for black lung benefits is difficult to estimate, and the trust and insurance policies may be insufficient to cover all such liability.
Coal Industry Retiree Health Benefit Act of 1992
Unlike many companies in the coal business, we do not have any liability under the Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”), which requires the payment of substantial sums to provide lifetime health benefits to union-represented miners (and their dependents) who retired before 1992, because liabilities under the Coal Act that had been imposed on Alpha were settled in the bankruptcy process.
GLOSSARY
Acquisition. Refers to the transaction by which Contura acquired certain of Alpha’s core coal operations as part of the Alpha Restructuring.
Alpha. Alpha Natural Resources, Inc.
Alpha’s Plan of Reorganization. Alpha’s plan of reorganization approved on July 7, 2016 and effective as of July 26, 2016.
Alpha Restructuring. The series of bankruptcy restructuring transactions which led to Alpha’s emergence from Chapter 11 bankruptcy on July 26, 2016.
Ash. Impurities consisting of iron, alumina and other incombustible matter that are contained in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the burning characteristics of coal.

Assigned reserves. Coal that is planned to be mined at an operation that is currently operating, currently idled, or for which permits have been submitted and plans are eventually to develop the operation.

Back-to-Back Coal Supply Agreement. An agreement with Blackjewel (the “Buyer”) under the terms of the asset purchase agreement associated with the sale of PRB under which the Buyer will supply, deliver and sell to the Company, and the Company will accept, purchase and pay for, all coal that the Company is obligated to supply, deliver and sell under PRB coal supply agreements existing as of the transaction closing date that did not transfer to the Buyer at closing.

British Thermal Unit or BTU. A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

Central Appalachia or CAPP. Coal producing area in eastern Kentucky, Virginia, southern West Virginia and a portion of eastern Tennessee.

Coal seam. Coal deposits occur in layers. Each layer is called a “seam.”


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Coke. A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel. Its production results in a number of useful byproducts.

Longwall mining. The most productive underground mining method in the United States. A rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the roof of the mine while the drum advances through the coal. Chain conveyors then move the loosened coal to a standard underground mine conveyor system for delivery to the surface.

Metallurgical coal. The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as “met” coal, its quality depends on four important criteria: volatility, which affects coke yield; the level of impurities including sulfur and ash, which affect coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Met coal typically has a particularly high BTU but low ash and sulfur content.

Northern Appalachia or NAPP. Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.

Operating Margin. Coal revenues less cost of coal sales and freight and handling costs.

Powder River Basin or PRB. Coal producing area in northeastern Wyoming and southeastern Montana.

Preparation plant. A preparation plant is a facility for crushing, sizing and washing coal to remove impurities and prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content. A preparation plant is usually located on a mine site, although one plant may serve several mines.

Probable reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

Productivity. As used in this report, refers to clean metric tons of coal produced per underground man hour worked, as published by the MSHA.

Proven reserves. Reserves for which 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 the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

Reclamation. The process of restoring land and the environment to their original state following mining activities. The process commonly includes “recontouring” or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually underway before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law.

Recoverable reserves. Metric tons of mineable coal that can be extracted and marketed after deduction for coal to be left behind within the seam (i.e., pillars left to hold up the ceiling, coal not economical to recover within the mine, etc.) and adjusted for reasonable preparation and handling losses.

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

Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place.

Sulfur. One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product of coal combustion.

Surface mine. A mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil.

Thermal coal. Coal used by power plants and industrial steam boilers to produce electricity, steam or both. It generally is lower in BTU heat content and higher in volatile matter than metallurgical coal.


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Tons. A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is equal to 2,240 pounds; a “metric” ton (or “ tonne ”) is approximately 2,205 pounds. Tonnage amounts in this prospectus are stated in short tons, unless otherwise indicated.

Unassigned reserves. Coal that is likely to be mined in the future, but which is not considered Assigned reserves.

Underground mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car and conveyor to the surface.


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Item 1A. Risk Factors

Investment in our common stock is subject to various risks, including risks and uncertainties inherent in our business. The following sets forth factors related to our business, operations, financial position, or future financial performance or cash flows, which could cause an investment in our securities to decline and result in a loss. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

Risk Relating to the Alpha Merger
We may not realize the expected business or financial benefits of the Alpha Merger. Integration of the companies could prove difficult, which could disrupt our business, dilute stockholder value and adversely affect our operating results and the market value of our common stock.

We may not realize the expected business or financial benefit from the integration of the Contura and Alpha operations. These potential difficulties could cause the results of the Alpha Merger to differ from our expectations, including, but not limited to, the following:
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failure to implement our business plan for the combined business or to achieve anticipated production, revenue or profitability targets;
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higher than expected costs, lower than expected cost savings and/or a need to allocate resources to manage unexpected operating difficulties;
•
difficulties in, and the cost of, integrating operations, technologies, services, platforms and personnel;
•
diversion of attention and resources of management;
•
inability to generate sufficient revenue to offset Merger or investment costs;
•
potential unknown liabilities associated with the merged businesses; and
•
challenges relating to the structure of an investment, such as governance, accountability and decision-making conflicts that may arise in the context of a Merger.

Difficulties like these could disrupt our business, dilute stockholder value and adversely affect our operating results and the market value of our common stock.

Risks Relating to Our Industry and the Global Economy
Declines in coal prices would reduce our revenues and adversely affect our operating results, cash flows, financial condition, stock price and the value of our coal reserves.
Our results of operations are substantially dependent upon the prices we receive for our coal. Those prices depend upon factors beyond our control (some of which are described in more detail in other risk factors below), including:
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the demand for domestic and foreign coal and coke, which depends significantly on the demand for electricity and steel;
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the price and availability of natural gas, other alternative fuels and alternative steel production technologies;
•
domestic and foreign economic conditions, including economic downturns and the strength of the global and U.S. economies;
•
the consumption pattern of industrial customers, electricity generators and residential users;
•
the legal, regulatory and tax environment for our industry and those of our customers;
•
adverse weather, climactic or other natural conditions, including natural disasters;
•
the quantity, quality and pricing of coal available in the resale market;
•
the effects of worldwide energy conservation or emissions measures;
•
competition from other suppliers of coal and other energy sources; and
•
the proximity to and availability, reliability and cost of transportation and port facilities.

Declines in coal prices in the U.S. and other countries may materially adversely affect our operating results and cash flows, as well as the value of our coal reserves and may cause the number of risks that we face to increase in likelihood, magnitude and duration.

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Lower demand for metallurgical coal (or “met coal”) by U.S. and foreign steel producers, including negative effects resulting from the imposition of tariffs, could reduce the price of our met coal, which would reduce our revenues.
Contura produces met coal that is sold directly to both U.S. and foreign steel industry customers and indirectly to foreign steel industry customers through U.S.-based companies. Met coal accounted for approximately 83.2% of our coal revenues (excluding freight and handling revenues) for the year ended December 31, 2018. Any deterioration in conditions in the U.S. or foreign steel industries, including the demand for steel and the continued financial viability of the industry, could reduce the demand for our met coal and could impact the collectability of our accounts receivable from U.S. or foreign steel industry customers.
The demand for foreign-produced steel both in foreign markets and in the U.S. market also depends on factors such as tariff rates on steel. On March 8, 2018, President Trump signed proclamations imposing a 25 percent tariff on imports of steel mill products and a 10 percent tariff on imports of wrought and unwrought aluminum. Contura’s export customers include foreign steel producers who may be affected by the tariffs to the extent their production is imported into the U.S. Conversely, demand for met coal from our domestic customers may increase. Retaliatory tariffs by foreign nations have already limited international trade and may adversely impact global economic conditions.
In addition, the steel industry’s demand for met coal is affected by a number of factors, including the variable nature of that industry’s business, technological developments in the steel-making process and the availability of substitutes for steel, such as aluminum, composites and plastics. The U.S. steel industry increasingly relies on processes to make steel that do not use coke, such as electric arc furnaces or pulverized coal processes. If this trend continues, the amount of met coal that we sell and the prices that we receive for it could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves. Lower demand for met coal in international markets could reduce the amount of met coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves. Foreign government policies related to coal production and consumption could negatively impact pricing and demand for our products.
Lower demand for thermal coal by North American electric power generators could reduce the price of our thermal coal, which would reduce our revenues.
Thermal coal accounted for approximately 16.8% of our coal revenues (excluding freight and handling revenues) for the year ended December 31, 2018. The majority of our sales of thermal coal were to U.S. electric power generators. The North American demand for thermal coal is affected primarily by:
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the overall demand for electricity, which is in turn influenced by the global economy and the weather, among other factors (for example, mild North American winters typically result in lower demand);
•
the availability, quality and price of competing fuels, such as natural gas, nuclear fuel, oil and alternative energy sources such as wind, solar, and hydroelectric power, which may change over time as a result of, among other things, technological developments and state or federal regulatory or statutory fuel subsidies or energy use mandates;
•
increasingly stringent environmental and other governmental regulations, including air emission standards for coal-fired power plants; and
•
the coal inventories of utilities.

Many North American electric power generators have shifted from coal to natural gas-fired power plants. Despite ongoing advancements in the availability and deployment of advanced coal and emissions reduction technologies, we expect that new power plants in the near-term will be fired by natural gas because natural gas-fired plants are less expensive to construct than coal-fired plants and natural gas is a cleaner-burning fuel, with plentiful supplies and low cost at the current time. Increasingly stringent regulations have also reduced the number of new power plants being built, particularly coal-fired power plants. A reduction in the amount of coal consumed by North American electric power generators would reduce the amount of thermal coal that we sell and the price that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves. In addition, uncertainty caused by federal and state regulations could cause thermal coal customers to be uncertain of their coal requirements in future years, which could adversely affect our ability to sell coal to such customers under multi-year sales contracts.
Competition within the coal industry may adversely affect our ability to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.
We compete with numerous other coal producers in various regions of the U.S. for domestic and international sales. We also compete in international markets against coal producers in other countries. International demand for U.S. coal exports also affects coal demand in the U.S. This competition affects domestic and foreign coal prices and our ability to retain or attract coal

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customers. Increased competition from the Illinois basin, the threat of increased production from competing mines, and natural gas price declines with large basis differentials have all historically contributed to soft market conditions.
In the past, high demand for coal and attractive pricing brought new investors to the coal industry, leading to the development of new mines and added production capacity. Subsequent overcapacity in the industry contributed, and may in the future contribute, to lower coal prices.
Potential changes to international trade agreements, trade concessions, foreign currency fluctuations or other political and economic arrangements may benefit coal producers operating in countries other than the United States. Additionally, North American steel producers face competition from foreign steel producers, which could adversely impact the financial condition and business of our customers. We cannot assure you that we will be able to compete on the basis of price or other factors with companies that in the future may benefit from favorable foreign trade policies or other arrangements. Coal is sold internationally in U.S. dollars and, as a result, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide our foreign competitors with a competitive advantage. If our competitors’ currencies decline against the U.S. dollar or against our foreign customers’ local currencies, those competitors may be able to offer lower prices for coal to customers. Furthermore, if the currencies of our overseas customers were to significantly decline in value in comparison to the U.S. dollar, those customers may seek decreased prices for the coal we sell to them. Consequently, currency fluctuations could adversely affect the competitiveness of our coal in international markets, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Business-Competition.” Similarly, currency fluctuations could adversely affect demand for U.S. steel.
Lower demand for U.S. coal exports would reduce our foreign sales, could negatively impact our revenues and could result in downward pressure on domestic coal prices.

Coal export revenues accounted for approximately 79.3% of our total coal revenues (excluding freight and handling revenues) for the year ended December 31, 2018. In addition to the factors described above, demand for and viability of U.S. coal exports is dependent upon a number of factors outside of our control, including ocean freight rates and port and shipping capacity.

In addition, trade conflicts between the United States and other nations that result in the imposition of barriers to trade, such as import tariffs, could materially and adversely affect the international demand and pricing for our coal. The current presidential administration has taken actions, including imposing tariffs on certain goods imported into the U.S., that have resulted in other nations adopting retaliatory measures such as the imposition of tariffs upon goods imported from the U.S. into those nations. China and Turkey, for example, have imposed tariffs upon the importing of coal from the U.S. The imposition of these trade barriers by other nations has already resulted in adverse effects upon our international sales of coal, including reduced demand and prices. If these barriers endure, or are enhanced, our coal exports may further decline, and increased domestic supply could cause competition among coal producers in the U.S. to intensify, potentially resulting in additional downward pressure on domestic coal prices and our business, financial condition and results of operations.

Competition with natural gas and renewable energy sources, and factors affecting these industries could have an adverse impact on coal demand.

Our coal competes with natural gas and renewable energy sources, and the price of these sources can therefore affect coal sales. The natural gas market has been volatile historically and prices in this market are subject to wide fluctuations in response to relatively minor changes in supply and demand. Changes in supply and demand could be prompted by any number of factors, such as worldwide and regional economic and political conditions; the level of global exploration, production and inventories; natural gas prices; and transportation availability. If natural gas prices decline significantly, it could lead to reduced coal sales and have a material adverse effect on our financial condition, results of operations and cash flows.
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.


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Future governmental policy changes in China may be detrimental to the global coal market and impact our business, financial condition or results of operations.
The Chinese government has from time to time implemented regulations and promulgated new laws or restrictions on their domestic coal industry, sometimes with little advance notice, which may impact worldwide coal demand, supply and prices. The recent rise from historic lows in prices was driven in part by government policies in China that curbed domestic supply. During the past several years, the Chinese government has initiated a number of anti-smog measures aimed at reducing hazardous air emissions through temporary production capacity restrictions within the steel, coal and coal-fired power sectors. It is possible that policy changes from Beijing may be detrimental to the global coal market and, thus, impact our business, financial condition or results of operations.
In addition, similar actions by government entities in countries that produce and/or consume large quantities of coal and other energy related commodities, such as India, may have a material impact on the prices at which we sell our product.
The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues and profitability.
Our largest customer during the year ended December 31, 2018 accounted for approximately 16.7% of our total coal revenues, and coal sales to our 10 largest customers accounted for approximately 60.1% of our total coal revenues. These customers may not continue to purchase coal from us as they have previously, or at all. If these customers were to reduce their purchases of coal significantly or if we were unable to sell coal to them on terms as favorable to us, our revenues and profitability could suffer.
We may not be able to extend our existing long-term supply contracts or enter into new ones, and our existing supply contracts may contain certain provisions that may reduce protection from short-term coal price volatility, which could adversely affect the profitability of our operations.
A substantial portion of our thermal coal is sold under long-term contracts. When our current contracts with customers expire or are otherwise renegotiated, our customers may decide to purchase fewer tons of coal than in the past or on terms, including pricing terms, that are not as favorable to us as the terms under our current agreements.
Further, in large part as a result of increasing and frequently changing regulation, and natural gas pricing, electric power generators are increasingly less willing to enter into long-term coal supply contracts, instead purchasing higher percentages of coal under short-term supply contracts. This industry shift away from long-term supply contracts could adversely affect us and the level of our revenues. For example, our having fewer customers with a contractual obligation to purchase coal from us increases the risk that we will not have a consistent market for our production and may require us to sell more coal in the spot market, where prices may be lower than we would expect a customer to pay for a contractually committed supply. Spot market prices also tend to be more volatile than contractual prices, which could result in decreased revenues. Our met coal supply contracts are typically priced on an annual, quarterly or spot basis, and therefore our met coal sales are particularly sensitive to repricing risk.
Generally, our long-term thermal coal agreements contain committed volumes and fixed prices for a certain number of periods during which thermal coal will be delivered. However, some of our long-term thermal coal agreements do not provide for a fixed price through the life of the agreement. Those agreements contain price negotiation and similar provisions for upcoming unpriced contract periods, with negotiations generally considering either then current market prices and/or relevant market indices. Failure of the parties to agree on a price can lead to termination of the contract or litigation, the outcome of which would be uncertain. Further, during periods of economic weakness, some of our customers experience lower demand for their products and services and may be unwilling to take all of their contracted tonnage or may request a lower price. Customers may make similar requests when market prices drop significantly. Any adjustment or negotiation leading to a significantly lower contract price could result in decreased revenues. Accordingly, supply contracts with terms of one year or more may provide only limited protection during adverse or volatile market conditions.
Our ability to collect payments from our customers could be impaired if their creditworthiness and financial health deteriorate.
Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness and financial health of our customers. Competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default. In recent years, downturns in the economy and disruptions in the global financial markets have, from time to time, affected the creditworthiness of our customers and limited their liquidity and credit availability. In addition, our customer base may change with deregulation as utilities sell or transfer their power plants to their

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non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear for customer payment default. These new power plant owners or operators may have credit ratings that are below investment grade or may become below investment grade after we enter into contracts with them.
Customers in other countries may 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. For the year ended December 31, 2018 we derived 79.3% of our total coal revenues, excluding freight and handling revenues, from coal sales made to customers outside the U.S.
Economic downturns and disruptions in the global financial markets have had, and could in the future have, a material adverse effect on the demand for and price of coal, which could have a material negative effect on our sales, costs, margins and profitability and ability to obtain financing.
Economic downturns and disruptions in the global financial markets have from time to time resulted in, among other things, extreme volatility in securities prices, severely diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others, including real estate. These sorts of disruptions, and in particular the tightening of credit in financial markets, could adversely affect our customers’ ability to obtain financing for operations and result in a decrease in demand, lower coal prices, the cancellation of some orders for our coal and the restructuring of agreements with some of our customers. Changes in the value of the U.S. dollar relative to other currencies, particularly where imported products are required for the mining process, could result in materially increased operating expenses. Any prolonged global, national or regional economic recession or other similar events could have a material adverse effect on the demand for and price of coal, on our sales, margins and profitability, and on our own ability to obtain financing. We are unable to predict the timing, duration and severity of any potential future disruptions in financial markets and potential future adverse economic conditions in the U.S. and other countries and the impact these events may have on our operations and the industry in general.
Risks Relating to Regulatory and Legal Developments
The extensive regulation of the mining industry imposes significant costs on us, and future regulations or violations could increase those costs or limit our ability to produce coal.
Our operations are subject to a wide variety of federal, state and local environmental, health and safety, transportation, labor and other laws and regulations relating to matters such as:
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blasting;
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controls on emissions and discharges;
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the effects of operations on surface water and groundwater quality and availability;
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the storage, treatment and disposal of wastes;
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the remediation of contaminated soil, surface water and groundwater;
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surface subsidence from underground mining;
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the classification of plant and animal species near our mines as endangered or threatened species;
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the reclamation of mined sites; and
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employee health and safety, and benefits for current and former employees (described in more detail below).

These laws and regulations are becoming increasingly stringent. For example:
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federal and state agencies and citizen groups have increasingly focused on the amount of selenium and other constituents in mine-related water discharges;
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MSHA and the states of Pennsylvania, Virginia and West Virginia have implemented and proposed changes to mine safety and health requirements to impose more stringent health and safety controls, enhance mine inspection and enforcement practices, increase sanctions, and expand monitoring and reporting; and
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GHG emissions is being considered that could increase our costs, require additional controls, or compel us to limit our current operations.

In addition, these laws and regulations require us to obtain numerous governmental permits and comply with the requirements of those permits (described in more detail below).
We incur substantial costs to comply with the laws, regulations and permits that apply to our mining and other operations, and to address the outcome of inspections. The required compliance and actions to address inspection outcomes are often time-consuming and may delay commencement or continuation of exploration or production. In addition, due in part to the extensive and comprehensive regulatory requirements, violations of laws, regulations and permits occur at our operations from time to

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time and may result in significant costs to us to correct the violations, as well as substantial civil or criminal penalties and limitations or shutdowns of our operations. We are also required to comply with the November 2014 Consent Decree with EPA and several government agencies. See “Environmental and Other Regulatory Matters-Clean Water Act-Wastewater Discharge.”
MSHA and state regulators may also order the temporary or permanent closing of a mine in the event of certain violations of safety rules, accidents or imminent dangers. In addition, regulators may order changes to mine plans or operations due to their interpretation or application of existing or new laws or regulations. Any required changes to mine plans or operations may result in temporary idling of production or addition of costs.
These factors have had and will continue to have a significant effect on our costs of production and competitive position, and as a result on our results of operations, cash flows and financial condition. New laws and regulations, as well as future interpretations or different enforcement of existing laws and regulations, may have a similar or more significant impact on us, including delays, interruptions or a termination of operations.
Climate change or carbon dioxide emissions reduction initiatives could significantly reduce the demand for coal and reduce the value of our coal assets.
Global climate issues continue to attract considerable public and scientific attention. Numerous reports, such as the Fourth and Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, and in particular the emissions of GHG, such as carbon dioxide and methane, on global climate issues. Combustion of fossil fuels like coal results in the creation of carbon dioxide, which is emitted into the atmosphere by coal end users such as coal-fired electric power generators, coke plants and steelmaking plants, and, to a lesser extent, by the combustion of fossil fuels by the mining equipment we use. In addition, coal mining can release methane from the mine, directly into the atmosphere. Concerns associated with global climate change, and GHG emissions reduction initiatives designed to address them, have resulted, and are expected to continue to result, in decreased coal-fired power plant capacity and utilization, phasing out and closing many existing coal-fired power plants, reducing or eliminating construction of new coal-fired power plants in the United States and certain other countries, increased costs to mine coal, and decreased demand and prices for coal.
Emissions from coal consumption and production are subject to pending and proposed regulations as part of regulatory initiatives to address global climate change and global warming. Various international, federal, regional, foreign and state proposals are currently in place or being considered to limit emissions of GHGs, including possible future U.S. treaty commitments, new federal or state legislation, and regulation under existing environmental laws by the EPA and other regulatory agencies and litigation by private parties. These include:
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the 2015 Paris climate summit agreement, which resulted in voluntary commitments by 197 countries (although on June 1, 2017, the Trump administration announced that the U.S. will withdraw from the agreement) to reduce their GHG emissions and could result in additional firm commitments by various nations and states with respect to future GHG emissions;
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federal regulations such as the CPP, which is currently stayed by the U.S. Supreme Court, and the ACE Rule, which has been proposed to replace the CPP, that require reductions in emissions from existing fossil fuel-fired power plants, and new source performance standards for GHG emissions for new, modified or reconstructed fossil fuel-fired power plants (Power Plant NSPS), which require the use of partial carbon capture and sequestration for fossil fuel-fired steam generating units (although a proposed revision to the Power Plant NSPS would revise this requirement, as discussed below), or any regulation that replaces them;
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state and regional climate change initiatives implementing renewable portfolio standards or cap-and-trade schemes;
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challenges to or denials of permits for new coal-fired power plants or retrofits to existing plants by state regulators and environmental organizations due to concerns related to GHG emissions from the new or existing plants; and
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private litigation against coal companies or power plant operators based on GHG-related concerns.

On March 28, 2017, President Trump signed the Executive Order for Promoting Energy Independence and Economic Growth (“March 2017 Executive Order”) that directed the EPA to review and, if appropriate, suspend, revise or rescind, both the CPP and the Power Plant NSPS as necessary to ensure consistency with the goals of energy independence, economic growth and cost-effective environmental regulation. On April 4, 2017, the EPA announced in the Federal Register that it is initiating its review of the CPP and the Power Plant NSPS. On April 28, 2017, the United States Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) paused legal challenges to both the CPP and the Power Plant NSPS for 60 days to allow parties in each of those cases to brief the court on whether the case should be remanded to the agency or kept on hold and in a series of orders since, has continued to hold the cases in abeyance while the EPA rulemaking regarding the CPP and the Power Plant NSPS continues. In December 2018, EPA proposed to revise the Power Plant NSPS to replace its

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designation of partial carbon capture and storage as the best system of emission reduction with less stringent standards focusing on improvements in efficiency and operating practices.
In October 2017, the EPA issued a proposed rule to rescind the CPP, and on August 31, 2018, the EPA published the ACE Rule, a proposed replacement of the CPP. The ACE Rule would focus on reducing GHG emissions from existing coal-fired power plants by requiring states to mandate the implementation of a range of technologies at power plants designed to improve their heat rate (i.e., decrease the amount of fuel necessary to generate the same amount of electricity). The ACE Rule was subject to a 60-day comment period, which ended on October 31, 2018. The outcome of these rulemakings is uncertain and likely to be subject to extensive notice, comment and litigation. More stringent standards for carbon dioxide pollution as a result of these rulemakings could further reduce demand for coal, and our business would be adversely impacted.
In addition, certain banks and other financing sources have taken actions to limit available financing for the development of new coal-fueled power plants, which also may adversely impact the future global demand for coal. Further, there have been recent efforts by members of the general financial and investment communities, such as investment advisors, sovereign wealth funds, public pension funds, universities and other groups, to divest themselves and to promote the divestment of securities issued by companies involved in the fossil fuel extraction market, such as coal producers. Those entities also have been pressuring lenders to limit financing available to such companies. These efforts may adversely affect the market for our securities and our ability to access capital and financial markets in the future.
Furthermore, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation. These efforts, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, and consumer and corporate preferences for non-coal fuel sources, could cause coal prices and sales of our coal to materially decline and could cause our costs to increase.
Any future laws, regulations or other policies or initiatives 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. Considerable uncertainty is associated with these regulatory initiatives and legal developments, as the content of proposed legislation and regulation is not yet fully determined, many of the new regulatory initiatives remain subject to governmental and judicial review, and, with respect to federal initiatives, the current U.S. presidential administration and/or Congress may further impact their development. We routinely attempt to evaluate the potential impact on us of any proposed laws, regulations or policies, which requires that we make several material assumptions. From time to time, we determine that the impact of one or more such laws, regulations or policies, if adopted and ultimately implemented as proposed, may result in materially adverse impacts on our operations, financial condition or cash flow; however, we often are not able to reasonably quantify such impacts.
In general, any laws, regulations or other policies aimed at reducing GHG emissions have imposed and are likely to continue to impose significant costs on many coal-fired power plants, steel-making plants and industrial boilers, which may make them unprofitable. Accordingly, some existing power generators have switched to other fuels that generate fewer emissions and others are likely to switch, some power plants have closed and others are likely to close, and fewer new coal-fired plants are being constructed, all of which reduce demand for coal and the amount of coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.
Other extensive environmental laws, including existing and potential future legislation, treaties and regulatory requirements relating to air emissions, waste management and water discharges, affect our customers and could further reduce the demand for coal as a fuel source and cause prices and sales of our coal to materially decline.
Our customers’ operations are subject to extensive laws and regulations relating to environmental matters, including air emissions, wastewater discharges and the storage, treatment and disposal of wastes; and operational permits. In particular, the Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from fossil-fuel fired power plants, which are the largest end-users of our thermal coal. A series of more stringent requirements will or may become effective in coming years, including:
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implementation of the current and more stringent proposed ambient air quality standards for sulfur dioxide, nitrogen oxides, particulate matter and ozone, including the EPA’s issuance of NAAQS in October 2015 of a more stringent ambient air quality standard for ozone and the EPA’s determinations of attainment designations with respect to these rules;
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implementation of the EPA’s CSAPR to significantly reduce nitrogen oxide and sulfur dioxide emissions from power plants in 28 states, and the CSAPR Update Rule, issued in September 2016, requiring further reductions in nitrogen oxides in 2017 in 22 states subject to CSAPR during the summertime ozone season;

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continued implementation of the EPA’s MATS, which impose stringent limits on emissions of mercury and other toxic air pollutants from electric power generators, issued in December 2011 and in effect pending completion of judicial review proceedings and subject to a new draft rule proposed in December 2018 that reverses certain findings that served as the basis for MATS;
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implementation of the EPA’s August 2014 final rule on cooling water intake structures for power plants;
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more stringent EPA requirements governing management and disposal of coal ash pursuant to a rule finalized in December 2014 and new amendments effective as of August 2018; and
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implementation of the EPA’s November 2015 final rule setting effluent discharge limits on the levels of metals that can be discharged from power plants.

These environmental laws and regulations impose significant costs on our customers, which are increasing as these requirements become more stringent. These costs make coal more expensive to use and make it a less attractive fuel source of energy for our customers. Accordingly, some existing power generators have switched to other fuels that generate fewer emissions and others are likely to switch, some power plants have closed and others are likely to close, and fewer coal-fired plants are being constructed, all of which reduce demand for coal, the amount of coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

In addition, regulations regarding sulfur dioxide emissions under the Clean Air Act, including caps on emissions and the price of emissions allowances, have a potentially significant impact on the demand for our coal based on its sulfur content. We sell both higher sulfur and low sulfur coal. More widespread installation by power generators of technology that reduces sulfur emissions may make high sulfur coal more competitive with our low sulfur coal. Decreases in the price of emissions allowances could have a similar effect. Significant increases in the price of emissions allowances could reduce the competitiveness of higher sulfur coal compared to low sulfur coal and possibly natural gas at power plants not equipped to reduce sulfur dioxide emissions. Any of these consequences could result in a decrease in revenues from some of our operations, which could adversely affect our business and results of operations.
Our long-term growth, and particularly that of our thermal coal platform, may be materially adversely impacted if economic, commercially available carbon mitigation technologies are not developed and adopted in a timely manner.
Federal or state laws or regulations may be adopted that would impose new or additional limits on the emissions of GHGs, including, but not limited to, CO2 from electric generating units using fossil fuels such as coal or natural gas. In order to comply with such regulations, electric generating units using fossil fuels may be required to implement certain emissions control technologies. For example, pursuant to the Power Plant NSPS finalized by the EPA in August 2015, the EPA designated partial carbon capture and sequestration as the best system of emission reduction for newly constructed fossil fuel-fired steam generating units at power plants to employ to meet the standard. However, there is a risk that such technology, which may include storage, conversion, or other commercial use for captured carbon, may not be commercially practical in limiting emissions as otherwise required by the rule or similar rules that may be proposed in the future. Although in December 2018, EPA proposed to revise the Power Plant NSPS to replace its designation of carbon capture and storage as the best system of emissions reduction with less stringent standards, this proposal may be subject to change and administrative and legal challenges. If such legislative or regulatory programs are adopted or remain in place, and economic, commercially available carbon capture or other carbon mitigation technologies for power plants are not developed or adopted in a timely manner, it would negatively affect our customers and would further reduce the demand for coal as a fuel source, causing coal prices and sales of our coal to decline, perhaps materially.
The U.S. Internal Revenue Service could withhold tax refunds and refundable credits and assert a right to setoff against pre-petition claims of the U.S. government during the Alpha Bankruptcy, which could have a material adverse effect upon the Company’s assets.

As of December 31, 2018, the Company has recorded approximately $68.8 million of federal income tax receivable and approximately $68.8 million of federal deferred tax asset related to refundable Alternative Minimum Tax (AMT) credits. In addition, the Company has recorded a non-current federal income tax receivable of approximately $43.8 million related to a net operating loss (NOL) carryback claim. Because the U.S. government was a creditor in the Predecessor Alpha bankruptcy proceedings, it is possible that the U.S. Internal Revenue Service (IRS) could withhold some or all of the tax refund attributable to the NOL carryback claim and the AMT refundable credits and assert a right to set off the tax refund and refundable credits against the U.S. government’s pre-petition bankruptcy claims. If the IRS were to take such actions, the Company would vigorously defend its position. However, if the Company were unsuccessful, there could be a material, adverse effect upon the Company’s assets.


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Decreases in consumer demand for electricity and changes in general energy consumption patterns attributable to energy conservation trends could adversely affect our business, financial condition and results of operations.
Due to efforts to promote energy conservation in recent years, there is a risk that both the demand for electricity and the general energy consumption patterns of consumers worldwide will decrease. The ability of energy conservation technologies, public initiatives and government incentives to reduce electricity consumption or to support other forms of renewable energy could also lead to a reduction in the price of coal. If prices for coal are not competitive, our business, financial condition and results of operations may be materially harmed.
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 use certain hazardous materials, and from time to time we generate limited quantities of hazardous wastes. We may be subject to claims under federal or state law for toxic torts, natural resource damages and other damages as well as for the investigation and clean-up of soil, surface water, sediments, groundwater and other natural resources. Such claims may arise out of current or former conditions at sites that we own or operate, or formerly owned or operated, and at contaminated sites owned or operated by third parties to which we sent wastes for treatment, storage or disposal. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share.
We operate and maintain a number of coal slurry impoundments. These impoundments are subject to extensive regulation. Some slurry impoundments maintained by other coal mining operations have failed, causing extensive damage to the environment and natural resources, as well as liability for related personal injuries and property damages. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of resulting damages. 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, and potential third-party claims for personal injury, property damage or other losses. In addition, we may become subject to such claims related to surface expressions of methane gas, which can result from underground coal mining activities.
These and other environmental impacts that our operations may have, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could render continued operations at certain mines economically unfeasible or impractical or otherwise materially and adversely affect our financial condition and results of operations.
We may be unable to obtain and renew permits, mine plan modifications and approvals, leases or other rights necessary for our operations, which would reduce our production, cash flows and profitability.
Mining companies must obtain numerous regulatory permits that impose strict conditions on various environmental and safety matters in connection with coal mining. The permitting rules are complex and change over time, potentially in ways that may make our ability to comply with the applicable requirements more difficult or impractical or even preclude the continuation of ongoing operations or the development of future mining operations. The public, including special interest groups and individuals, have certain rights under various statutes to comment upon, submit objections to and otherwise engage in the permitting process, including bringing citizens’ lawsuits or administrative actions to challenge permits or mining activities. In states where we operate, applicable laws and regulations also provide that a mining permit or modification can, under certain circumstances, be delayed, refused or revoked if we or any entity that owns or controls or is under common ownership or control with us or is determined to be linked to us under OSM’s AVS, have unabated permit violations or have been the subject of permit or reclamation bond revocation or suspension. These regulations define certain relationships, such as owning over 50% of stock in an entity or having the authority to determine the manner in which the entity conducts mining operations, as constituting ownership and control. Certain other relationships are presumed to constitute ownership or control, including being an officer or director of an entity or owning between 10% and 50% of the mining operator. This presumption, in some cases, can be rebutted where the person or entity can demonstrate that it in fact does not or did not have authority directly or indirectly to determine the manner in which the relevant coal mining operation is conducted. Thus, past or ongoing violations of federal and state mining laws by us or by coal mining operations owned or controlled by our significant stockholders, directors or officers or by entities linked to us through OSM’s AVS could provide a basis to revoke existing permits and to deny the issuance of additional permits or modification or amendment of existing permits. This is known as being “permit-blocked.” In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.
As a result, the permitting process is costly and time-consuming, required permits may not be issued or renewed in a timely fashion (or at all), and permits that are issued may be conditioned in a manner that may restrict our ability to conduct our

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mining activities efficiently. In some circumstances, regulators could seek to revoke permits previously issued. We are required under certain permits to provide data on the impact on the environment of proposed exploration for or production of coal to governmental authorities.
In particular, certain of our activities require a dredge and fill permit from the COE under Section 404 of the CWA. In recent years, the Section 404 permitting process has been subject to increasingly stringent regulatory and administrative requirements and a series of court challenges, which have resulted in increased costs and delays in the permitting process.
In addition, in 2015, the EPA and the COE issued a final rule, now known as the CWR under the CWA that would further expand the circumstances when a Section 404 permit is needed. The CWR is the subject of extensive ongoing litigation and administrative proceedings and its current and future impact on our operations are the subject of significant uncertainty. The rule was subsequently stayed nationwide by the U.S. Court of Appeals for the Sixth Circuit during the pendency of several lawsuits challenging the CWR in the Sixth Circuit and several federal district courts. On January 22, 2018, the Supreme Court reversed the Sixth Circuit's decision, ruling that jurisdiction over challenges to the CWR rests with the federal district courts and not with the appellate courts, which was followed by the dissolution of the stay by the Sixth Circuit. On February 6, 2018, the EPA and COE published a rule that delayed applicability of the CWR for two years. However, on August 16, 2018, the federal court in South Carolina enjoined the rule, effectively reinstating the CWR in Virginia and Pennsylvania (where we have operations) and in 24 other states. The injunction is being challenged on appeal. However, our West Virginia operations remain unaffected by the CWR, due to separate injunctions issued by federal courts in Georgia and North Dakota applicable to West Virginia and 23 other states. On February 28, 2017, while challenges to the CWR were pending, President Trump signed an executive order directing the EPA and the COE to review the CWR for consistency with the goals of “promoting economic growth and minimizing regulatory uncertainty” and to consider a new rule that reflects Justice Scalia’s plurality opinion in the 2006 Supreme Court decision, Rapanos v. United States , that CWA jurisdiction attaches only to “navigable waters” and other waters with a relatively permanent flow, such as rivers or lakes. On March 6, 2017, the EPA and the COE published a Notice of Intent to review and rescind or revise the rule and on June 29, 2018 the EPA and the COE published a supplemental notice indicating their intention to repeal the CWR and providing a variety of reasons to support such a repeal. On December 11, 2018, EPA and USACE issued a pre-publication version and supporting documents for a proposed rule replacing the CWR (the proposal was formally published on February 14, 2019). In accordance with President Trump’s executive order, the proposed rule would define “waters of the United States” along the lines of Justice Scalia’s Rapanos opinion, which would have the effect of excluding from the definition certain wetlands and other water bodies that are covered by the definition pursuant to the CWR. The process to rescind or revise the CWR will likely be subject to extensive notice and comment and litigation.
Additionally, we may rely on nationwide permits under the CWA Section 404 program for some of our operations. These nationwide permits are issued every five years, and the 2017 nationwide permit program was recently reissued in January 2017. If we are unable to use the nationwide permits and require an individual permit for certain work, that could delay operations.
Many of our permits are subject to renewal from time to time, and renewed permits may contain more restrictive conditions than our existing permits. For example, many of our permits governing surface stream and groundwater discharges and impacts will be subject to new and more stringent conditions to address various new water quality requirements upon renewal over the next several years. Although we have no estimates at this time, our costs to satisfy these conditions could be substantial.
Future changes or challenges to the permitting and mine plan modification and approval process could cause additional increases in the costs, time, and difficulty associated with obtaining and complying with the permits and could delay or prevent commencing or continuing exploration or production operations, and as a result, adversely affect our coal production, cash flows and profitability.
Federal and state regulatory agencies have the authority to order any of our facilities to be temporarily or permanently closed under certain circumstances, which could materially adversely affect our ability to meet our customers’ demands.
Federal and state regulatory agencies have the authority following significant health and safety incidents, such as fatalities, to order a facility to be temporarily or permanently closed. If this were to occur, we may be required to incur capital expenditures to re-open the facility. In the event that these agencies order the closing of our facilities, our coal sales agreements and our take-or-pay contracts related to our export terminals may 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 facilities 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.

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We have obligations under various settlement agreements with state and federal agencies in relation to the Alpha Restructuring settlement and the failure to meet these obligations could result in the termination of such settlement agreements, the revocation of permits and regulatory or enforcement actions, among other things.
In connection with the Alpha Restructuring settlement, Alpha and Contura entered into a number of agreements with state and federal agencies regarding the funding, performance and bonding of reclamation and other environmental restoration obligations with respect to mine properties retained by Alpha under the Alpha Restructuring. These agreements have been amended from time to time in connection with sales by Alpha of certain of these properties. These agreements require Contura to make periodic payments to certain accounts designated to fund reclamation and other activities at various facilities and also impose bonding, reporting and other obligations. A failure by Contura to fulfill our obligations under these agreements could be considered an event of default which could result in, among other things, the cancellation of certain permits, a termination of the agreement, termination of the right to use the funds in the Restricted Cash Reclamation Account, the Water Treatment Restricted Cash Account or the Mitigation Account and the taking of any regulatory or enforcement action that an agency enforcing such default is permitted to take.
We are in the process of developing systems and procedures for internal control over financial reporting. We may not complete our development or implementation of these systems and procedures in a timely manner, or our internal controls or the disclosure controls related to them may have one or more material weaknesses, which may adversely affect the value of our common stock.
We are in the costly and challenging process of compiling the systems and processing the documentation necessary to implement and evaluate the effectiveness of our internal control over financial reporting. These activities may divert management’s attention from other business concerns. Further, during the development of these systems, it is possible that our financial statements could contain errors, which could have a material adverse effect on our business, financial condition, results of operations and cash flows, and cause investors to lose confidence in our reported results, thus affecting our ability to finance our business. To design, maintain and improve the effectiveness of these controls and procedures, we must commit significant resources, may be required to hire additional staff and need to continue to provide effective management oversight, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Certain U.S. federal income tax provisions currently available with respect to coal percentage depletion and exploration and development may be eliminated by future legislation.
From time to time, legislation is proposed that could result in the reduction or elimination of certain U.S. federal income tax provisions currently available to companies engaged in the exploration, development, and production of coal reserves. These proposals have included, but are not limited to: (1) the elimination of current deductions, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (2) the repeal of the percentage depletion allowance with respect to coal properties and (3) the repeal of capital gains treatment of coal and lignite royalties. The passage of these or other similar proposals could increase our taxable income and negatively impact our cash flows and the value of an investment in our common stock.
Changes in tax laws, particularly in the areas of non-income taxes, or obligations arising from audits of royalties previously paid to government entities, could cause our financial position and profitability to deteriorate.
We pay non-income taxes on the coal we produce. A substantial portion of our non-income taxes are levied as a percentage of gross revenues, while others are levied on a per ton basis. Further, liabilities could arise in connection with audits of royalties previously paid to government entities in connection with our former PRB operations. If such liabilities were to arise, or if non-income tax rates were to increase significantly, our results of operations could be materially and adversely affected.
Federal healthcare legislation could adversely affect our financial condition and results of operations.
In March 2010, the PPACA was enacted, impacting our costs of providing healthcare benefits to our eligible active and certain former employees and workers’ compensation benefits related to occupational disease resulting from coal workers’ pneumoconiosis (black lung). The PPACA has both short-term and long-term implications on benefit plan standards. Implementation of this legislation is expected to extend through 2022. In the short term, our healthcare costs could increase due to, among other things, an increase in the maximum age for covered dependents to receive benefits, changes to benefits for occupational disease related illnesses, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual. In the long term, our healthcare costs could increase due to, among other things, an excise tax on “high cost” plans and the elimination of annual dollar limits per covered individual.

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Beginning in 2022, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain governmental agencies will provide additional regulations or interpretations concerning the application of this excise tax. We will continue to evaluate the impact of the PPACA, including any new regulations or interpretations, as well as efforts to limit or repeal the PPACA.
Risks Relating to Our Operations
Our coal mining production and delivery is subject to conditions and events beyond our control that could result in higher operating expenses and decreased production and sales. The occurrence of a significant accident or other event that is not fully insured could adversely affect our business and operating results and could result in impairments to our assets.
Our coal production at our mines is subject to operating conditions and events beyond our control that could disrupt operations, affect production and the cost of mining for varying lengths of time and have a significant impact on our operating results. Adverse operating conditions and events that we have experienced in the past and/or may experience in the future include:
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changes or variations in geologic, hydrologic or other conditions, such as the thickness of the coal deposits and the amount of rock, clay or other non-coal material embedded in or overlying the coal deposit;
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mining, processing and loading equipment failures and unexpected maintenance problems;
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limited availability or increased costs of mining, processing and loading equipment and parts and other materials from suppliers;
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difficulties associated with mining under or around surface obstacles;
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unfavorable conditions with respect to proximity to and availability, reliability and cost of transportation facilities;
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adverse weather and natural disasters, such as heavy snows, heavy rains and flooding, lightning strikes, hurricanes or earthquakes;
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accidental mine water discharges, coal slurry releases and failures of an impoundment or refuse area;
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mine safety accidents, including fires and explosions from methane and other sources;
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hazards or occurrences that could result in personal injury and loss of life;
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a shortage of skilled and unskilled labor;
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security breaches or terroristic acts;
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strikes and other labor-related interruptions;
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delays or difficulties in, the unavailability of, or unexpected increases in the cost of acquiring, developing or permitting new acquisitions from the federal government and other new mining reserves and surface rights;
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competition and/or conflicts with other natural resource extraction activities and production within our operating areas;
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the termination of material contracts by state or other governmental authorities; and
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fatalities, personal injuries or property damage arising from train derailments, mined material or overburden leaving permit boundaries, underground mine blowouts, impoundment failures, subsidence or other unexpected incidents.

If any of these or other conditions or events occur in the future at any of our mines or affect deliveries of our coal to customers, they may increase our cost of mining, delay or halt production or sales to our customers, result in regulatory action or lead to customers initiating claims against us. Any of these consequences could adversely affect our operating results or result in impairments to our assets.
In addition, our mining operations are concentrated in a small number of material mines. As a result, the effects of any of these conditions or events may be exacerbated and may have a disproportionate impact on our results of operations and assets.
We maintain insurance policies that provide limited coverage for some, but not all, of these risks. Even where covered by insurance, these risks may not be fully covered and insurers may contest their obligations to make payments. Failures by insurers to make payments could have a material adverse effect on our cash flows, results of operations or financial condition.
A decline in demand for met coal would limit our ability to sell our high quality thermal coal as higher priced met coal, which would reduce our revenues and profitability, and could affect the economic viability of some of our mines with higher operating costs.
We are able to mine, process and market some of our coal reserves as either met coal or high-quality thermal coal. In deciding our approach to these reserves, we assess the conditions in the met and thermal coal markets, including factors such as the current and anticipated future market prices of met coal and thermal coal, the generally higher price of met coal as compared to thermal coal, the lower volume of saleable tons that results when producing coal for sale in the met market rather

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than the thermal market, the increased costs of producing met coal, the likelihood of being able to secure a longer term sales commitment for thermal coal and our contractual commitments to deliver different types of coal to our customers. A decline in demand for met coal relative to thermal coal could cause us to shift coal from the met market to the thermal market, thereby reducing our revenues and profitability.
Mining in Central and Northern Appalachia is more complex and involves more regulatory constraints than mining in other areas of the U.S., which could affect our mining operations and cost structures in these areas.
The geological characteristics of Northern and Central Appalachian coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available or, if available, may not be able to be mined at costs comparable to those of the depleting mines. In addition, compared to mines in other areas of the country, permitting, licensing and other environmental and regulatory requirements are more costly and time consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to use coal produced by, our mines in Northern and Central Appalachia.
Disruptions in transportation services and increased transportation costs could impair our ability to supply coal to our customers, reduce demand and adversely affect our business.
For the year ended December 31, 2018, 54.8% of our captive coal volume was transported from our shipping points to a vessel loading point or customer location by rail. Deterioration in the reliability of the service provided by rail carriers would result in increased internal coal handling costs and decreased shipping volumes, and if we are unable to find alternatives our business could be adversely affected. Some of our operations are serviced by a single rail carrier. Due to the difficulty in arranging alternative transportation, these operations are particularly at risk to disruptions, capacity issues or other difficulties with that carrier’s transportation services, which could adversely impact our revenues and results of operations.
We also depend upon trucks, beltlines, ocean vessels and barges to deliver coal to our customers. In addition, much of our eastern coal is transported from our mines to our loading facilities by trucks owned and operated by third parties. Disruption of any of these transportation services due to weather-related problems, mechanical difficulties, fuel and supply costs, strikes, lockouts, bottlenecks, terrorist attacks and other events could impair our ability to supply coal to our customers, resulting in decreased shipments and revenue. Disruption in shipment levels over longer periods of time could cause our customers to look to other sources for their coal needs, negatively affecting our revenues and results of operations.
An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production on a profit-making basis and could therefore adversely affect our revenues and earnings. Because transportation costs represent a significant portion of the total cost of coal for our customers, increases in transportation costs could also reduce overall demand for coal or make our coal production less competitive than coal produced from other sources or other regions.
Certain provisions in our coal supply agreements may result in economic penalties upon our failure to meet specifications.
Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as BTU, sulfur content, ash content, grindability, moisture and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Further, some of our coal supply agreements allow our customers to terminate the contract in the event of regulatory changes that restrict the type of coal the customer may use at its facilities or the use of that coal or increase the price of coal or the cost of using coal beyond specified limits. In addition, our coal supply agreements typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during specified events beyond the control of the affected party. As a result of these issues, we may not achieve the revenue or profit we expect to achieve from our coal supply agreements.
Expenditures for certain employee benefits could be materially higher than we have anticipated, which could increase our costs and adversely affect our financial results.
We are responsible for certain liabilities under a variety of benefit plans and other arrangements with employees. The unfunded status of these obligations as of December 31, 2018 included $182.0 million of workers’ compensation obligations, $180.8 million of pension obligations, and $92.2 million of black lung obligations. These obligations have been estimated based on assumptions including actuarial estimates, discount rates, and changes in health care costs. We could be required to expend greater amounts than anticipated. In addition, future regulatory and accounting changes relating to these benefits could result in increased obligations or additional costs, which could also have a material adverse effect on our financial results.

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Several states in which we operate consider changes in workers’ compensation laws from time to time, which, if enacted, could adversely affect us.
We require a skilled workforce to run our business. If we cannot hire qualified persons to meet replacement or expansion needs, we may not be able to achieve planned results.
Efficient coal mining using modern techniques and equipment requires skilled laborers with mining experience and proficiency as well as qualified managers and supervisors. The demand for skilled employees sometimes causes a significant constriction of the labor supply resulting in higher labor costs. We, along with the mining industry generally, are currently facing a shortage of experienced mechanics and certified electricians. When coal producers compete for skilled miners, recruiting challenges can occur and employee turnover rates can increase, which negatively affect operating efficiency and costs. If a shortage of skilled workers exists and we are unable to train or retain the necessary number of miners, it could adversely affect our productivity, costs and ability to expand production.
If the assumptions underlying our accruals for reclamation and mine closure obligations prove to be inaccurate, we could be required to expend greater amounts than anticipated.
SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as deep mining. We accrue for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharge where necessary. Our estimated total reclamation and mine-closing liabilities were $228.4 million as of December 31, 2018, based upon permit requirements and the historical experience at our operations, and depend on a number of variables involving assumptions and estimation and therefore may be subject to change, including the estimated future asset retirement costs and the timing of such costs, estimated proven reserves, assumptions involving profit margins of third-party contractors, inflation rates and discount rates. Furthermore, these obligations are primarily unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results and financial position could be adversely affected. In addition, significant changes from period to period could result in significant variability in our operating results, which could reduce comparability between periods and impact our liquidity. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates” for a description of our estimated costs of these liabilities.
Estimates of our economically recoverable coal reserves involve uncertainties, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs, decreased profitability and asset impairments.
We base our estimates of our economically recoverable coal reserves on engineering, economic and geological data assembled and analyzed by our staff, including various engineers and geologists, and periodically reviewed by outside firms. Our estimates as to the quantity and quality of the coal in our reserves are updated annually to reflect production of coal from the reserves and new drilling, engineering or other data. These estimates depend upon a variety of factors and assumptions, many of which involve uncertainties and factors beyond our control and may vary considerably from actual results, such as:
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geological and mining conditions that may not be fully identified by available exploration data or that may differ from experience in current operations;
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historical production from the area compared with production from other similar producing areas;
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the assumed effects of regulation and taxes by governmental agencies; and
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assumptions about coal prices, operating costs, mining technology improvements, development costs and reclamation costs.

For these reasons, estimates of the economically recoverable quantities and qualities attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of net cash flows expected from particular reserves prepared by different engineers or by the same engineers at different times may vary substantially. In addition, actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our reserves may vary materially from estimates. Accordingly, our estimates may not accurately reflect our actual reserves. Any inaccuracy in our reserve estimates could result in lower than expected revenues, higher than expected costs, decreased profitability and asset impairments.
Our business will be adversely affected if we are unable to timely develop or acquire additional coal reserves that are economically recoverable.
Our profitability depends substantially on our ability to mine in a cost-effective manner coal reserves of the quality our customers need. Although we have coal reserves that we believe could support current production levels for more than 35 years, we have not yet developed the mines for all our reserves. We may not be able to mine all of our reserves as profitably as

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we do at our current operations. Under adverse market conditions, some reserves could not be mined profitably at all. In addition, in order to develop our reserves, we must receive various governmental permits. As discussed above, some of these permits are becoming increasingly more difficult and expensive to obtain and the review process continues to lengthen. We may be unable to obtain the necessary permits on terms that would permit us to operate profitably or at all.
Because our reserves are depleted as we mine our coal, our future success and growth depend in part on our ability to timely acquire additional coal reserves that are economically recoverable. Our planned development projects and acquisition activities may not result in significant additional reserves, and we may not succeed in developing new mines or expanding existing mines beyond our existing reserves. Replacement reserves may not be available when required or, if available, may not be able to be mined at costs comparable to those of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves that we now own or subsequently acquire, which may adversely affect our profitability and financial condition. Exhaustion of reserves at particular mines also may have an adverse effect on our operating results due to lost production capacity from diminished or discontinued operations at those mines, as well as lay-offs, write-off charges and other costs, potentially causing an adverse effect that is disproportionate to the percentage of overall production represented by those mines. Our ability to acquire other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates available on commercially reasonable terms, among other factors. If we are unable to replace or increase our coal reserves on acceptable terms, our production and revenues will decline as our reserves are depleted.
If we are unable to acquire surface rights to access our coal reserves, we may be unable to obtain a permit to mine coal we own and may be required to employ expensive techniques to mine around those sections of land we cannot access in order to access other sections of coal reserves, which could materially and adversely affect our business and our results of operations.
After we acquire coal reserves, we are required to obtain a permit to mine the reserves through the applicable state agencies prior to mining the acquired coal. In part, permitting requirements provide that, under certain circumstances, we must obtain surface owner consent if the surface estate has been severed from the mineral estate, which is commonly known as a “severed estate.” At certain of our mines where we have obtained the underlying coal and the surface is held by one or more owners, we are engaged in negotiations for surface rights with multiple parties. If we are unable to successfully negotiate surface rights with any or all of these surface owners, or to do so on commercially reasonable terms, we may be denied a permit to mine some or all of our coal or may find that we cannot mine the coal at a profit. If we are denied a permit, this would create significant delays in our mining operations and materially and adversely impact our business and results of operations. Furthermore, if we decide to alter our plans to mine around the affected areas, we could incur significant additional costs to do so, which could increase our operating expenses considerably and could materially and adversely affect our results of operations.
If we are unable to complete permit transfers as expected or if there are complications in connection with the permit transfer process, it could materially and adversely affect our business and results of operations.
On December 8, 2017, Contura closed a transaction (“PRB Transaction”) with Blackjewel to sell the Eagle Butte and Belle Ayr mines located in the PRB, including applicable permits. Alpha similarly sold properties for which the permits are in the process of being transferred. During the permit transfer period we must maintain the required reclamation bonds and related collateral, which are off-balance sheet arrangements. A local citizens organization filed objections to the permit transfer with the Wyoming Environmental Quality Council in November, 2018. The objections are scheduled to be heard in May, 2019. The Company believes that the objections are without merit. If the permit transfer process is not completed as expected, however, or if there are complications in connection with the process, we will remain obligated to maintain these bonds and collateral, which could materially and adversely affect our business and our results of operations.
Our work force could become increasingly unionized in the future and our unionized or union-free work force could strike, which could adversely affect the stability of our production and reduce our profitability.
Approximately 84% of our total workforce and approximately 78% of our hourly workforce was union-free as of December 31, 2018. However, under the National Labor Relations Act, employees have the right at any time to form or affiliate with a union. Any further unionization of our employees or the employees of third-party contractors who mine coal for us could adversely affect the stability of our production and reduce our profitability.
Certain of Contura’s subsidiaries have wage agreements with the UMWA that are subject to termination by either the employer or the UMWA, without cause, on July 31, 2020.

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As is the case with our union-free operations, the union-represented employees could strike, which would disrupt our production, increase our costs and disrupt shipments of coal to our customers, and could result in the closure of affected mines, all of which could reduce our profitability.
Conflicts with competing holders of mineral rights and rights to use adjacent, overlying or underlying lands could materially and adversely affect our ability to mine coal or do so on a cost-effective basis.
Our operations at times face potential conflicts with holders of other mineral interests such as coalbed methane, natural gas and oil reserves. Some of these minerals are located on, or are adjacent to, some of our coal reserves and active operations, potentially creating conflicting interests between us and the holders of those interests. From time to time we acquire these minerals ourselves to prevent conflicting interests from arising. If, however, conflicting interests arise and we do not acquire the competing mineral rights, we may be required to negotiate our ability to mine with the holder of the competing mineral rights. Furthermore, the rights of third parties for competing uses of adjacent, overlying or underlying lands, such as oil and gas activity, coalbed methane, pipelines, roads, easements and public facilities, may affect our ability to operate as planned if our title is not superior or arrangements cannot be negotiated. If we are unable to reach an agreement with these holders of such rights, or to do so on a cost-effective basis, we may incur increased costs and our ability to mine could be impaired, which could materially and adversely affect our business and results of operations.
Provisions in our lease agreements, defects in title in our mine properties or loss of leasehold rights could limit our ability to recover coal from our properties or result in significant unanticipated costs.
We conduct a significant part of our mining operations on properties that we lease. Title to most of our leased properties and mineral rights is not thoroughly verified until a permit to mine the property is obtained, and in some cases, title is not verified at all. Accordingly, actual or alleged defects in title or boundaries may exist, which may result in the loss of our right to mine on the property or in unanticipated costs to obtain leases or mining contracts to allow us to conduct our mining operations on the property, which could adversely affect our business and profitability. Furthermore, some leases require us to produce a minimum quantity of coal and/or pay minimum production royalties. If those requirements are not met, the leasehold interest may terminate.
Decreased availability or increased costs of key equipment and materials, including certain items mandated by regulations, or of coal that we purchase from third parties, could impact our cost of production and decrease our profitability.
We depend on reliable supplies of mining equipment, replacement parts and materials such as explosives, diesel fuel, tires, steel, magnetite and other raw materials and consumables which, in some cases, do not have ready substitutes. Some equipment and materials are needed to comply with regulations, such as proximity detection devices on continuous mining machines. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies. Any significant reduction in availability or increase in cost of any mining equipment or key supplies could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows.
In addition, the prices we pay for these materials are strongly influenced by the global commodities markets. Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives and diesel and other liquid fuels. If the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses will increase, which could materially adversely impact our profitability. Some materials, such as steel, are needed to comply with regulatory requirements. Furthermore, operating expenses at our mining locations are sensitive to changes in certain variable costs, including diesel fuel prices, which is one of our largest variable costs. Our results depend on our ability to adequately control our costs. Any increase in the price we pay for diesel fuel will have a negative impact on our results of operations. A rapid or significant increase in the cost of these commodities could increase our mining costs because we have limited ability to negotiate lower prices.

We purchase coal from third parties, for use in coal blending and for other purposes, for which ready substitutes may not be immediately available. A significant reduction in availability or increase in cost of these supplies, or the failure of third party coal producers to provide them in a timely fashion, could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows.


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Some of our mines are operated by third-party contract mine operators, and our results of operations could be adversely affected if these operators fail to operate the mines effectively.

Some of our mines are operated by third-party contract mine operators. While we have certain contractual rights of oversight over these mines, which are operated under our permits, we do not control, and our employees do not participate in, the day-to-day operations of these mines. Operational difficulties at these mines, increased competition for contract miners from other coal producers and other factors beyond our control could affect the availability, cost and quality of coal produced for us by contractors. Disruption in our supply of contractor-produced coal could impair our ability to fill our customers’ orders or require us to pay higher prices to obtain the required coal from other sources. Any increase in the per-ton compensation for services we pay for the production of contractor-produced coal could increase our costs and therefore lower our earnings and adversely affect our results of operations.
Strategic transactions, including acquisitions, involve a number of risks, any of which could result in a material adverse effect on our business, financial condition or results of operations.
In the future, we may undertake strategic transactions such as the acquisition or disposition of coal mining and related infrastructure assets, interests in coal mining companies, joint ventures or other strategic transactions involving companies with coal mining or other energy assets. Our ability to complete these transactions is subject to the availability of attractive opportunities, including potential acquisition targets that can be successfully integrated into our existing business and provide us with complementary capabilities, products or services on terms acceptable to us, as well as general market conditions, among other things.
Risks inherent in these strategic transactions include:
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uncertainties in assessing the value, strengths, and potential profitability, and identifying the extent of all weaknesses, risks, contingent liabilities and other liabilities of acquisition candidates and strategic partners;
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the potential loss of key customers, management and employees of an acquired business;
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the ability to achieve identified operating and financial synergies from an acquisition or other strategic transactions in the amounts and on the time frame due to inaccurate assumptions underlying estimates of expected cost savings, the deterioration of general industry and business conditions, unanticipated legal, insurance and financial compliance costs, or other factors;
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the ability of management to manage successfully our exposure to pending and potential litigation and regulatory obligations;
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unanticipated increases in competition that limit our ability to expand our business or capitalize on expected business opportunities, including retaining current customers; and
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unanticipated changes in business, industry, market, or general economic conditions that differ from the assumptions underlying our rationale for pursuing the acquisition or other strategic transactions.

The ultimate success of any strategic transaction we may undertake will depend in part on our ability to continue to realize the anticipated synergies, business opportunities and growth prospects from those transactions. We may not be able to successfully integrate the companies, businesses or properties that we acquire, invest in or partner with. Problems that could arise from the integration of an acquired business may involve:
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coordinating management and personnel and managing different corporate cultures;
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applying our safety and environmental programs at acquired mines and facilities;
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establishing, testing and maintaining effective internal control processes and systems of financial reporting for the acquired business;
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the diversion of our management’s and our finance and accounting staff’s resources and time commitments, and the disruption of either our or the acquired company’s ongoing businesses;
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tax costs or inefficiencies; and
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inconsistencies in standards, information technology systems, procedures or policies.

Any one or more of these factors could cause us not to realize the benefits anticipated from a strategic transaction, adversely affect our ability to maintain relationships with clients, employees or other third parties or reduce our earnings.
Moreover, any strategic transaction we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or do both. Future transactions could also result in our assuming more long-term liabilities relative to the value of the acquired assets. Further, acquisition accounting rules require changes in certain assumptions made subsequent to the measurement period, as defined in current accounting standards, to be recorded in current period earnings, which could affect our results of operations.

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We may be unable to generate sufficient taxable income from future operations, or other circumstances could arise, which may limit our ability to utilize our tax net operating loss carryforwards or maintain our deferred tax assets.
We acquired the core coal assets of Predecessor Alpha as part of Predecessor Alpha’s bankruptcy restructuring in transactions intended to be treated as a tax-free reorganization for U.S. federal income tax purposes. As a result of these transactions, we inherited the tax basis of the core assets and the net operating loss and other carryforwards of Predecessor Alpha. These carryforwards and tax basis were subject to reduction on December 31, 2016 due to the cancellation of indebtedness resulting from Predecessor Alpha’s bankruptcy restructuring. Due to the change in ownership, the net operating loss and other carryforwards will be subjected to limitations on their use in future years. In addition, we do not have a long history of operating results, and if we are unable to generate profits in the future, we may be unable to utilize these carryforwards. As of December 31, 2018, a valuation allowance of $94.8 million has been provided on federal and state net operating loss carryforwards and gross deferred tax assets not expected to provide future tax benefits.
Negative or unexpected consequences of the Tax Cuts and Jobs Act could affect our business.
On December 22, 2017, legislation commonly referred to as the Tax Cuts and Jobs Act (the “TCJA”) significantly revised U.S. federal corporate tax law by, among other things, reducing the U.S. federal corporate income tax rate to 21%, eliminating the corporate alternative minimum tax, providing a mechanism for corporations to monetize alternative minimum tax credits (“AMT Credits”) during the 2018 to 2021 tax years, limiting the tax deduction for interest expense to 30% of adjusted earnings, allowing immediate expensing for certain new investments, and, effective for net operating losses arising in taxable years beginning after December 31, 2017, eliminating net operating loss carrybacks, permitting indefinite net operating loss carryforwards, and limiting the use of net operating loss carryforwards to 80% of current year taxable income.
There are a number of uncertainties and ambiguities as to the interpretation and application of many of the provisions in the TCJA. In the absence of guidance of these issues, we will use what we believe are reasonable interpretations and assumptions in interpreting and applying the TCJA for purposes of determining our cash tax liabilities and results of operations, which may change as we receive additional clarification and implementation guidance and as the interpretation of the TCJA evolves over time. It is possible that the IRS could issue subsequent guidance or take positions on audit that differ from the interpretations and assumptions that we previously made, which could have a material adverse effect on our cash tax liabilities, results of operations and financial condition.
Our business requires substantial capital investment and maintenance expenditures, which we may be unable to provide.
Our business plan and strategy require substantial capital expenditures. We require capital for, among other purposes, acquisition of surface rights, equipment and the development of our mining operations, capital renovations, maintenance and expansions of plants and equipment and compliance with safety, health and environmental laws and regulations. Future debt or equity financing may not be available or, if available, may result in dilution or not be available on satisfactory terms. If we are unable to obtain additional capital, we may not be able to maintain or increase our existing production rates and we could be forced to reduce or delay capital expenditures or change our business strategy, sell assets or restructure or refinance our indebtedness, all of which could have a material adverse effect on our business or financial condition.
Changes in the fair value of derivative instruments and other assets or liabilities that are marked to market could cause volatility in our earnings.
Pursuant to the Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession, dated May 27, 2016, as modified and confirmed by the Order Confirming Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession, as Modified (Docket No. 3038), entered by the Bankruptcy Court on July 12, 2016, we have contingent revenue payment obligations to certain of Alpha’s creditors, which are recorded at fair market value and marked to market in each reporting period, with changes in value reflected in earnings. Any change in fair value can have a significant impact on our earnings from period to period, including in the future.
Cybersecurity attacks, natural disasters, terrorist attacks and other similar crises or disruptions may negatively affect our business, financial condition and results of operations, or those of our customers and suppliers.
Our business, or the businesses of our customers and suppliers, may be impacted by disruptions such as cybersecurity attacks or failures, threats to physical security, and extreme weather conditions or other natural disasters. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cybersecurity attacks than other targets in the U.S. These disruptions or any significant increases in energy prices that follow could result in government-imposed price controls. Our insurance may not protect us against such occurrences. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Further, as cybersecurity

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attacks continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cybersecurity attacks.
Risks Relating to Our Liquidity
Our indebtedness exposes us to various risks.
At December 31, 2018, we had $632.8 million of indebtedness outstanding before discounts and issuance costs applied for financial reporting, of which $149.0 million will mature in the next three years.
Our indebtedness could have important consequences to our business. For example, it could:
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make it more difficult for us to pay or refinance our debts as they become due during adverse economic and industry conditions because any related decrease in revenues could cause us to not have sufficient cash flows from operations to make our scheduled debt payments;
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force us to seek additional capital, restructure or refinance our debts, or sell assets;
•
cause us to be less able to take advantage of significant business opportunities such as acquisition opportunities and to react to changes in market or industry conditions;
•
cause us to use a portion of our cash flow from operations for debt service, reducing the availability of working capital and delaying or preventing investments, capital expenditures, research and development and other business activities;
•
cause us to be more vulnerable to general adverse economic and industry conditions;
•
expose us to the risk of increased interest rates because certain of our borrowings are at variable rates of interest;
•
expose us to the risk of foreclosure on substantially all of our assets and those of most of our subsidiaries, which secure certain of our indebtedness if we default on payment or are unable to comply with covenants or restrictions in any of the agreements;
•
limit our ability to borrow additional monies in the future to fund working capital, capital expenditures and other general corporate purposes; and
•
result in a downgrade in the credit ratings of our indebtedness, which could harm our ability to incur additional indebtedness and result in more restrictive borrowing terms, including increased borrowing costs and more restrictive covenants, all of which could affect our internal cost of capital estimates and therefore impact operational and investment decisions.

Our ability to meet our debt service obligations will depend on our future cash flow from operations and our ability to restructure or refinance our debt, which will depend on the condition of the capital markets and our financial condition at that time. We may incur additional secured or unsecured indebtedness in the future, subject to compliance with covenants in our existing debt agreements. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations, and the terms of existing or future debt instruments may restrict us from adopting some of these alternatives.

The terms of our credit facility impose operating and financial restrictions on us, which may limit our ability to respond to changing business and economic conditions.

In connection with the consummation of the Alpha Merger, we incurred indebtedness of approximately $550 million under a term loan facility to refinance existing indebtedness and to pay related fees and expenses, and borrowing capacity of $225 million under a revolving credit facility. Additionally, as a result of the Alpha Merger, we assumed a letter of credit agreement and a credit and security agreement which, among other things, include letter of credit facilities that provide for the issuance of letters of credit. The terms of our credit facilities impose operating and financial restrictions on us, which may limit our ability to respond to changing business and economic conditions.

The term loan facility matures on November 9, 2025 and the revolving credit facility matures on April 3, 2022. The term loan facility permits us, subject to approval of the administrative agent and the lenders providing the financing, to request incremental term loans up to an aggregate amount of $150 million plus additional amounts subject to a First Lien Leverage Ratio test and other specified conditions, in increments not less than $25 million or the remaining availability. The revolving loan facility permits us, subject to approval of the administrative agent and the lenders providing the financing, to request incremental revolving commitment increases up to an aggregate amount of $50 million, in increments not less than $10 million or the remaining availability and subject to specified conditions.

We are subject to various operating and financial covenants under the term loan and revolving credit facilities which restrict our ability to, among other things, incur additional indebtedness, make particular types of investments, incur certain

45

types of liens, engage in fundamental corporate changes, enter into transactions with affiliates, make substantial asset sales, make certain restricted payments, enter into amendments or waivers to certain agreements, conduct certain sale leasebacks or enter into certain burdensome agreements. Any failure to comply with these covenants may constitute a breach under the term loan and revolving credit facilities which could result in the acceleration of all or a substantial portion of any outstanding indebtedness and termination of revolving credit commitments under the term loan and revolving credit facilities. Our inability to maintain our term loan and revolving credit facilities could materially adversely affect our liquidity and our business. At December 31, 2018, we were in compliance with the operating and financial covenants under the term loan and revolving credit facilities.

Pressure on our business, cash flow and liquidity could materially and adversely affect our ability to fund our business operations or react to and withstand changing market and industry conditions. Additional sources of funds may not be available.
A significant source of liquidity is our cash balance. Access to additional funds from liquidity-generating transactions or other sources of external financing may not be available to us and, if available, would be subject to market conditions and certain limitations including our credit rating and covenant restrictions in our credit facility.
Our ability to make the required payments on our indebtedness depends on the cash flow generated by our subsidiaries, which may be constrained by legal, contractual, market or operating conditions from paying dividends to us.
We will depend to a significant extent on the generation of cash flow by our subsidiaries and their ability to make that cash available to us, by dividend, debt repayment or otherwise. These subsidiaries may not be able to, or be permitted to, make distributions to enable us to make payments in respect of our indebtedness. Each of these subsidiaries is a distinct legal entity and, under certain circumstances, legal and contractual restrictions, as well as the financial condition and operating requirements of our subsidiaries, may limit our ability to obtain cash from our subsidiaries. In the event that we do not receive distributions from our subsidiaries, we may be unable to make required payments of principal, premium, if any, and interest on our indebtedness.
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal.
Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations such as mine closure or reclamation costs, federal and state workers’ compensation costs (including related to black lung), coal leases and other obligations. These bonds are typically renewable annually. Under applicable regulations, self-bonding may not be available to us as a means to comply with our reclamation bonding obligations for the foreseeable future. Surety bond issuers and holders may not continue to renew the bonds, may demand less favorable terms upon renewal or may impose new or increased collateral requirements. As of December 31, 2018, we had outstanding surety bonds with third parties of approximately $581.4 million. Surety bond issuers and holders may demand additional collateral, unfavorable terms or higher fees. Our failure to retain, or inability to acquire, surety bonds or to provide a suitable alternative could adversely affect our ability to mine or lease coal, which would materially adversely affect our business and results of operations. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety bonds, restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of any credit arrangements then in place, or our inability to comply with our reclamation bonding obligations through self-bonding. In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand cash collateral as a condition to providing or maintaining surety bonds. Any such demands, depending on the amount of any cash collateral required, could have a material adverse impact on our liquidity and financial position. If we are unable to meet cash collateral requirements and cannot otherwise obtain or retain required surety bonds, we may be unable to satisfy legal requirements necessary to conduct our mining operations.
Difficulty in acquiring surety bonds, or additional collateral requirements, would increase our costs and likely require greater use of alternative sources of funding for this purpose, which would reduce our liquidity. If we are unable to provide the financial assurance that is required by state and federal law to secure our reclamation and coal lease obligations, our ability to mine or lease coal and, as a result, our results of operations could be materially and adversely affected.
The terms of our borrowing arrangements limit our and our subsidiaries’ ability to take certain actions, which may limit our operating and financial flexibility and adversely affect our business.
Our borrowing arrangements contain, and any future borrowing arrangements are also likely to contain, a number of significant restrictions and covenants that limit our ability and our subsidiaries’ ability to, among other things, incur additional indebtedness, enter into sale and leaseback transactions, pay dividends, make redemptions and repurchases of certain capital

46

stock, make loans and investments, create liens, sell certain assets, engage in transactions with affiliates, and merge or consolidate with other companies or sell substantially all of our assets. These covenants could adversely affect our ability to finance our future operations or capital needs or to execute preferred business strategies. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions. We regularly evaluate opportunities to enhance our capital structure and financial flexibility through a variety of methods, including repayment or repurchase of outstanding debt, amendment of our credit facility and other facilities, and other methods. As a result of any of these actions, the restrictions and covenants that apply to us may become more restrictive or otherwise change.
Operating results below current levels, or other adverse factors, including a significant increase in interest rates, could result in our being unable to comply with our covenants and payment obligations contained in our borrowing arrangements. If we violate these covenants or obligations under any of these agreements and are unable to obtain waivers from our lenders, our debt under all of these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we were able to obtain new financing, it may not be on commercially reasonable terms or on terms that are acceptable to us. If our debt is in default for any reason, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

The need to maintain capacity for required letters of credit could limit our ability to provide financial assurance for self-insured obligations and negatively impact our ability to fund future working capital, capital expenditure or other general corporate requirements.

On November 9, 2018, the Company entered into the Amended and Restated Asset-Based Revolving Credit Agreement. Additionally, as a result of the Alpha Merger, the Company assumed an Amended and Restated Letter of Credit Agreement and a Credit and Security Agreement. Each of these agreements includes, among other things, provisions that provide for the issuance of letters of credit. Obligations secured by letters of credit may increase in the future. If we do not maintain sufficient borrowing capacity under our letter of credit facilities, we may be unable to provide financial assurance for self-insured obligations and could negatively impact our ability to fund future working capital, capital expenditure or other general corporate requirements.

Risks Relating to the Ownership of Our Common Stock

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE, with which we are not currently required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time for our board of directors and management and will significantly increase our costs and expenses. We will need to:
•
institute a more comprehensive compliance function;
•
comply with rules promulgated by the NYSE;
•
prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
•
establish new internal policies; and
•
retain and involve to a greater degree outside counsel and accountants in the above activities.

Our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

47

An active, liquid and orderly trading market for our common stock may not be maintained, and our stock price may be volatile.
Contura’s common stock trades on the New York Stock Exchange under the ticker symbol “CTRA”. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. An active, liquid and orderly trading market for our common stock may not be maintained, however. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock.
The following factors, among others, could affect our stock price:
•
our operating and financial performance, including reserve estimates;
•
an unexpected mine or environmental incident;
•
quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;
•
the public reaction to our press releases, our other public announcements and our filings with the SEC;
•
strategic actions by our competitors;
•
changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;
•
speculation in the press or investment community;
•
research analysts’ coverage of our common stock, or their failure to cover our common stock;
•
sales of our common stock by us, our directors or officers or the selling stockholders or the perception that such sales may occur;
•
our payment of dividends;
•
changes in accounting principles, policies, guidance, interpretations or standards;
•
additions or departures of key management personnel;
•
actions by our stockholders;
•
general market conditions, including fluctuations in commodity prices;
•
public sentiment regarding climate change and fossil fuels;
•
domestic and international economic, legal and regulatory factors unrelated to our performance; and
•
the realization of any risks described under this “Risk Factors” section or described elsewhere in this document.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.
Future sales of our common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
We may issue additional shares of common stock or convertible securities in subsequent public offerings. We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock or the dividend amount payable per share on our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock or the dividend amount payable per share on our common stock. In addition, the issuance of shares of common stock upon the exercise of outstanding options will result in dilution to the interests of other stockholders. In addition, the issuance of shares of common stock upon the exercise of outstanding options and warrants will result in dilution to the interests of other stockholders.
We may issue preferred stock with terms that could adversely affect the voting power or value of our common stock.
Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the

48

happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock is influenced by the research and reports that securities or industry analysts publish about us or our business. Securities and industry analysts currently publish these research reports, but there is no guarantee they will continue to publish them in the future. If securities or industry analysts initiate coverage and one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.
Provisions in our organizational documents and the instruments governing our debt may discourage a takeover attempt even if doing so might be beneficial to our stockholders.
Provisions contained in our second amended and restated certificate of incorporation (the “amended and restated certificate of incorporation”) and second amended and restated bylaws (the “amended and restated bylaws”) could impose impediments to the ability of a third-party to acquire us even if a change of control would be beneficial to our stockholders. Provisions of our amended and restated certificate of incorporation and amended and restated bylaws impose various procedural and other requirements, which could make it more difficult for stockholders to effect certain corporate actions. For example, our amended and restated certificate of incorporation authorizes our board of directors to determine the rights, preferences, privileges and restrictions of unissued series of preferred stock, without any vote or action by our stockholders. Thus, our board of directors can authorize the issuance of shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of our common stock. These provisions may have the effect of delaying or deterring a change of control of our company and could limit the price that certain investors might be willing to pay in the future for shares of our common stock.

A change of control (as defined under the instruments governing our debt) is an event of default, permitting our lenders to accelerate the maturity of certain borrowings. Further, our borrowing arrangements impose other restrictions on us, including with respect to mergers or consolidations with other companies and the sale of substantially all of our assets. These provisions could prevent or deter a third-party from acquiring us even where the acquisition could be beneficial to our stockholders.

Our amended and restated bylaws provide, subject to certain exceptions, that the Court of Chancery of the State of Delaware is the sole and exclusive forum for certain stockholder litigation matters, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or stockholders.

Our amended and restated bylaws provide, subject to limited exceptions, that the Court of Chancery of the State of Delaware is, to the fullest extent permitted by law, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf; (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers or other employees to us or our stockholders; (iii) any action asserting a claim against us, any director or our officers or employees arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation (including any certificate of designations relating to any class or series of preferred stock) or our amended and restated bylaws; or (iv) any action asserting a claim against us, any director or our officers or employees that is governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock shall be deemed to have notice of and to have consented to the provisions of our amended and restated bylaws described above. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or any of our directors, officers, other employees or stockholders which may discourage lawsuits with respect to such claims. Alternatively, if a court were to find the choice of forum provision that is contained in our amended and restated bylaws to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could materially adversely affect our business, financial condition and results of operations.
Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

49


Coal Reserves
We prepared our estimates of reserves which were audited by Marshall Miller & Associates, Inc. (“MM&A”), and MM&A reviewed our methodology, assumptions and reserve factors utilized in determining these estimates. In the few instances where MM&A recommended revisions to reserve figures, MM&A worked with our team to modify reserve estimates. MM&A relied on their independent pro-forma economic analysis for ultimate reserve determination; this analysis is further discussed in the Costs & Calculations section below.
We maintain an internal staff of engineers and geoscience professionals who work closely with independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our estimated reserves. Our internal technical team members meet with independent reserve engineers periodically to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for their properties, such as ownership interest, production, test data, commodity prices and operating and development costs.
These estimates are based on engineering, economic and geologic data, coal ownership information and current and proposed mine plans. Our proven and probable coal reserves are reported as “recoverable coal reserves,” which is the portion of the coal that could be economically and legally extracted or produced at the time of the reserve determination, taking into account mining recovery and preparation plant yield. These estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Acquisitions or dispositions of coal properties will also change these estimates. Changes in mining methods may increase or decrease the recovery basis for a coal seam, as will changes in preparation plant processes.
“Reserves” are defined by the SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Industry Guide 7 divides reserves between “proven (measured) reserves” and “probable (indicated) reserves,” which are defined as follows:
•
“Proven (Measured) Reserves.” Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
•
“Probable (Indicated) Reserves.” Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.
On October 31, 2018, the SEC voted to adopt amendments to modernize the property disclosure requirements for mining registrants and related guidance under the Securities Act of 1933 and the Securities Exchange Act of 1934. The final rules provide a three-year transition period, thus, we will be required to begin to comply with the new rules for the fiscal year beginning on January 1, 2021 (reported in the Annual Report on Form 10-K for the year ended December 31, 2021). We are in the process of assessing the impact the new rules will have on our disclosures.
As of December 31, 2018, we had estimated reserves totaling 1,348.4 million tons, of which 598.5 million tons, or 44%, were “assigned” recoverable reserves that were either being mined, were controlled and accessible from a then active mine, or located at idled facilities where limited capital expenditures would be required to initiate operations when conditions warrant. The remaining 749.9 million tons were classified as “unassigned,” representing coal at currently non-producing locations that we anticipate mining in the future, but which would require significant additional development capital before operations could begin.

50

The following table provides the location and coal reserves associated with each of our reportable segments and related significant mines as of December 31, 2018:
As of December 31, 2018
(in thousands of short tons) (1)
Recoverable Reserves
Reportable Segment
Location
Reserves
Proven
Probable
Assigned (2)
Unassigned (2)
CAPP - Met










Deep Mine 41
Virginia
35,479

27,624

7,855

35,479

—

Road Fork 52
West Virginia
18,818

8,786

10,032

18,818

—

CAPP - Met Other
Virginia, West Virginia
592,301

402,498

189,803

332,065

260,236

CAPP - Thermal
West Virginia
49,779

26,666

23,113

49,224

555

NAPP










Cumberland
Pennsylvania
116,293

88,633

27,660

24,095

92,198

NAPP Other
Pennsylvania
535,695

331,299

204,396

138,787

396,908

1,348,365

885,506

462,859

598,468

749,897

(1) 1 short ton is equivalent to 0.907185 metric tons.
(2) “Assigned” reserves represent recoverable reserves that are either currently being mined, reserves that are controlled and accessible from a currently active mine or reserves at idled facilities where limited capital expenditures would be required to initiate operations. “Unassigned” reserves represent coal at currently non-producing locations that would require significant additional capital spending before operations begin.


The following table provides the breakdown between the quantity of reserves that is currently covered by an active mining permit or not permitted and the quantity of reserves that is met coal or thermal coal associated with each of our reportable segments and related significant mines as of December 31, 2018:
As of December 31, 2018
(in thousands of short tons) (1)
Reserve Control
By Permit Status
By Coal Market Type (2)
Reportable Segment
Owned
Leased
Permitted
Not Permitted
Met
Thermal
CAPP - Met








Deep Mine 41
—

35,479

29,768

5,711

35,479

—

Road Fork 52
145

18,673

3,301

15,517

18,818

—

CAPP - Met Other
104,254

488,047

181,391

410,910

554,790

37,511

CAPP - Thermal
9,802

39,977

44,005

5,774

11,938

37,841

NAPP








Cumberland
18,572

97,721

24,095

92,198

—

116,293

NAPP Other
293,985

241,710

13,858

521,837

44,180

491,515

426,758

921,607

296,418

1,051,947

665,205

683,160

(1) 1 short ton is equivalent to 0.907185 metric tons.
(2) Classification of coal market type is based on available quality information and is subject to change with shifting market condition and/or additional exploration.


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The following table provides a summary of the quality of our reserves for each of our reportable segments and related significant mines as of December 31, 2018:
As of December 31, 2018
(in thousands of short tons) (1)
Sulfur Content
Average Btu
Reportable Segment
Reserves
Primary Coal Type
<1% Sulfur
1 - 1.5% Sulfur
>1.5% Sulfur
>12,500
<12,500
CAPP - Met
Deep Mine 41
35,479

MVM
35,479

—

—

35,479

—

Road Fork 52
18,818

LVM
18,818

—

—

18,818

—

CAPP - Met Other
592,301

HVM
441,870

137,858

12,573

569,353

22,948

CAPP - Thermal
49,779

T
49,779

—

—

39,977

9,802

NAPP
Cumberland
116,293

T
—

—

116,293

116,293

—

NAPP Other
535,695

T
73,633

—

462,062

472,381

63,314

1,348,365

619,579

137,858

590,928

1,252,301

96,064

(1) 1 short ton is equivalent to 0.907185 metric tons.
(2) Coal Type: T=Thermal; LVM=Low-Vol. Metallurgical Coal; MVM=Mid-Vol. Metallurgical Coal; HVM=High-Vol. Metallurgical Coal .



The following table provides a summary of information regarding our mining operations for each of our reportable segments and related significant mines as of December 31, 2018:
Transportation
Reportable Segment
Reserves (thousands of short tons) (1)
Type (2)
Mining Equipment (3)
Rail
Other (4)
CAPP - Met
Deep Mine 41
35,479

U
CM
CSX
B
Road Fork 52
18,818

U
CM
NS
B
CAPP - Met Other
592,301

U/S
CM/S/H
NS/CSX
B
CAPP - Thermal
49,779

U
CM
NS/CSX
B
NAPP
Cumberland
116,293

U
LW
NS/CSX
B
NAPP Other
535,695

U
LW
NS/CSX
B
1,348,365

(1) 1 short ton is equivalent to 0.907185 metric tons.
(2) Type of Mine: S = Surface; U = Underground.
(3) Mining Equipment: S = Shovel/Excavator/Loader/Trucks; LW = Longwall; CM = Continuous Miner; H = Highwall Miner.
(4) Transportation: B = Barge Loadout availability.



52

The following table provides a summary of information regarding our significant preparation plants as of December 31, 2018:
Preparation Plant(s)
Reportable Segment/Preparation Plant
Capacity
(short tons per hr) (1)
Utilization %
Source of Power
CAPP - Met
McClure
1,000
67%
MP2 Energy
Toms Creek
1,050
42%
Old Dominion
Bandmill
1,200
55%
AEP
Marfork
2,400
70%
AEP
NAPP
Cumberland
1,700
88%
West Penn Power
(1) 1 short ton is equivalent to 0.907185 metric tons.

Information provided within the previous tables concerning our properties has been prepared in accordance with applicable U.S. federal securities laws. All mineral reserve estimates have been prepared in accordance with SEC Industry Guide 7.
We own a 65.0% interest in the DTA coal export terminal in eastern Virginia. DTA provides us with the ability to fulfill a broad range of customer coal quality requirements through coal blending, while also providing storage capacity and transportation flexibility.
Costs & Calculations
Coal tonnage is classified as reserve when demonstrating profit on a fully loaded cost basis. Pro forma testing conducted by MM&A demonstrated that our reserves are expected to generate cash and are profitable on a fully loaded cost basis. Fully loaded costs were compared to two-year historical sales realizations for all potential reserve areas. The classification of reserves is dependent upon the sum of all costs normalized to a per clean ton basis being less than the two-year historical sales price. The two-year historical sales price includes the following price ranges categorized by coal qualities:
Coal Qualities
Two Year Historical Sales Price
Met High-Vol. A
$119 -$126
Met High-Vol. B
$85.50 - $119
Met Mid-Vol.
$101 - $143
Met Low-Vol.
$126
Thermal
$44 - $60

For the surface mining reserve areas, the mining costs were estimated using the surface mining overburden ratios. Direct mining costs were estimated for labor, blasting, fuel and lubrication supplies, repairs and maintenance, operating supplies and other costs. The pro forma mining cost estimates for underground mining areas began with the computation of representative total seam thickness for each area evaluated. The clean-tons-per-foot of mining advance was calculated to support mine production and productivity calculations.
All underground and highwall miner coal reserves are expected to require washing to remove coal partings and out-of-seam contamination. Preparation plant yield was calculated by multiplying the in-seam recovery, out-of-seam contamination and plant efficiency factors. In-seam recovery factors were obtained based upon the relative percentages of coal and rock within the seam. Direct mining costs were estimated for labor, supplies, maintenance and repairs, mine power and other direct mining costs. Sales, general and administration and environmental cost allocations were based on values typically observed by MM&A. Sales variable costs for royalty payments, black lung excise tax and reclamation fees were calculated, along with cost components for other indirect mining costs.

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a201810kmapv2.jpg

Item 3. Legal Proceedings

For a description of the Company’s legal proceedings, see Note 26 , part (d), to the Consolidated Financial Statements, which is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Information 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.

Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Price range of our common stock

Upon the consummation of the transactions contemplated by the Merger Agreement, Contura began trading on the New York Stock Exchange under the ticker “CTRA” on November 9, 2018. Previously, Contura shares traded on the OTC market

54

under the ticker “CNTE.” The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock reported in the OTC market and the New York Stock Exchange.
2018
High
Low
First Quarter
$69.00
$61.00
Second Quarter
$80.00
$62.25
Third Quarter
$81.00
$66.00
Fourth Quarter
$80.00
$60.76
2017
High
Low
First Quarter
$71.25
$58.00
Second Quarter
$78.00
$65.05
Third Quarter
$70.00
$55.00
Fourth Quarter
$61.50
$54.00

As of December 31, 2018, there were 118 registered holders of record of our common stock. The transfer agent and registrar for our common stock is Computershare Trust Company, N.A.

Dividend Policy

See Item 8. Financial Statements and Supplementary Data, Note 13 Dividend and Stock Repurchases for more information.

Repurchase of Common Stock

The following table summarizes information about shares of common stock that were repurchased during the fourth quarter of 2018.
Total Number
of Shares
Purchased (1)
Average Price
Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Programs (2)
Approximate Dollar
Value of Shares
that May Yet Be
Purchased Under
the Programs
October 1, 2018 through October 31, 2018
—

$
—

—

$
—

November 1, 2018 through November 30, 2018
4,224

$
75.00

—

$
—

December 1, 2018 through December 31, 2018
1,590

$
67.29

223,218

$
—

5,814

223,218

$
—

(1) The Company is authorized to repurchase common shares from employees (upon the election by the employee) to satisfy the employees’ statutory tax withholdings upon the vesting of stock grants. Shares that are repurchased to satisfy the employees’ statutory tax withholdings are recorded in treasury stock at cost.
(2) The Company entered into the Amended and Restated Credit Agreement and the Restated Asset-Based Revolving Credit Agreement on November 9, 2018. The agreement, among other things, permitted an aggregate amount of $15 million of cash to be used for the repurchase of its common stock in any twelve month period after the closing date of the agreement, subject to certain terms and conditions. On December 6, 2018, the Company announced that its Board of Directors had approved a stock repurchase plan (the “Company Repurchase Plan”) to acquire up to $15 million in the aggregate of the company’s common stock.

Unregistered Sales of Equity Securities and Use of Proceeds

Working capital restrictions and other limitation on dividend payments

See Item 8. Financial Statements and Supplementary Data, Note 13 Dividend and Stock Repurchases for more information.

Unregistered sales of equity securities made during the current quarter

See Item 8. Financial Statements and Supplementary Data, Note 20 Warrants for more information.


55

Item 6. Selected Financial Data
The following table presents selected financial and other data for the most recent five fiscal periods. The term “Successor” refers to Contura and its subsidiaries for periods beginning as of July 26, 2016 and thereafter. The term “Predecessor” refers to Contura on a carve-out basis using Predecessor Alpha’s historical basis and our assets, liabilities and operating results while they were under Predecessor Alpha’s ownership.
The selected historical consolidated and combined financial data for the year ended December 31, 2018 and 2017, for the Successor period from July 26, 2016 to December 31, 2016 and for the Predecessor period from January 1, 2016 to July 25, 2016, and as of December 31, 2018 and 2017, have been derived from our audited consolidated and Predecessor combined financial statements for the year ended December 31, 2018, which are included elsewhere in this Annual Report on Form 10-K.
The selected historical combined financial data for the Predecessor year ended December 31, 2015, December 31, 2014 and as of December 31, 2016 and December 31, 2015 have been derived from the audited Predecessor financial statements that are not included in this Annual Report on Form 10-K. The selected historical combined financial data for the Predecessor year as of July 25, 2016 and December 31, 2014 have been derived from Contura’s unaudited financial statements, which are not included in this Annual Report on Form 10-K.
As a result of our acquisition of certain Predecessor Alpha core coal operations in connection with Predecessor Alpha’s restructuring, the Successor consolidated financial statements on and after July 25, 2016 are not comparable with the Predecessor combined financial statements prior to that date. Refer to Note 1 to Contura’s audited consolidated and predecessor combined financial statements for the year ended December 31, 2018, included elsewhere in this Annual Report on Form 10-K.
Our Predecessor combined financial statements and condensed combined financial statements include allocations of expenses for certain corporate functions historically performed by Predecessor Alpha, including, but not limited to, general corporate expenses related to finance, legal, information technology, human resources, communications, employee benefits and incentives, insurance and stock-based compensation. These costs may not be representative of costs incurred by us as an independent company. Consequently, the financial information included here may not necessarily reflect our financial position, results of operations and cash flows in the future or what our financial condition, results of operations and cash flows would have been had we been an independent company during the periods presented.
The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, see Item 1A “Risk Factors” of this Annual Report on Form 10-K for a discussion of risk factors that could impact our future results of operations.
In addition, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8 “Financial Statements and Supplementary Data” for additional financial information.

56

SELECTED HISTORICAL CONSOLIDATED AND COMBINED FINANCIAL DATA
(Amounts in thousands, except share and per share data)
Successor
Predecessor
For the Year Ended December 31, 2018
For the Year Ended December 31, 2017
For the Period from July 26, 2016 to December 31, 2016
For the Period from January 1, 2016 to July 25, 2016
For the Year Ended December 31, 2015
For the Year Ended December 31, 2014
Statements of Operations Data:
Revenues:
Coal revenues
$
2,020,889

$
1,392,481

$
431,692

$
344,692

$
816,010

$
1,027,387

Freight and handling revenues
—

247,402

70,544

52,076

97,237

98,109

Other revenues
10,316

10,086

4,060

14,343

12,774

17,262

Total revenues
2,031,205

1,649,969

506,296

411,111

926,021

1,142,758

Costs and expenses:

Cost of coal sales (exclusive of items shown separately below)
1,297,990

1,079,895

319,790

305,276

704,297

767,513

Freight and handling costs
363,128

247,402

70,544

52,076

97,237

98,109

Depreciation, depletion and amortization
77,549

34,910

5,973

66,076

149,197

148,137

Accretion on asset retirement obligations
9,966

9,934

4,800

5,005

5,696

3,098

Amortization of acquired intangibles, net
(5,392
)
59,007

61,281

11,567

2,223

420

Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)
59,271

67,459

19,135

29,568

44,158

52,256

Asset impairment and restructuring (1)
—

—

—

3,096

297,425

6,732

Goodwill impairment (2)
—

—

—

—

70,017

Merger related costs
51,800

—

—

—

—

—

Secondary offering costs (3)
—

4,491

—

—

—

—

Total other operating (income) loss:
Mark-to-market adjustment for acquisition-related obligations
24

3,221

(10,616
)
—

—

—

Gain on settlement of acquisition-related obligations
(580
)
(38,886
)
—

—

—

—

Other expenses
(16,311
)
178

—

2,184

(99
)
2,220

Total costs and expenses
1,837,445

1,467,611

470,907

474,848

1,300,134

1,148,502

Income (loss) from operations
193,760

182,358

35,389

(63,737
)
(374,113
)
(5,744
)
Other (expense) income:
Interest expense
(38,810
)
(35,977
)
(20,496
)
(2
)
(28
)
(101
)
Interest income
1,949

210

23

19

4

4

Mark-to-market adjustment for warrant derivative liability
—

—

(33,975
)
—

—

—

Loss on modification and extinguishment of debt
(12,042
)
(38,701
)
—

—

—

—

Bargain purchase gain
—

1,011

7,719

—

—

—

Equity loss in affiliates
(6,112
)
(3,339
)
(2,287
)
(2,735
)
(7,712
)
(9,831
)
Miscellaneous income, net
(1,254
)
194

(139
)
(13,978
)
(20,904
)
(20,441
)
Total other expense, net
(56,269
)
(76,602
)
(49,155
)
(16,696
)
(28,640
)
(30,369
)
Income (loss) from continuing operations before reorganization items and income taxes
137,491

105,756

(13,766
)
(80,433
)
(402,753
)
(36,113
)
Reorganization items, net
—

—

—

(20,989
)
(10,085
)
—

Income (loss) from continuing operations before income taxes
137,491

105,756

(13,766
)
(101,422
)
(412,838
)
(36,113
)
Income tax benefit
165,363

67,979

1,920

39,881

155,052

4,476

Net income (loss) from continuing operations
302,854

173,735

(11,846
)
(61,541
)
(257,786
)
(31,637
)
Discontinued operations:

57

Successor
Predecessor
For the Year Ended December 31, 2018
For the Year Ended December 31, 2017
For the Period from July 26, 2016 to December 31, 2016
For the Period from January 1, 2016 to July 25, 2016
For the Year Ended December 31, 2015
For the Year Ended December 31, 2014
Statements of Operations Data:
(Loss) income from discontinued operations before income taxes
(4,994
)
(36,894
)
1,467

(679
)
(259,317
)
(33,972
)
Income tax benefit (expense) from discontinued operations
1,305

17,681

(551
)
(4,992
)
99,543

13,264

(Loss) income from discontinued operations
(3,689
)
(19,213
)
916

(5,671
)
(159,774
)
(20,708
)
Net income (loss)
$
299,165

$
154,522

$
(10,930
)
$
(67,212
)
$
(417,560
)
$
(52,345
)
Basic income (loss) per common share: (4)
Income (loss) from continuing operations
$
27.61

$
17.01

$
(1.15
)
(Loss) income from discontinued operations
(0.33
)
(1.89
)
0.09

Net income (loss)
$
27.28

$
15.12

$
(1.06
)
Diluted income (loss) per common share: (4)
Income (loss) from continuing operations
$
25.86

$
16.13

$
(1.15
)
(Loss) income from discontinued operations
(0.32
)
(1.78
)
0.09

Net income (loss)
$
25.54

$
14.35

$
(1.06
)
Weighted average shares - basic
10,967,014

10,216,464

10,309,310

Weighted average shares - diluted
11,712,653

10,770,005

10,309,310

Statement of Cash Flows Data: (5)
Net cash provided by (used in):
Operating activities
$
158,381

$
314,260

$
21,459

$
77,029

$
155,052

$
165,103

Investing activities
$
102,196

$
(121,307
)
$
108,352

$
(25,029
)
$
(97,034
)
$
(114,561
)
Financing activities
$
22,709

$
(170,282
)
$
41,478

$
(35,822
)
$
(53,585
)
$
(50,568
)
Successor
Predecessor
As of December 31,
As of July 25, 2016
As of December 31,
2018
2017
2016
2015
2014
Balance Sheet Data (at period end):
Cash and cash equivalents
$
233,599

$
141,924

$
127,948

$
100

$
227

$
6

Working capital (6)
$
473,782

$
234,595

$
222,917

$
(3,888
)
$
76,711

$
56,209

Total current and non-current assets - discontinued operations
$
22,475

$
48,130

$
190,454

$
401,543

$
404,363

$
679,851

Total assets
$
2,746,058

$
836,600

$
946,752

$
1,590,256

$
1,715,410

$
2,429,213

Notes payable and long-term debt, including current portion, net
$
588,012

$
372,703

$
346,994

$
95

$
136

$
1,867

Total current and non-current liabilities - discontinued operations
$
21,986

$
61,876

$
164,709

$
225,964

$
197,383

$
241,173

Total liabilities (7)
$
1,674,918

$
743,952

$
909,528

$
470,003

$
501,513

$
764,871

Stockholders’ equity/Predecessor business equity
$
1,071,140

$
92,648

$
37,224

$
1,120,253

$
1,213,897

$
1,664,342


(1)
Asset impairment and restructuring expenses for 2015 include long-lived asset impairment charges of $224,139 and $72,012 related to asset groups within the NAPP and CAPP - Met segments, respectively.
(2)
Goodwill impairment for 2014 includes impairment charges of $70,017 within the CAPP - Met segment.
(3)
Secondary offering costs reflect expenses incurred in connection with the withdrawn secondary offering of our common stock.

58

(4)
Historical basic income (loss) per share is calculated based on the weighted average common shares outstanding for the year ended December 31, 2018, December 31, 2017 and for the period from July 26, 2016 to December 31, 2016. For the year ended December 31, 2018 and December 31, 2017, the dilutive effect of stock options and other stock-based instruments is considered when calculating the diluted earnings per share as the Company generated net income during these periods. There was no dilutive effect to common shares outstanding for the period from July 26, 2016 to December 31, 2016 as in periods of net loss, the number of shares used to calculate diluted earnings per share is the same as basic earnings per share.
(5)
Cash flow data includes discontinued operations.
(6)
Working capital (current assets minus current liabilities) calculation includes cash and cash equivalents but excludes discontinued operations.
(7)
Total liabilities as of July 25, 2016 and December 31, 2015 include $35,693 and $72,242, respectively, of liabilities subject to compromise related to Alpha’s bankruptcy filing.

Item 7. Management ’ s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis provides a narrative of our results of operations and financial condition for the years ended December 31, 2018 and 2017 (Successor), the period from July 26, 2016 to December 31, 2016 (Successor), and the period from January 1, 2016 to July 25, 2016 (Predecessor). The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and related notes and the risk factors included elsewhere in this Annual Report on Form 10-K.
Non-GAAP Financial Measures

The discussion below contains “non-GAAP financial measures.” These are financial measures which either exclude or include amounts that are not excluded or included in the most directly comparable measures calculated and presented in accordance with generally accepted accounting principles in the United States (“GAAP”). Specifically, we make use of the non-GAAP financial measure “Adjusted EBITDA” and “Adjusted Cost of Produced Coal Sold.” Adjusted EBITDA does not purport to be an alternative to net income (loss) as a measure of operating performance. The presentation of these measures should not be considered in isolation, or as a substitute for analysis of our results as reported under GAAP.

Management uses non-GAAP financial measures to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone. Because not all companies use identical calculations, the presentations of these measures may not be comparable to other similarly titled measures of other companies and can differ significantly from company to company depending on long-term strategic decisions regarding capital structure, the tax jurisdictions in which companies operate, and capital investments.

Included below are reconciliations of non-GAAP financial measures to GAAP financial measures.

Formation

Contura was incorporated in the State of Delaware on June 10, 2016 to acquire and operate certain of Alpha’s core coal operations, as part of the Alpha Restructuring. On July 26, 2016, a consortium of former Alpha creditors acquired our common stock in exchange for a partial release of their creditor claims pursuant to the Alpha Restructuring. Furthermore, pursuant to an asset purchase agreement between Contura and Alpha, we purchased certain former core coal operations of Alpha.
Overview

We are a large-scale provider of met and thermal coal to a global customer base, operating high-quality, cost-competitive coal mines across two major U.S. coal basins (CAPP and NAPP) along with a robust Trading and Logistics business. As of December 31, 2018 , our operations consisted of thirty-two active mines and twelve coal preparation and load-out facilities, with approximately 4,420 employees. We produce, process, and sell met coal and thermal coal from operations located in Virginia, West Virginia and Pennsylvania. We also sell coal produced by others, some of which is processed and/or blended with coal produced from our mines prior to resale, with the remainder purchased for resale by our trading operations. As of December 31, 2018 , we had 1.3 billion tons of reserves, including 885.5 million tons of proven reserves and 462.9 million tons of probable reserves.

We began operations on July 26, 2016, with mining operations in NAPP, the PRB, and CAPP. Through the Acquisition, Contura acquired a significant reserve base. We also acquired Alpha’s 40.6% interest in the DTA coal export terminal in eastern Virginia, and on March 31, 2017, we acquired a portion of another partner’s ownership stake and increased our interest to 65.0%. On December 8, 2017, the Company closed a transaction to sell the Eagle Butte and Belle Ayr mines located in the PRB, Wyoming, along with related coal reserves, equipment, infrastructure and other real properties. The PRB results of operations and financial position are reported as discontinued operations in the Consolidated Financial Statements. The historical information in the accompanying Notes to the Consolidated Financial Statements has been restated to reflect the

59

effects of the PRB operations being reported as discontinued operations in the Consolidated Financial Statements. See Note 4 for further information on discontinued operations. The Merger with Alpha Natural Resources Holdings, Inc. and ANR, Inc. was completed on November 9, 2018. Refer to Note 3 for information on terms of the Merger Agreement.
For the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016 sales of met coal were 11.1 million tons, 8.9 million tons, 3.1 million tons, and 2.6 million tons, respectively, and accounted for approximately 63.2%, 56.9%, 52.8%, and 36.8%, respectively, of our coal sales volume. Sales of thermal coal were 6.5 million tons, 6.7 million tons, 2.7 million tons, and 4.4 million tons, respectively, and accounted for approximately 36.8%, 43.1%, 47.2%, and 63.2%, respectively, of our coal sales volume. These results include sales from our Trading and Logistics business.

Our sales of met coal were made primarily to steel companies in the northeastern and midwestern regions of the United States and in several countries in Europe, Asia and the Americas. Our sales of thermal coal were made primarily to large utilities and industrial customers throughout the United States. For the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016 approximately 82.7%, 77.2%, 71.2%, and 39.3%, respectively, of our total coal revenues, including freight and handling revenues, were derived from coal sales made to customers outside the United States.
In addition, we generate other revenues from equipment sales, rentals, terminal and processing fees, coal and environmental analysis fees, royalties and the sale of natural gas. We also record freight and handling fulfillment revenue within coal revenues for freight and handling services provided in delivering coal to certain customers, which are a component of the contractual selling price.
Our primary expenses are operating supply costs, repair and maintenance expenditures, cost of purchased coal, royalties, wages and benefits, post-employment benefits, freight and handling costs, and taxes incurred in selling our coal. Historically, our cost of coal sales per ton is lower for sales of our produced and processed coal than for sales of purchased coal that we do not process prior to resale.
As of December 31, 2018 , we have four reportable segments: CAPP - Met, CAPP - Thermal, NAPP, and Trading and Logistics. See Note 28 for more information about our reportable segments. CAPP - Met consists of twenty-five active mines, including four mines in Virginia operated by third-party contractors, four mines operated by us in Virginia, and seventeen mines operated by us in West Virginia. CAPP - Met operations also include two preparation plants in Virginia, six preparation plants in West Virginia, as well as expenses associated with certain idled and closed mines. The coal produced by the CAPP - Met segment is predominantly met coal with some amounts of thermal coal being produced as a byproduct of mining. CAPP - Thermal consists of six active mines and three preparation plants in West Virginia, as well as expenses associated with certain idle and closed mines. The coal produced by the CAPP - Thermal segment is predominantly thermal coal with some met coal byproduct. NAPP consists of one active mine in Pennsylvania and one preparation plant, as well as expenses associated with one closed mine. Our NAPP segment produces primarily thermal coal, however, we are also able to sell part of our Cumberland coal production (0.7 and 0.2 million tons for the years ended 2018 and 2017, respectively) into the met coal market as High-Vol. B, achieving higher realized pricing than if sold as thermal coal. The Trading and Logistics segment focuses primarily on coal trading and coal terminal facility services. Our All Other category includes general corporate overhead and corporate assets and liabilities and the elimination of certain intercompany activity.
Business Developments

Merger with Alpha Natural Resources Holdings, Inc. and ANR, Inc.

The Merger with ANR, Inc. (“ANR”) and Alpha Natural Resources Holdings, Inc. (“Holdings”, and, together with ANR, the "Alpha Companies”) was completed on November 9, 2018 (the “Merger” or the “Alpha Merger”). For the year ended December 31, 2018, the Alpha Companies’ financial results are included in the Financial Statements for the period from November 9, 2018 through December 31, 2018. The Alpha Companies’ financial results are not included in the Financial Statements in periods prior to November 9, 2018. Refer to Note 3 for information on Alpha Merger and terms of the Merger Agreement.

Upon the consummation of the transactions contemplated by the Merger Agreement, our common stock began trading on the New York Stock Exchange under the ticker “CTRA.” Previously, our shares traded on the OTC market under the ticker “CNTE.”

Sale of PRB Operations

60


On December 8, 2017, we closed a transaction with Blackjewel L.L.C. (“Buyer”) to sell the Eagle Butte and Belle Ayr mines located in the Power River Basin (“PRB”). During the permit transfer period, we will maintain the required reclamation bonds and related collateral. As of December 31, 2018, we had outstanding surety bonds with a total face amount of $237.2 million to secure various obligations and commitments related to the PRB. A citizens’ organization filed objections to the permit transfer with the Wyoming Environmental Quality Council on November 16, 2018. The objections are scheduled to be heard on May 15 and 16, 2019. We believe the objections are without merit. Once the permits have been transferred, we estimate approximately $12.6 million comprised of short-term restricted cash and short-term deposits will be returned to operating cash. If the permit transfer process is not completed as expected, it could have material, adverse effects on us.

The PRB results of operations and financial position are reported as discontinued operations in the Consolidated Financial Statements. The historical information in the accompanying Notes to the Consolidated Financial Statements has been restated to reflect the effects of the PRB operations being reported as discontinued operations in the Consolidated Financial Statements. The discontinued operations include our former PRB segment. To conform with the Consolidated Financial Statements and accompanying Notes, the former PRB segment information for the discontinued operation has been eliminated. See Note 4 for further information on discontinued operations. The following tables summarize certain financial information relating to the PRB discontinued operating results that have been derived from our Consolidated Financial Statements for the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016.

Revenues

Year Ended December 31,
Increase (Decrease)
(In thousands, except for per ton data)
2018
2017
$ or Tons
%
Coal revenues:
Thermal
$
—

$
339,599

$
(339,599
)
(100.0
)%
Tons sold:
Thermal
—

31,102

(31,102
)
(100.0
)%
Coal sales realization per ton:
Thermal
$
—

$
10.92

$
(10.92
)
(100.0
)%

Successor
Predecessor
(In thousands, except for per ton data)
Period from
July 26, 2016 to December 31, 2016
% of Total Revenues
Period from
January 1, 2016 to July 25, 2016
% of Total Revenues
Coal revenues:
Thermal
$
180,555

35.7
%
$
192,629

46.9
%
Tons sold:
Thermal
16,674

17,225

Coal sales realization per ton:
Thermal
$
10.83

$
11.18




61

Costs and Expenses

Year Ended December 31,
Increase (Decrease)
(In thousands, except for per ton data)
2018
2017
$ or Tons
%
Cost of coal sales:
$
—

$
311,119

$
(311,119
)
(100.0
)%
Tons sold:
—

31,102

(31,102
)
(100.0
)%
Cost of coal sales per ton:
$
—

$
10.00

$
(10.00
)
(100.0
)%
Coal margin per ton (1) :
$
—

$
0.92

$
(0.92
)
(100.0
)%
Successor
Predecessor
(In thousands, except for per ton data)
Period from
July 26, 2016 to December 31, 2016
% of Total Revenues
Period from
January 1, 2016 to July 25, 2016
% of Total Revenues
Cost of coal sales:
$
140,803

27.8
%
$
164,920

40.1
%
Tons sold:
16,674

17,225

Cost of coal sales per ton:
$
8.44

$
9.57

Coal margin per ton (1) :
$
2.39

$
1.61

(1) Coal margin per ton is calculated as coal sales realization per ton less cost of coal sales per ton.

Per terms of the Back-to-Back Coal Supply Agreements, we are required to purchase and sell coal in 2019 and 2020 totaling $16.1 million and $9.2 million, respectively. For the year ended December 31, 2018 , we purchased and sold 5.7 million tons, totaling $62.1 million, under the Back-to-Back Coal Supply Agreements. For the year ended December 31, 2017, we purchased and sold 2.0 million tons, totaling $21.7 million, under the Back-to-Back Coal Supply Agreements.

During the third quarter of 2018, Blackjewel L.L.C. (“Blackjewel”) procured surety bonds for a total of $220.5 million to facilitate the transfer of record by the State of Wyoming of the Belle Ayr and Eagle Butte mine permits from Contura Coal West, LLC to Blackjewel as required by the Asset Purchase Agreement dated as of December 7, 2017, among Blackjewel, Contura Energy, Inc. (“Contura”), Contura Coal West, LLC, Contura Wyoming Land, LLC, Contura Coal Sales, LLC, and Contura Energy Services, LLC.

Contura agreed to backstop a total of $44.8 million of Blackjewel’s bonding obligations with respect to the Belle Ayr and Eagle Butte permits by entering into secondary general indemnification agreements and providing letters of credit totaling $18.8 million to the sureties as collateral for Contura’s indemnification obligations. This arrangement provides cost reimbursement for the issuing sureties. Indemnity bonds were issued by a third-party insurer in favor of Contura in a total amount of $26.0 million to insure Blackjewel’s performance obligations to Contura with respect to cancellation of the general indemnification agreements and return of the letters of credit.

Blackjewel agreed that, by June 30, 2019, it will (i) enter into financing arrangements of $44.8 million to be held as collateral by the sureties and (ii) cause each surety to release and return each letter of credit and cancel the Contura general indemnification agreements.

Blackjewel’s performance obligations are also collateralized by a security interest in mobile equipment granted to Contura under 8.6(c) of the Asset Purchase Agreement. Further, in connection with this arrangement, approximately $8.0 million in surety cash collateral previously supporting reclamation bonds was returned to Contura by certain of its sureties.

During the third quarter of 2018, we recorded a guarantee within discontinued operations to account for the Blackjewel surety bonding arrangement with no material impact on our financial statements.

Factors Affecting Our Results of Operations
Sales Volume. We earn revenues primarily through the sale of coal produced at our operations and resale of coal purchased from third parties. During the year ended December 31, 2018 , we sold 5.7 million tons of met coal from CAPP - Met, CAPP - Thermal, and NAPP, 5.4 million tons of met coal from our Trading and Logistics business, 6.4 million tons of thermal coal from CAPP - Met, CAPP - Thermal, and NAPP, and 0.1 million tons of thermal coal from our Trading and Logistics business. During the year ended December 31, 2017 , we sold 4.1 million tons of met coal from CAPP - Met and NAPP, 4.8 million tons

62

of met coal from our Trading and Logistics business, and 6.7 million tons of thermal coal from CAPP - Met and NAPP. During the period from July 26, 2016 to December 31, 2016, we sold 1.6 million tons of met coal from CAPP - Met and NAPP, 1.5 million tons of met coal from our Trading and Logistics business, and 2.7 million tons of thermal coal from CAPP - Met and NAPP. During the period from January 1, 2016 to July 25, 2016, we sold 2.4 million tons of met coal from CAPP - Met and NAPP, 0.2 million tons of met coal from our Trading and Logistics business, and 4.4 million tons of thermal coal from CAPP - Met and NAPP.
Sales Agreements
We manage our commodity price risk for coal sales through the use of coal supply agreements. As of March 15, 2019, we expect to ship on sales commitments of approximately 6.5 million tons of NAPP coal for 2019, 96% of which is priced at an average realized price per ton of $42.85, 9.3 million tons of CAPP - Met coal for 2019, 60% of which is priced at an average realized price per ton of $123.82, and 4.9 million tons of CAPP - Thermal coal for 2019, 90% of which is priced at an average realized price per ton of $57.67.
Realized Pricing . Our realized price per ton of coal is influenced by many factors that vary by region, including (i) coal quality, which includes energy (heat content), sulfur, ash, volatile matter and moisture content; (ii) differences in market conventions concerning transportation costs and volume measurement; and (iii) regional supply and demand.
•
Coal Quality. The energy content or heat value of thermal coal is a significant factor influencing coal prices as higher energy coal is more desirable to consumers and typically commands a higher price in the market. The heat value of coal is commonly measured in British thermal units or the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. Coal from the eastern and midwest regions of the United States tends to have a higher heat value than coal found in the western United States. Coal volatility is a significant factor influencing met coal pricing as coal with a lower volatility has historically been more highly valued and typically commands a higher price in the market. The volatility refers to the loss in mass, less moisture, when coal is heated in the absence of air. The volatility of met coal determines the percentage of feed coal that actually becomes coke, known as coke yield, with lower volatility producing a higher coke yield.
•
Market Conventions. Coal sales contracts are priced according to conventions specific to the market into which such coal is to be sold. Our domestic sales contracts are typically priced free on board (“FOB”) at our mines and on a short ton basis. Our international sales contracts are typically priced FOB at the shipping port from which such coal is delivered and on a metric ton basis. Accordingly, for international sales contracts, we typically bear the cost of transportation from our mines to the applicable outbound shipping port, and our coal sales realization per ton calculation reflects the conversion of such tonnage from metric tons into short tons, as well as the elimination of the freight and handling fulfillment component of coal sales revenue. In addition, for domestic sales contracts, as customers typically bear the cost of transportation from our mines, our operations located further away from the end user of the coal may command lower prices.
•
Regional Supply and Demand. Our realized price per ton is influenced by market forces of the regional market into which such coal is to be sold. Market pricing may vary according to region and lead to different discounts or premiums to the most directly comparable benchmark price for such coal product.
Costs. Our results of operations are dependent upon our ability to improve productivity and control costs. Our primary expenses are for operating supply costs, repair and maintenance expenditures, cost of purchased coal, royalties, current wages and benefits, freight and handling costs and taxes incurred in selling our coal. Principal goods and services we use in our operations include maintenance and repair parts and services, electricity, fuel, roof control and support items, explosives, tires, conveyance structure, ventilation supplies and lubricants.
In addition, our cost of coal sales includes idle and closed mine costs and purchased coal costs. Additionally due to the Merger, our cost of coal sales includes the cost impact of coal inventory fair value adjustments. In the following table, we calculate adjusted cost of produced coal sold as cost of coal sales less idle and closed mine costs, cost impact of coal inventory fair value adjustments and purchased coal costs.



63

Year Ended December 31, 2018
(In thousands, except for per ton data)
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Cost of coal sales:
Cost of produced coal sold
$
360,164


$
34,690


$
238,876


$
—


$
220

$
633,950

Cost of purchased coal sold
49,383

2,185

—

587,857

—

639,425

Cost impact of coal inventory fair value adjustment (1)
11,547

5,517

—

—

—

17,064

Idle and closed mine costs
3,852

202

2,776

—

721

7,551

Total cost of coal sales
$
424,946

$
42,594

$
241,652

$
587,857

$
941

$
1,297,990

Tons sold
5,196

632

6,273

5,486

—

17,587

Cost of coal sales per ton
$
81.78

$
67.40

$
38.52

$
107.16

$
—

$
73.80

Total cost of coal sales
$
424,946

$
42,594

$
241,652

$
587,857

$
941

$
1,297,990

Less: cost of purchased coal sold
(49,383
)
(2,185
)
—

(587,857
)
—

(639,425
)
Less: cost impact of coal inventory fair value adjustment
(11,547
)
(5,517
)
—

—

—

(17,064
)
Less: idle and closed mine costs
(3,852
)
(202
)
(2,776
)
—

(721
)
(7,551
)
Cost of produced coal sold
$
360,164

$
34,690

$
238,876

$
—

$
220

$
633,950

Produced tons sold
4,750

595

6,273

—

—

11,618

Cost of produced coal sold per ton
$
75.82


$
58.30


$
38.08


$
—


$
—


$
54.57

(1) The cost impact of the coal inventory fair value adjustment as a result of the Alpha Merger is expected to have short-term impact.

Year Ended December 31, 2017
(In thousands, except for per ton data)
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Cost of coal sales:
Cost of produced coal sold
$
267,121


$
—


$
248,344


$
—


$
—

$
515,465

Cost of purchased coal sold
14,734

—

47

543,148

—

557,929

Idle and closed mine costs
2,779

—

3,722

—

—

6,501

Total cost of coal sales
$
284,634

$
—

$
252,113

$
543,148

$
—

$
1,079,895

Tons sold
3,901

—

6,904

4,852

—

15,657

Cost of coal sales per ton
$
72.96


$
—


$
36.52


$
111.94


$
—


$
68.97

Total cost of coal sales
$
284,634


$
—


$
252,113


$
543,148


$
—

$
1,079,895

Less: cost of purchased coal sold
(14,734
)
—

(47
)
(543,148
)
—

(557,929
)
Less: idle and closed mine costs
(2,779
)
—

(3,722
)
—

—

(6,501
)
Cost of produced coal sold
$
267,121

$
—

$
248,344

$
—

$
—

$
515,465

Produced tons sold
3,757

—

6,902

—

—

10,659

Cost of produced coal sold per ton
$
71.10


$
—


$
35.98


$
—


$
—


$
48.36


64

Period from July 26, 2016 to December 31, 2016
(In thousands, except for per ton data)
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Cost of coal sales:
Cost of produced coal sold
$
77,291


$
—


$
83,744


$
—


$
29

$
161,064

Cost of purchased coal sold
14,321

—

17,349

122,667

—

154,337

Idle and closed mine costs
1,129

—

3,260

—

—

4,389

Total cost of coal sales
$
92,741

—

$
104,353

$
122,667

$
29

$
319,790

Tons sold
1,388

—

2,888

1,531

—

5,807

Cost of coal sales per ton
$
66.82


$
—


$
36.13


$
80.12


$
—


$
55.07

Total cost of coal sales
$
92,741


$
—


$
104,353


$
122,667


$
29

$
319,790

Less: cost of purchased coal sold
(14,321
)
—

(17,349
)
(122,667
)
—

(154,337
)
Less: idle and closed mine costs
(1,129
)
—

(3,260
)
—

—

(4,389
)
Cost of produced coal sold
$
77,291

$
—

$
83,744

$
—

$
29

$
161,064

Produced tons sold
1,302

—

2,402

—

—

3,704

Cost of produced coal sold per ton
$
59.36


$
—


$
34.86


$
—


$
—


$
43.48


Our management strives to aggressively control costs and improve operating performance to mitigate external cost pressures. We experience volatility in operating costs related to fuel, explosives, steel, tires, contract services and healthcare, among others, and take measures to mitigate the increases in these costs at all operations. We have a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods, and to support the business units. We promote competition between suppliers and seek to develop relationships with suppliers that focus on lowering our costs. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. We may also experience difficult geologic conditions, delays in obtaining permits, labor shortages, unforeseen equipment problems, and unexpected shortages of critical materials such as tires, fuel and explosives that may result in adverse cost increases and limit our ability to produce at forecasted levels.
Results of Operations

Our results of operations for the Successor period for the years ended December 31, 2018 and 2017 are discussed in these “Results of Operations” presented below. Given the change in basis that resulted from the Acquisition on July 26, 2016, we separately discuss our Successor and Predecessor results of operations and segment results for the results of operations for 2016.

Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017 (Successor)

The following tables summarize certain financial information relating to our operating results that have been derived from our Consolidated Financial Statements for the year ended December 31, 2018 and 2017.


65

Revenues
Year Ended December 31,
Increase (Decrease)
(In thousands, except for per ton data)
2018
2017
$ or Tons
%
Revenues:
Coal revenues:
Met
$
1,378,747

$
1,105,819

$
272,928

24.7
%
Thermal
279,014

286,662

(7,648
)
(2.7
)%
Freight and handling fulfillment revenues (1)
363,128

247,402

115,726

46.8
%
Other revenues
10,316

10,086

230

2.3
%
Total revenues
$
2,031,205

$
1,649,969

$
381,236

23.1
%
Tons sold:
Met
11,121

8,916

2,205

24.7
%
Thermal
6,466

6,741

(275
)
(4.1
)%
Total
17,587

15,657

1,930

12.3
%
Coal sales realization per ton (2) :
Met
$
123.98


$
124.03

$
(0.05
)
—
%
Thermal
$
43.15


$
42.53

$
0.62

1.5
%
Average
$
94.26


$
88.94

$
5.32

6.0
%
Year Ended December 31,
Increase (Decrease)
(In thousands, except for per ton data)
2018
2017
$ or Tons
%
Coal revenues (2) :
CAPP - Met operations
$
649,041

$
458,806

$
190,235

41.5
%
CAPP - Thermal operations
35,685

—

35,685

100.0
%
NAPP operations
281,175

301,789

(20,614
)
(6.8
)%
Trading and Logistics operations
691,860

631,886

59,974

9.5
%
Total coal revenues
$
1,657,761


$
1,392,481


$
265,280

19.1
%


Tons sold:


CAPP - Met operations
5,196

3,901

1,295

33.2
%
CAPP - Thermal operations
632

—

632

100.0
%
NAPP operations
6,273

6,904

(631
)
(9.1
)%
Trading and Logistics operations
5,486

4,852

634

13.1
%


Coal sales realization per ton (2) :


CAPP - Met operations
$
124.91

$
117.61

$
7.30

6.2
%
CAPP - Thermal operations
$
56.46

$
—

$
56.46

100.0
%
NAPP operations
$
44.82

$
43.71

$
1.11

2.5
%
Trading and Logistics operations
$
126.11

$
130.23

$
(4.12
)
(3.2
)%
Average
$
94.26

$
88.94

$
5.32

6.0
%
(1) Subsequent to the adoption of Accounting Standards Codification 606 during the current year, freight and handling fulfillment revenues for the year ended December 31, 2018 are included within coal revenues. See Note 5 .
(2) Does not include $363.1 million of freight and handling fulfillment revenues for the year ended December 31, 2018 .


66

Total revenues. Total revenues increased $381.2 million , or 23.1% , for the year ended December 31, 2018 compared to the prior year period. The increase in total revenues was due to increased coal revenues of $265.3 million , increased freight and handling fulfillment revenues of $115.7 million and increased other revenues of $0.2 million .

Coal revenues. Coal revenues increased $265.3 million , or 19.1% , for the year ended December 31, 2018 compared to the prior year period. The increase in coal revenues was due primarily to increased revenues of 41.5% and 9.5% for CAPP - Met and our Trading and Logistics operations, respectively, and the addition of revenues from the CAPP - Thermal operations during the current year period, partially offset by decreased revenues of 6.8% for NAPP.

The increase in CAPP - Met revenues was primarily due to higher coal sales volume of 1.3 million tons and increases in coal sales realization of $7.30 per ton. CAPP - Thermal revenues consisted of 0.6 million tons sold at a coal sales realization of $56.46 per ton. The decrease in NAPP revenues was primarily due to lower coal sales volumes of 0.6 million tons, partially offset by higher coal sales realization of $1.11 per ton. The increase in Trading and Logistics coal revenues was primarily due to higher sales volumes of 0.6 million tons, partially offset by lower coal sales realization of $4.12 per ton.

Our sales mix of met coal and thermal coal based on volume was 63.2% and 36.8%, respectively, for the year ended December 31, 2018 compared to 56.9% and 43.1%, respectively, in the prior year period. Our sales mix of met coal and thermal coal based on coal revenues, excluding freight and handling fulfillment revenues, was 83.2% and 16.8%, respectively, for the year ended December 31, 2018 compared to 79.4% and 20.6%, respectively, for the prior year period.

Met coal volumes increased 2.2 million tons due to increased export sales during the current period, and average coal realization per ton decreased $0.05 . Thermal coal volumes decreased 0.3 million tons due to increased longwall moves and geological factors during the current period, and average coal realization per ton increased $0.62 . The increase in coal revenues consisted of increased met coal revenue of $272.9 million , or 24.7% , partially offset by decreased thermal coal revenue of $7.6 million , or 2.7% .

Freight and handling fulfillment revenues were $363.1 million for the year ended December 31, 2018 , an increase of $115.7 million , or 46.8% , compared to the prior year period. This increase was primarily due to increased shipments by rail car and increased shipping rates during the current period.

Other revenues. Other revenues were $10.3 million for the year ended December 31, 2018 , an increase of $0.2 million , or 2.3% , compared to the prior year period, primarily attributable to a $2.0 million increase in coal royalty revenues and a $0.5 million increase in terminal revenues, partially offset by a $2.2 million decrease in rail transportation rebates.

Costs and Expenses
Year Ended December 31,
Increase (Decrease)
(In thousands, except for per ton data)
2018
2017
$ or Tons
%
Cost of coal sales (exclusive of items shown separately below)
$
1,297,990

$
1,079,895

$
218,095

20.2
%
Freight and handling costs
363,128

247,402

115,726

46.8
%
Depreciation, depletion and amortization
77,549

34,910

42,639

122.1
%
Accretion on asset retirement obligations
9,966

9,934

32

0.3
%
Amortization of acquired intangibles, net
(5,392
)
59,007

(64,399
)
(109.1
)%
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization shown separately above)
59,271

67,459

(8,188
)
(12.1
)%
Merger related costs
51,800

—

51,800

100.0
%
Secondary offering costs
—

4,491

(4,491
)
(100.0
)%
Total other operating (income) loss:




Mark-to-market adjustment for acquisition-related obligations
24

3,221

(3,197
)
(99.3
)%
Gain on settlement of acquisition-related obligations
(580
)
(38,886
)
38,306

98.5
%
Other (income) expense
(16,311
)
178

(16,489
)
(9,263.5
)%
Total costs and expenses
1,837,445

1,467,611

$
369,834

25.2
%

67

Other income (expense):





Interest expense
(38,810
)
(35,977
)
(2,833
)
(7.9
)%
Interest income
1,949

210

1,739

828.1
%
Loss on modification and extinguishment of debt
(12,042
)
(38,701
)
26,659

68.9
%
Equity loss in affiliates
(6,112
)
(3,339
)
(2,773
)
(83.0
)%
Bargain purchase gain
—

1,011

(1,011
)
(100.0
)%
Miscellaneous income, net
(1,254
)
194

(1,448
)
(746.4
)%
Total other expense, net
(56,269
)
(76,602
)
20,333

26.5
%
Income tax benefit
165,363

67,979

97,384

143.3
%
Net income from continuing operations
$
302,854

$
173,735

$
129,119

74.3
%




Cost of coal sales:




CAPP - Met operations
$
424,946

$
284,634

$
140,312

49.3
%
CAPP - Thermal operations
$
42,594

$
—

$
42,594

100.0
%
NAPP operations
$
241,652

$
252,113

$
(10,461
)
(4.1
)%
Trading and Logistics operations
$
587,857

$
543,148

$
44,709

8.2
%




Tons sold:




CAPP - Met operations
5,196

3,901

1,295

33.2
%
CAPP - Thermal operations
632

—

632

100.0
%
NAPP operations
6,273

6,904

(631
)
(9.1
)%
Trading and Logistics operations
5,486

4,852

634

13.1
%




Cost of coal sales per ton:




CAPP - Met operations
$
81.78

$
72.96

$
8.82

12.1
%
CAPP - Thermal operations
$
67.40

$
—

$
67.40

100.0
%
NAPP operations
$
38.52

$
36.52

$
2.00

5.5
%
Trading and Logistics operations
$
107.16

$
111.94

$
(4.78
)
(4.3
)%




Coal margin per ton (1) :




CAPP - Met operations
$
43.13

$
44.65

$
(1.52
)
(3.4
)%
CAPP - Thermal operations
$
(10.94
)
$
—

$
(10.94
)
(100.0
)%
NAPP operations
$
6.30

$
7.19

$
(0.89
)
(12.4
)%
Trading and Logistics operations
$
18.95

$
18.29

$
0.66

3.6
%
(1) Coal margin per ton for our reportable segments is calculated as coal sales realization per ton for our reportable segments less cost of coal sales per ton for our reportable segments. Coal margin per ton is not shown for our All Other category since it has no coal sales or coal production related to our continuing operations.

Cost of coal sales. Cost of coal sales increased $218.1 million , or 20.2% , for the year ended December 31, 2018 compared to the prior year period. The increase was primarily driven by increased purchases of tons associated with our Trading and Logistics operations segment, increased labor costs, and increased repair and maintenance activities during the current period.
Freight and handling costs. Freight and handling costs increased $115.7 million , or 46.8% , for the year ended December 31, 2018 compared to the prior year period. This increase was primarily due to increased shipments by rail car and increased shipping rates during the current period.
Depreciation, depletion and amortization. Depreciation, depletion and amortization increased $42.6 million , or 122.1% , for the year ended December 31, 2018 compared to the prior year period. The increase in depreciation, depletion and amortization primarily related to increased purchases of machinery and equipment, increased asset development during the current period, and additions of property, plant and equipment as a result of the Merger.

68

Amortization of acquired intangibles, net. Amortization of acquired intangibles, net decreased $64.4 million , or 109.1% , for the year ended December 31, 2018 compared to the prior year period. The decrease was primarily driven by the write-off of above-market coal sales contract assets during 2017 associated with the sale of PRB, certain other above-market coal sales contract assets being fully amortized as of December 31, 2017, and the amortization related to below-market acquired intangibles acquired as a result of the Merger, partially offset by the accelerated amortization of acquired intangibles related to the above-market coal sales contract asset related to FirstEnergy Generation, LLC during the current period.
Selling, general and administrative. Selling, general and administrative expenses decreased $8.2 million , or 12.1% for the year ended December 31, 2018 compared to the prior year period. This decrease in expense was primarily related to decreases of $7.2 million in stock compensation expense and $5.1 million in professional services fees, partially offset by increases of $3.0 million in incentive bonus plans and $2.5 million in severance pay during the current period.
Merger related costs. The Merger related costs of $51.8 million recorded during the year ended December 31, 2018 related primarily to professional fees, severance pay and incentive pay incurred related to the Merger Agreement entered into with the Alpha Companies on April 29, 2018.
Secondary offering costs. The secondary offering costs of $4.5 million recorded during the year ended December 31, 2017 related to (i) legal fees for drafting the registration statement and other legal services directly related to the withdrawn offering and (ii) financial reporting advisory fees directly related to the withdrawn offering including preparation of the pro forma financial statements and other financial information included in the registration statement.
Acquisition-related obligations. For the year ended December 31, 2018 the Company recorded a mark-to-market loss on acquisition-related obligations of $24 thousand related to the Contingent Revenue Obligation. The mark-to-market loss on acquisition-related obligations of $3.2 million for the year ended December 31, 2017 primarily consisted of a mark-to-market loss of $2.5 million related to the Contingent Reclamation Funding Liability and a mark-to-market loss of $0.7 million related to the Contingent Credit Support Commitment. The gain on settlement of acquisition-related obligations of $38.9 million for the year ended December 31, 2017 primarily consisted of the UMWA Contingent VEBA Funding Notes 1 and Note 2 settlements.
Other (income) expense. Other (income) expense decreased $16.5 million for the year ended December 31, 2018 compared to the prior year period. This decrease primarily related to the gain on disposal of assets of $16.9 million recorded during the year ended December 31, 2018 related to the sale of a disposal group within the Company’s CAPP - Met segment.
Interest expense. Interest expense increased $2.8 million , or 7.9% , for the year ended December 31, 2018 compared to the prior year period, primarily due to higher interest costs associated with Company debt as a result of the current year debt refinancing. See Note 15 for additional information.
Loss on modification and extinguishment of debt. The loss on modification and extinguishment of debt of $12.0 million for the year ended December 31, 2018 primarily related to the write-off of certain outstanding debt discounts, debt issuance costs and debt fees incurred in connection with the Amended and Restated Credit Agreement entered into by the Company on November 9, 2018. For the year ended December 31, 2017 the Company incurred a loss on modification and extinguishment of debt of $38.7 million , primarily related to a prepayment premium of $22.5 million on the 10.00% Senior Secured First Lien Notes and the write-off of outstanding debt discounts of $13.4 million on the 10.00% Senior Secured First Lien Notes and GUC Distribution Note in connection with the Credit Agreement entered into by the Company on March 17, 2017.
Income taxes. Income tax benefit of $165.4 million was recorded for the year ended December 31, 2018 on income from continuing operations before income taxes of $137.5 million . The effective tax rate is lower than the federal statutory rate of 21% primarily due to the impact of the net operating loss carryback benefit and the reduction in the valuation allowance.

Income tax benefit of $68.0 million was recorded for the year ended December 31, 2017 on income from continuing operations before income taxes of $105.8 million . The effective tax rate is lower than the federal statutory rate of 35% primarily due to the impact of the percentage depletion allowance and the reduction in the valuation allowance, partially offset by the revaluation of the net deferred tax assets as a result of the enactment of the Tax Cuts and Jobs Act. See Note 21 for additional information.

Segment Adjusted EBITDA

Segment Adjusted EBITDA for our reportable segments is a financial measure. This non-GAAP financial measure is presented as a supplemental measure and is not intended to replace financial performance measures determined in accordance

69

with GAAP. Moreover, this measure is not calculated identically by all companies and therefore may not be comparable to similarly titled measures used by other companies. Segment Adjusted EBITDA is presented because management believes it is a useful indicator of the financial performance of our coal operations. The following tables presents a reconciliation of net income (loss) to Adjusted EBITDA for the year ended December 31, 2018 and 2017:
Successor
Year Ended December 31, 2018
(In thousands)
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Net income (loss) from continuing operations
$
193,422

$
(18,974
)
$
18,651

$
107,196

$
2,559

$
302,854

Interest expense
260

1

(1,286
)
—

39,835

38,810

Interest income
(22
)
—

(34
)
(18
)
(1,875
)
(1,949
)
Income tax benefit
—

—

—

—

(165,363
)
(165,363
)
Depreciation, depletion and amortization
40,330

10,596

23,273

—

3,350

77,549

Merger related costs
—

1

—

22

51,777

51,800

Management restructuring costs (1)
—

—

—

—

2,659

2,659

Non-cash stock compensation expense
73

24

—

335

11,546

11,978

Mark-to-market adjustment - acquisition-related obligations
—

—

—

—

24

24

Gain on settlement of acquisition-related obligations
—

—

—

—

(580
)
(580
)
Gain on sale of disposal group (2)
(16,386
)
—

—

—

—

(16,386
)
Accretion on asset retirement obligations
4,430

1,298

3,764

—

474

9,966

Loss on modification and extinguishment of debt
—

—

—

—

12,042

12,042

Cost impact of coal inventory fair value adjustment (3)
11,547

5,517

—

—

—

17,064

Amortization of acquired intangibles, net
2,746

662

—

(8,800
)
—

(5,392
)
Adjusted EBITDA
$
236,400

$
(875
)
$
44,368

$
98,735

$
(43,552
)
$
335,076

(1) Management restructuring costs are related to severance expense associated with senior management changes in the year ended December 31, 2018 .
(2) During the fourth quarter of 2017, we entered into an asset purchase agreement to sell a disposal group (comprised of property, plant and equipment and associated asset retirement obligations) within our CAPP - Met segment. From the date we entered into the asset purchase agreement through the transaction close date, the property, plant and equipment and associated asset retirement obligations were classified as held for sale in amounts representing the fair value of the disposal group. Upon permit transfer, the transaction closed on April 2, 2018. We paid $10.0 million in connection with the transaction, which was paid into escrow on March 27, 2018 and transferred to the buyer at the transaction close date, and expect to pay a series of additional cash payments in the aggregate amount of $1.5 million, per the terms stated in the agreement, and recorded a gain on sale of approximately $16.4 million within other (income) expense in the Consolidated Statements of Operations.
(3) The cost impact of the coal inventory fair value adjustment as a result of the Alpha Merger is expected to have short-term impact.



70

Successor
Year Ended December 31, 2017
(In thousands)
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Net income (loss) from continuing operations
$
150,304

$
—

$
36,604

$
29,639

$
(42,812
)
$
173,735

Interest expense
(90
)
—

(1,505
)
—

37,572

35,977

Interest income
(22
)
—

(1
)
—

(187
)
(210
)
Income tax benefit
—

—

—

—

(67,979
)
(67,979
)
Depreciation, depletion and amortization
18,941

—

15,087

—

882

34,910

Non-cash stock compensation expense
—

—

—

650

19,559

20,209

Mark-to-market adjustment - acquisition-related obligations
—

—

—

—

3,221

3,221

Gain on settlement of acquisition-related obligations
—

—

—

—

(38,886
)
(38,886
)
Secondary offering costs
—

—

—

—

4,491

4,491

Loss on modification and extinguishment of debt
—

—

—

—

38,701

38,701

Bargain purchase gain
—

—

—

—

(1,011
)
(1,011
)
Accretion on asset retirement obligations
5,770

—

4,164

—

—

9,934

Amortization of acquired intangibles, net
—

—

—

59,007

—

59,007

Expenses related to the dividend
115

—

84

—

6,168

6,367

Adjusted EBITDA (1) (2)
$
175,018


$
—

$
54,433


$
89,296


$
(40,281
)

$
278,466

(1) Our Adjusted EBITDA calculation has been modified to add back non-cash stock compensation expense and accretion on asset retirement obligations, a non-cash expense, to align with industry peer group methodology.
(2) Pursuant to the PRB divestiture and classification as a discontinued operation, we are no longer presenting a PRB reporting segment. The former PRB reporting segment had Adjusted EBITDA of $41.9 million for the year ended December 31, 2017 .

The following table summarizes Adjusted EBITDA for our three reportable segments and All Other category:
Year Ended December 31,
Increase (Decrease)
(In thousands)
2018
2017
$ or Tons
%
Adjusted EBITDA
CAPP - Met operations
$
236,400

$
175,018

$
61,382

35.1
%
CAPP - Thermal operations
$
(875
)
$
—

$
(875
)
(100.0
)%
NAPP operations
$
44,368

$
54,433

$
(10,065
)
(18.5
)%
Trading and Logistics operations
$
98,735

$
89,296

$
9,439

10.6
%
All Other
$
(43,552
)
$
(40,281
)
$
(3,271
)
(8.1
)%
Total
$
335,076


$
278,466


$
56,610

20.3
%

CAPP - Met operations. Adjusted EBITDA increased $61.4 million , or 35.1% , for the year ended December 31, 2018 compared to the prior year period. The increase in Adjusted EBITDA was primarily driven by increased average sales realization per ton of $7.30 , or approximately 6.2% , due primarily to increases in the market pricing of coal during the current period and increased sales volumes.
CAPP - Thermal operations. Adjusted EBITDA for the CAAP - Thermal operations was ($0.9) million for the year ended December 31, 2018 . The prior year period did not have any activity in this segment and therefore the current year results explain the entire amount of change. The primary driver for adjusted EBITDA during the current year period related to repair and maintenance costs and costs associated with certain idled properties.

71

NAPP operations. Adjusted EBITDA decreased $10.1 million , or 18.5% , for the year ended December 31, 2018 compared to the prior year period. The decrease in Adjusted EBITDA was primarily due to decreased coal margin per ton of $0.89 . The decrease in coal margin per ton consisted of increased average cost of coal sales per ton of $2.00 , or approximately 5.5% , due primarily to reductions in tons sold due to geological factors during the current period.
Trading and Logistics operations. Adjusted EBITDA increased $9.4 million , or 10.6% , for the year ended December 31, 2018 compared to the prior year period. The increase in Adjusted EBITDA was primarily due to increased sales volumes during the current period and an increase in coal margin per ton of $0.66 .

All Other category. Adjusted EBITDA decreased $3.3 million , or 8.1% , for the year ended December 31, 2018 compared to the prior year period. The decrease in Adjusted EBITDA was primarily driven by increases in incentive pay and severance related expenses during the current period.

Period from July 26, 2016 to December 31, 2016 (Successor)
The following tables summarize certain financial information relating to our operating results that have been derived from our consolidated financial statements for the period from July 26, 2016 to December 31, 2016. Also included is certain information relating to the operating results as a percentage of total revenues.

72

Revenues
Successor
(In thousands, except for per ton data)
Period from
July 26, 2016 to December 31, 2016
% of Total Revenues
Revenues:
Coal revenues:
Met
$
312,503

61.7
%
Thermal
119,189

23.6
%
Freight and handling revenues
70,544

13.9
%
Other revenues
4,060

0.8
%
Total revenues
$
506,296

100.0
%
Tons sold:
Met
3,068

Thermal
2,739

Total
5,807

Coal sales realization per ton:
Met
101.86

Thermal
43.52

Average
74.34

Successor
(In thousands, except for per ton data)
Period from
July 26, 2016 to December 31, 2016
% of Total Revenues
Coal revenues (1) :
CAPP - Met operations
$
137,981

27.3
%
CAPP - Thermal operations
—

—
%
NAPP operations
129,961

25.7
%
Trading and Logistics operations
163,750

32.3
%
Total coal revenues
$
431,692

85.3
%
Tons sold:
CAPP - Met operations
1,388

CAPP - Thermal operations
—

NAPP operations
2,888

Trading and Logistics operations
1,531

Coal sales realization per ton (1) :
CAPP - Met operations
$
99.41

CAPP - Thermal operations
$
—

NAPP operations
$
45.00

Trading and Logistics operations
$
106.96

Average
$
74.34

(1)
Does not include any portion of the price paid by our export customers to transport coal to the relevant outbound shipping port.


73

Total revenues were $506.3 million for the period from July 26, 2016 to December 31, 2016 and consisted of coal revenues of $431.7 million, freight and handling revenues of $70.5 million and other revenues of $4.1 million. Our sales mix of met coal and thermal coal based on volume was 52.8% and 47.2%, respectively, and our sales mix of met coal and thermal coal based on coal revenues was 72.4% and 27.6%, respectively, for the period from July 26, 2016 to December 31, 2016. Average coal sales realization per ton was $74.34. CAPP - Met, NAPP, and Trading and Logistics operations’ coal revenues comprised 27%, 26%, and 32%, respectively, of total revenues for the period from July 26, 2016 to December 31, 2016.
Costs and Expenses
Successor
(In thousands, except for per ton data)
Period from
July 26, 2016 to December 31, 2016
% of Total Revenues
Cost of coal sales (exclusive of items shown separately below)
$
319,790

63.2
%
Freight and handling costs
70,544

13.9
%
Depreciation, depletion and amortization
5,973

1.2
%
Accretion on asset retirement obligations
4,800

0.9
%
Amortization of acquired intangibles, net
61,281

12.1
%
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization shown separately above)
19,135

3.8
%
Mark-to-market adjustment for acquisition-related obligations
(10,616
)
(2.1
)%
Total costs and expenses
470,907

93.0
%
Other (expense) income:
Interest expense
(20,496
)
(4.0
)%
Interest income
23

—
%
Equity loss in affiliates
(2,287
)
(0.5
)%
Mark-to-market adjustment for warrant derivative liability
(33,975
)
(6.7
)%
Bargain purchase gain
7,719

1.5
%
Miscellaneous expense, net
(139
)
—
%
Total other expense, net
(49,155
)
(9.7
)%
Income tax benefit
1,920

0.4
%
Net loss from continuing operations
$
(11,846
)
(2.3
)%
Cost of coal sales:
CAPP - Met operations
$
92,741

18.3
%
CAPP - Thermal operations
$
—

—
%
NAPP operations
$
104,353

20.6
%
Trading and Logistics operations
$
122,667

24.2
%
Tons sold:
CAPP - Met operations
1,388

CAPP - Thermal operations
—

NAPP operations
2,888

Trading and Logistics operations
1,531

Cost of coal sales per ton (1) :
CAPP - Met operations
$
66.82

CAPP - Thermal operations
$
—

NAPP operations
$
36.13

Trading and Logistics operations
$
80.12


74

Coal margin per ton (2) :
CAPP - Met operations
$
32.59

CAPP - Thermal operations
$
—

NAPP operations
$
8.87

Trading and Logistics operations
$
26.84

(1)
Cost of coal sales per ton exclude costs associated with our All Other category.
(2)
Coal margin per ton for our reportable segments is calculated as coal sales realization per ton for our reportable segments less cost of coal sales per ton for our reportable segments. Coal margin per ton is not shown for our All Other category since it has no coal sales or coal production related to our continuing operations.

Cost of coal sales was $319.8 million , freight and handling costs were $70.5 million, depreciation, depletion and amortization was $6.0 million, accretion on asset retirement obligations was $4.8 million , amortization of acquired intangibles, net was $61.3 million and selling, general and administrative expenses were $19.1 million for the period from July 26, 2016 to December 31, 2016.
The mark-to-market gain on acquisition-related obligations of $10.6 million for the period from July 26, 2016 to December 31, 2016 consisted of a mark-to-market gain of $17.4 million related to the Contingent Credit Support Commitment and a mark-to-market loss of $6.8 million related to the Contingent Reclamation Funding Liability.
The change in fair value of the Contingent Credit Support Commitment resulted from a reduction in our estimated obligation to provide ANR with revolving credit support. The fair value calculation was based on a probability-weighted scenario analysis. The inputs to this analysis included ANR’s projected short-term cash flows, which were derived from the ANR financial statements and operating budget provided pursuant to the terms of the agreement. The cash position of ANR at December 31, 2016 increased relative to the projections used at the Acquisition Date resulting in a gain of $17.4 million in the estimated fair value of this obligation. Based on relevant factors including ANR’s current cash balance, near-term estimated met coal prices, the September 30, 2018 termination date to loan funds, and the provision that loans can only be requested if ANR’s unrestricted cash is below $20.0 million, we adjusted the liability down to $4.6 million for this obligation. Absent a significant change in ANR’s cash position and related projections, we do not expect the obligation to change significantly.
Due to the increase in met coal prices and the corresponding improvement to our financial results, our credit-adjusted risk-free rate as of December 31, 2016 decreased relative to the rate used to discount the Contingent Reclamation Funding Liability at the Acquisition Date. The reduction in the credit-adjusted risk-free rate used to discount the projected obligation was the primary driver of the loss of $6.8 million. Due to the long-term nature of this obligation and the uncertainty of ANR’s operational results over the life of the obligation, we maintained the expectations utilized at the Acquisition Date related to ANR’s expected long-term contributions to the Restricted Cash Reclamation Accounts.
Interest expense of $20.5 million for the period from July 26, 2016 to December 31, 2016 consisted of the accrued interest on debt instruments and acquisition-related obligations, including discounts, resulting from the Acquisition.
The mark-to-market loss on the warrant derivative liability of $34.0 million for the period from July 26, 2016 to December 31, 2016 related to the warrants issued in connection with the Acquisition and was calculated using the Black-Scholes pricing model. The warrants are marked to market at each reporting period with changes in value reflected in earnings. The inputs included in the Black-Scholes pricing model include our stock price, the stated exercise price, the expected term, the annual risk-free interest rate based on the U.S. Constant Maturity Curve and annualized equity volatility. The annualized volatility was calculated by observing volatilities for comparable companies with adjustments for our size and leverage. The annualized volatility as of December 31, 2016 decreased relative to the annualized volatility used as of the Acquisition Date due to the significant improvement in our leverage ratio. However, our stock price as of December 31, 2016 was also significantly higher than our stock price at the Acquisition Date and was the primary driver of the mark-to-market loss of $34.0 million recognized for the warrant derivative liability.
The bargain purchase gain of $7.7 million for the period from July 26, 2016 to December 31, 2016 resulted from the excess of the fair value of the acquired assets over liabilities assumed through the Acquisition.
Income tax benefit of $1.9 million was recorded for the period from July 26, 2016 to December 31, 2016 on loss from continuing operations before income taxes of $13.8 million. The income tax rate differs from the federal statutory rate of 35% primarily due to the impact of the non-deductible mark-to-market adjustment for the warrant derivative liability, partially offset by the impact of the percentage depletion allowance and the reduction in the valuation allowance. See Note 21 for additional information.

75

Segment Adjusted EBITDA
Segment Adjusted EBITDA for our reportable segments is a non-GAAP financial measure. This non-GAAP financial measure is presented as a supplemental measure and is not intended to replace financial performance measures determined in accordance with GAAP. Moreover, this measure is not calculated identically by all companies and therefore may not be comparable to similarly titled measures used by other companies. Segment Adjusted EBITDA is presented because ANR’s management believes it is a useful indicator of the financial performance of our coal operations. The following table presents a reconciliation of net income (loss) to Adjusted EBITDA for the period from July 26, 2016 to December 31, 2016:
Successor
Period from July 26, 2016 to December 31, 2016
(In thousands)
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Net income (loss) from continuing operations
$
37,436

$
—

$
26,434

$
(22,053
)
$
(53,663
)
$
(11,846
)
Interest expense
97

—

171

—

20,228

20,496

Interest income
(6
)
—

—

—

(17
)
(23
)
Income tax benefit
—

—

—

—

(1,920
)
(1,920
)
Depreciation, depletion and amortization
6,442

—

(772
)
—

303

5,973

Non-cash stock compensation expense
—

—

—

37

1,387

1,424

Mark-to-market adjustment for warrant derivative liability
—

—

—

—

33,975

33,975

Bargain purchase gain
—

—

—

—

(7,719
)
(7,719
)
Mark-to-market adjustment - acquisition-related obligations
—

—

—

—

(10,616
)
(10,616
)
Accretion on asset retirement obligations
2,435

—

2,365

—

—

4,800

Amortization of acquired intangibles, net
—

—

—

61,281

—

61,281

Adjusted EBITDA (1) (2)
$
46,404

$
—

$
28,198

$
39,265

$
(18,042
)
$
95,825

(1)
Our Adjusted EBITDA calculation has been modified to add back non-cash stock compensation expense and accretion on asset retirement obligations, a non-cash expense, to align with industry peer group methodology.
(2)
Pursuant to the PRB divestiture and classification as a discontinued operation, we are no longer presenting a PRB reporting segment. The former PRB reporting segment had adjusted EBITDA of $45.8 million for the period from July 26, 2016 to December 31, 2016.

CAPP- Met operations. Adjusted EBITDA was $46.4 million for the period from July 26, 2016 to December 31, 2016, driven by coal margin per ton of $32.59 , coal sales realization per ton of $99.41 and cost of coal sales per ton of $66.82 .
NAPP operations. Adjusted EBITDA was $28.2 million for the period from July 26, 2016 to December 31, 2016, driven by coal margin per ton of $8.87 , coal sales realization per ton of $45.00 and cost of coal sales per ton of $36.13 .
Trading and Logistics operations. Adjusted EBITDA was $39.3 million for the period from July 26, 2016 to December 31, 2016, driven by coal margin per ton of $26.84, coal sales realization per ton of $106.96 and cost of coal sales per ton of $80.12.
All Other category. Adjusted EBITDA was ($18.0) million for the period from July 26, 2016 to December 31, 2016, primarily driven by wages and benefits expense of $7.4 million, professional fees of $4.0 million, incentive pay of $3.2 million, and rent, utilities and property costs of $0.6 million
Period from January 1, 2016 to July 25, 2016 (Predecessor)
The following tables summarize certain financial information relating to our operating results that have been derived from our combined financial statements for the period from January 1, 2016 to July 25, 2016. Also included is certain information relating to the operating results as a percentage of total revenues.

76

Revenues
Predecessor
(In thousands, except for per ton data)
Period from
January 1, 2016 to July 25, 2016
% of Total Revenues
Revenues:
Coal revenues:
Met
$
147,557

35.9
%
Thermal
197,135

48.0
%
Freight and handling revenues
52,076

12.7
%
Other revenues
14,343

3.4
%
Total revenues
$
411,111

100.0
%
Tons sold:
Met
2,576

Thermal
4,424

Total
7,000

Coal sales realization per ton:
Met
$
57.28

Thermal
$
44.56

Average
$
49.24

Predecessor
(In thousands, except for per ton data)
Period from
January 1, 2016 to July 25, 2016
% of Total Revenues
Coal revenues (1) :
CAPP - Met operations
$
131,640

32.0
%
CAPP - Thermal operations
—

—
%
NAPP operations
204,473

49.7
%
Trading and Logistics operations
8,579

2.1
%
Total coal revenues
$
344,692

83.8
%
Tons sold:
CAPP - Met operations
2,189

CAPP - Thermal operations
—

NAPP operations
4,654

Trading and Logistics operations
157

Coal sales realization per ton (1) :
CAPP - Met operations
$
60.14

CAPP - Thermal operations
$
—

NAPP operations
$
43.93

Trading and Logistics operations
$
54.64

Average
$
49.24

(1)
Does not include any portion of the price paid by our export customers to transport coal to the relevant outbound shipping port.


77

Total revenues were $411.1 million for the period from January 1, 2016 to July 25, 2016 and consisted of coal revenues of $344.7 million, freight and handling revenues of $52.1 million and other revenues of $14.3 million. Our sales mix of met coal and thermal coal based on volume was 36.8% and 63.2%, respectively, and our sales mix of met coal and thermal coal based on coal revenues was 42.8% and 57.2%, respectively, for the period from January 1, 2016 to July 25, 2016. Average coal sales realization per ton was $49.24. CAPP - Met, NAPP and Trading and Logistics operations’ coal revenues comprised 32%, 50% and 2%, respectively, of total revenues for the period from January 1, 2016 to July 25, 2016.
Costs and Expenses
Predecessor
(In thousands, except for per ton data)
Period from
January 1, 2016 to July 25, 2016
% of Total Revenues
Cost of coal sales (exclusive of items shown separately below)
$
305,276

74.3
%
Freight and handling costs
52,076

12.7
%
Depreciation, depletion and amortization
66,076

16.1
%
Accretion on asset retirement obligations
5,005

1.2
%
Amortization of acquired intangibles, net
11,567

2.8
%
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization shown separately above)
29,568

7.2
%
Asset impairment and restructuring
3,096

0.8
%
Other expenses
2,184

0.5
%
Total costs and expenses
474,848

115.5
%
Other (expense) income:
Interest expense
(2
)
—
%
Interest income
19

—
%
Equity loss in affiliates
(2,735
)
(0.7
)%
Miscellaneous expense, net
(13,978
)
(3.4
)%
Total other expense, net
(16,696
)
(4.1
)%
Reorganization items, net
(20,989
)
(5.1
)%
Income tax benefit
39,881

9.7
%
Net loss from continuing operations
$
(61,541
)
(15.0
)%
Cost of coal sales:
CAPP - Met operations
$
129,759

31.6
%
CAPP - Thermal operations
$
—

—
%
NAPP operations
$
167,822

40.8
%
Trading and Logistics operations
$
7,695

1.9
%
Tons sold:
CAPP - Met operations
2,189

CAPP - Thermal operations
—

NAPP operations
4,654

Trading and Logistics operations
157

Cost of coal sales per ton (1) :
CAPP - Met operations
$
59.28

CAPP - Thermal operations
$
—

NAPP operations
$
36.06

Trading and Logistics operations
$
49.01


78

Coal margin per ton (2) :
CAPP - Met operations
$
0.86

CAPP - Thermal operations
$
—

NAPP operations
$
7.87

Trading and Logistics operations
$
5.63

(1)
Cost of coal sales per ton exclude costs associated with our All Other category.
(2)
Coal margin per ton for our reportable segments is calculated as coal sales realization per ton for our reportable segments less cost of coal sales per ton for our reportable segments. Coal margin per ton is not shown for our All Other category since it has no coal sales or coal production related to our continuing operations.

Cost of coal sales was $305.3 million , freight and handling costs were $52.1 million, other expenses were $2.2 million, depreciation, depletion and amortization was $66.1 million, accretion on asset retirement obligations was $5.0 million , amortization of acquired intangibles, net was $11.6 million and selling, general and administrative expenses were $29.6 million for the period from January 1, 2016 to July 25, 2016.
Asset impairment and restructuring expenses of $3.1 million for the period from January 1, 2016 to July 25, 2016 consisted of $2.1 million of losses related to non-core property divestitures and $1.0 million related to severance expenses and other restructuring-related charges.
Reorganization items, net of $21.0 million for the period from January 1, 2016 to July 25, 2016 primarily consisted of realized gains and losses from the settlement of pre-petition liabilities, professional fees, and provisions for losses resulting from Predecessor Alpha’s Restructuring.
Income tax benefit of $39.9 million was recorded for the period from January 1, 2016 to July 25, 2016 on a loss from continuing operations before income taxes of $101.4 million. The income tax rate differs from the federal statutory rate of 35% primarily due to the impact of the percentage depletion allowance and state income taxes, net of federal tax impact, partially offset by the impact of the non-deductible transaction costs. See Note 21 for additional information.
Segment Adjusted EBITDA

Segment Adjusted EBITDA for our reportable segments is a non-GAAP financial measure. This non-GAAP financial measure is presented as a supplemental measure and is not intended to replace financial performance measures determined in accordance with GAAP. Moreover, this measure is not calculated identically by all companies and therefore may not be comparable to similarly titled measures used by other companies. Segment Adjusted EBITDA is presented because ANR’s management believes it is a useful indicator of the financial performance of our coal operations. The following table presents a reconciliation of net (loss) income to Adjusted EBITDA for the period from January 1, 2016 to July 25, 2016 :

79

Predecessor
Period from January 1, 2016 to July 25, 2016
(In thousands)
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Combined
Net income (loss) from continuing operations
$
(26,407
)
$
—

$
(43,143
)
$
(1,452
)
$
9,461

$
(61,541
)
Interest expense
2

—

—

—

—

2

Interest income
(9
)
—

(10
)
—

—

(19
)
Income tax benefit
—

—

—

—

(39,881
)
(39,881
)
Depreciation, depletion and amortization
15,389

—

49,852

3

832

66,076

Non-cash stock compensation expense
34

—

61

—

498

593

Reorganization items, net
8,196

—

12,528

248

17

20,989

Asset impairment and restructuring
1,667

—

1,408

21

—

3,096

Accretion on asset retirement obligations
1,753

—

3,252

—

—

5,005

Amortization of acquired intangibles, net
—

—

11,567

—

—

11,567

Adjusted EBITDA (1) (2)
$
625

$
—

$
35,515

$
(1,180
)
$
(29,073
)
$
5,887

(1)
Our Adjusted EBITDA calculation has been modified to add back non-cash stock compensation expense and accretion on asset retirement obligations, a non-cash expense, to align with industry peer group methodology.
(2)
Pursuant to the PRB divestiture and classification as a discontinued operation, we are no longer presenting a PRB reporting segment. The former PRB reporting segment had adjusted EBITDA of $36.9 million for the period from January 1, 2016 to July 25, 2016.

CAPP - Met operations. Adjusted EBITDA was $0.6 million for the period from January 1, 2016 to July 25, 2016, driven by coal margin per ton of $0.86 , coal sales realization per ton of $60.14 and cost of coal sales per ton of $59.28 .
NAPP operations. Adjusted EBITDA was $35.5 million for the period from January 1, 2016 to July 25, 2016, driven by coal margin per ton of $7.87 , coal sales realization per ton of $43.93 and cost of coal sales per ton of $36.06 .
Trading and Logistics operations. Adjusted EBITDA was ($1.2) million for the period from January 1, 2016 to July 25, 2016, driven by coal margin per ton of $5.63, coal sales realization per ton of $54.64 and cost of coal sales per ton of $49.01.
All Other category. Adjusted EBITDA was ($29.1) million for the period from January 1, 2016 to July 25, 2016, primarily driven by wages and benefits expense of $8.9 million, incentive pay of $8.1 million, professional fees of $5.8 million, and rent, utilities and property costs of $5.0 million.

Liquidity and Capital Resources
Our primary liquidity and capital resource requirements stem from the cost of our coal production and purchases, our capital expenditures, our debt service, our reclamation obligations, our regulatory costs and settlements and associated costs. Our primary sources of liquidity are derived from sales of coal, our debt financing and miscellaneous revenues.
We believe that cash on hand and cash generated from our operations will be sufficient to meet our working capital requirements, anticipated capital expenditures, debt service requirements, acquisition-related obligations, and reclamation obligations for the next 12 months. We have relied on a number of assumptions in budgeting for our future activities. These include the costs for mine development to sustain capacity of our operating mines, our cash flows from operations, effects of regulation and taxes by governmental agencies, mining technology improvements and reclamation costs. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if market conditions deteriorate, and we may not be able to do so in a timely fashion, or at all; or one or more of our assumptions proves to be incorrect or if we choose to expand our acquisition, exploration, appraisal, or development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell equity or debt securities or obtain

80

additional bank credit facilities. The sale of equity securities could result in dilution to our stockholders. The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations.

At December 31, 2018 , we had total liquidity of $429.9 million, including cash and cash equivalents of $233.6 million and $196.3 million of unused commitments available under the Amended and Restated Asset-Based Revolving Credit Agreement, subject to limitations described therein. On November 9, 2018, we entered into a $550.0 million term loan credit facility under the Amended and Restated Credit Agreement with a maturity date of November 9, 2025, and a $225.0 million asset-based revolving credit facility under the Amended and Restated Asset-Based Revolving Credit Agreement expiring on April 3, 2022. Refer to Note 15 for disclosures on long-term debt.

On November 9, 2018, Contura, along with the Alpha Companies, completed the Merger in which the Company acquired 100% of the outstanding Class C-1 shares of ANR and the 100% of the outstanding shares of Holdings. Prior to the closing of the transaction, the Alpha Companies stockholders also received a special cash dividend (the “Dividend”). Refer to Note 3 for additional disclosures surrounding these amounts. Additionally, on November 6, 2018, Contura, the Alpha Companies and the West Virginia Department of Environmental Protection (the “WVDEP”) entered into a binding term sheet agreement to resolve certain issues related to the issuance of the Dividend under the Permitting and Reclamation Plan Settlement Agreement for the State of West Virginia dated as of July 12, 2016. The agreement, among other things, required the posting of collateral to secure Contura’s and ANR’s payment obligations under the Amended Reclamation Funding Agreement and the Amended Settlement Agreement until a performance bond was issued as described in the following sentence. The performance bond was issued during the fourth quarter of 2018. Refer to Note 26 for disclosures surrounding the WVDEP Settlement Agreement.

We sponsor three qualified non-contributory pension plans (“Pension Plans”)  which cover certain salaried and non-union hourly employees. Participants accrued benefits either based on certain formulas, the participant’s compensation prior to retirement or plan specified amounts for each year of service. Benefits are frozen under these Pension Plans. Annual funding contributions to the Pension Plans are made as recommended by consulting actuaries based upon the ERISA funding standards. Funding decisions also consider certain funded status thresholds defined by the Pension Protection Act of 2006. We expect to contribute $6.4 million to the Pension Plans in 2019. See Note 22 for further disclosures related to this obligation.

To secure our obligations under certain worker’s compensation, black lung, reclamation-related obligations, general liabilities, and financial guarantees, we are required to provide cash collateral. At December 31, 2018 , we had cash collateral in the amounts of $243.6 million, $24.0 million, and $29.1 million classified as short-term and long-term restricted cash, short-term and long-term deposits, and long-term restricted investments, respectively, on our balance sheet. Once the permits associated with the PRB transaction have been transferred, we estimate approximately $12.6 million, comprised of short-term restricted cash and short-term deposits, will be returned to operating cash. If the permit transfer process is not completed as expected, it could have material, adverse effects on us.

Cash Flows

Cash, cash equivalents, and restricted cash increased by $283.3 million , $22.7 million , $171.3 million , and $16.2 million over the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016, respectively. The net change in cash, cash equivalents, and restricted cash was attributable to the following:
Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Cash flows (in thousands):
Net cash provided by operating activities
$
158,381

$
314,260

$
21,459

$
77,029

Net cash provided by (used in) investing activities
102,196

(121,307
)
108,352

(25,029
)
Net cash provided by (used in) financing activities
22,709

(170,282
)
41,478

(35,822
)
Net increase in cash, cash equivalents, and restricted cash
$
283,286

$
22,671

$
171,289

$
16,178


Operating Activities

Net cash flows from operating activities consist of net income adjusted for non-cash items, such as depreciation, depletion and amortization, amortization of acquired intangibles, net, accretion and settlement of acquisition-related obligations discount,

81

amortization of debt issuance costs and accretion of debt discount, mark-to-market adjustments for acquisition related obligations, equity loss in affiliates, accretion on asset retirement obligations, employee benefit plans, deferred income taxes, loss on extinguishment of debt, loss on disposals, and changes in net working capital.

Net cash provided by operating activities for the year ended December 31, 2018 was $158.4 million and was primarily attributable to net income of $299.2 million adjusted for depreciation, depletion and amortization of $77.5 million , employee benefit plans, net of $9.2 million , accretion on asset retirement obligations of $10.0 million , loss on modification and extinguishment of debt of $12.0 million and stock-based compensation of $13.4 million , partially offset by a $16.9 million gain on disposal of assets and changes in deferred income taxes of $66.7 million. The change in our operating assets and liabilities of ($191.3) million was primarily attributed to increases in trade accounts receivable of $84.1 million, increases in prepaid expenses and other current assets of $44.3 million, increases in other non-current assets of $36.7 million, decreases in acquisition-related obligations of $14.5 million, and decreases in other non-current liabilities of $19.9 million, partially offset by decreases in inventories, net of $33.2 million.

Net cash provided by operating activities for the year ended December 31, 2017 was $314.3 million and was primarily attributed to net income of $154.5 million adjusted for depreciation, depletion and amortization of $65.0 million , amortization of acquired intangibles, net of $59.0 million , accretion on asset retirement obligations of $21.3 million , loss on sale of Powder River Basin of $36.1 million, stock based compensation of $20.4 million, and loss on modification and extinguishment of debt of $38.7 million , partially offset by a $38.9 million gain on settlement of acquisition-related obligations and changes in deferred income taxes of $78.7 million. The change in our operating assets and liabilities of $9.8 million was primarily attributed to decreases in trade accounts receivable, net of $34.8 million, decreases in deposits of $38.4 million, and decreases in other non-current assets of $24.5 million, partially offset by increases in prepaid expenses and other current assets of $40.4 million, decreases in acquisition-related obligations of $22.8 million, and decreases in other non-current liabilities of $16.5 million.

Net cash provided by operating activities for the period from July 26, 2016 to December 31, 2016 was $21.5 million and was primarily attributed to net loss of $10.9 million adjusted for depreciation, depletion and amortization of $44.0 million, amortization of acquired intangibles, net of $61.3 million, and mark-to-market adjustment for warrants derivative liability of $34.0 million, partially offset by a gain on mark-to-market adjustment for acquisition-related obligations of $10.6 million. The change in our operating assets and liabilities of ($111.5) million was primarily attributed to increases in trade accounts receivable of $114.2 million, increases in inventories, net of $32.0 million and increases in deposits of $55.4 million, partially offset by increases in trade accounts payable of $59.2 million and increases in accrued expenses and other current liabilities of $51.1 million.

Net cash provided by operating activities for the period from January 1, 2016 to July 25, 2016 was $77.0 million and was primarily attributed to net loss of $67.2 million adjusted for depreciation, depletion and amortization of $85.4 million, amortization of acquired intangibles, net of $11.6 million, and deferred income taxes of $34.9 million. The change in our operating assets and liabilities of $46.6 million was primarily attributed to decreases in trade accounts receivable of $42.8 million and decreases in inventories, net of $16.7 million, partially offset by decreases in other non-current liabilities of $15.6 million.

Investing Activities

Net cash provided by investing activities for the year ended December 31, 2018 was $102.2 million , primarily driven by cash, cash equivalents and restricted cash acquired in acquisition, net of amounts paid of $198.5 million, partially offset by capital expenditures of $81.9 million , payments on disposition of assets of $10.3 million , and capital contributions to equity affiliates of $5.3 million .

Net cash used in investing activities for the year ended December 31, 2017 was $121.3 million , primarily driven by the purchase of additional ownership interest in equity affiliate of $13.3 million , cash paid on the sale of Powder River Basin of $21.4 million, capital expenditures of $83.1 million , and capital contributions to equity affiliates of $5.7 million , partially offset by proceeds on disposal of assets of $2.6 million .

Net cash provided by investing activities for the period from July 26, 2016 to December 31, 2016 was $108.4 million, primarily driven by cash, cash equivalents and restricted cash acquired in the Acquisition of $143.8 million partially offset by capital expenditures of $34.5 million and capital contributions to equity affiliates of $2.7 million.

Net cash used in investing activities for the period from January 1, 2016 to July 25, 2016 was $25.0 million, driven by capital expenditures of $23.4 million and capital contributions to equity affiliates of $2.1 million, partially offset by proceeds on disposal of assets of $0.5 million.

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Financing Activities

Net cash provided by financing activities for the year ended December 31, 2018 was $22.7 million , primarily attributable to net proceeds from borrowings on debt of $537.8 million, partially offset by principal repayments of debt of $471.7 million , common stock repurchases and related expenses of $20.3 million , debt issuance costs of $14.9 million , form S-4 costs of $3.9 million, and principal repayments of notes payable of $3.8 million .

Net cash used in financing activities for the year ended December 31, 2017 was $170.3 million , primarily attributable to principal repayments of debt of $369.5 million , special dividend paid of $100.7 million , debt extinguishment costs of $25.0 million , debt issuance costs of $14.4 million , and common stock repurchases and related expenses of $49.9 million , partially offset by borrowings on debt of $396.0 million .

Net cash provided by financing activities for the period from July 26, 2016 to December 31, 2016 was $41.5 million, primarily attributable to $42.5 million of proceeds from borrowings on debt.

Net cash used in financing activities for the period from January 1, 2016 to July 25, 2016 was $35.8 million, primarily attributable to transfers to Alpha.

The major components of cash flows related to our discontinued operations are as follows:
Successor
Predecessor
(in thousands )
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Depreciation, depletion and amortization
$
—

$
30,090

$
38,005

$
19,303

Capital expenditures
$
—

$
(10,420
)
$
(11,123
)
$
(8,071
)
Other significant operating non-cash items related to discontinued operations:
Accretion on asset retirement obligations
$
—

$
11,341

$
6,019

$
7,400

Asset impairment and restructuring
$
—

$
—

$
—

$
659



Long-Term Debt

Refer to Note 15 for disclosures on long-term debt and Note 3 for financing related to the Merger.

Analysis of Material Debt Covenants

We were in compliance with all covenants under the Amended and Restated Credit Agreement and the Amended and Restated Asset-Based Revolving Credit Agreement, as of April 1, 2019 . A breach of the covenants in the Amended and Restated Credit Agreement and the Amended and Restated Asset-Based Revolving Credit Agreement could result in a default under the terms of the agreement and the respective lenders could elect to declare all amounts borrowed due and payable.

Pursuant to the Amended and Restated Asset-Based Revolving Credit Agreement, during any Liquidity Period (capitalized terms as defined in the Amended and Restated Asset-Based Revolving Credit Agreement), our Fixed Charge Coverage Ratio cannot be less than 1.00 to 1.00 as of the last day of any Test Period, commencing with the Test Period ended immediately preceding the commencement of such Liquidity Period. The Fixed Charge Coverage Ratio is calculated as (a) Consolidated EBITDA of the Company and its Restricted Subsidiaries for such period, minus non-financed Capital Expenditures (including Capital Expenditures financed with the proceeds of any Loans) paid or payable currently in cash by the Company or any of its Subsidiaries for such period to (b) the Fixed Charges of the Company and its Restricted Subsidiaries during such period. As of April 1, 2019 , we were not in a Liquidity Period.

In the event that there shall be Excess Cash Flow for any fiscal quarter commencing with the fiscal quarter ended March 31, 2019, pursuant to the Amended and Restated Credit Agreement, we will, no later than 70 days after the end of such fiscal quarter (or 130 days in the case of the last fiscal quarter of any fiscal year), prepay the loan amounts under the Amended and Restated Credit Agreement, based on the Total Leverage Ratio as follows:

83

Total Leverage Ratio (1)
Prepayment Amount (2)
Equal to or greater than 2.25
75% of Excess Cash Flow
Less than 2.25 and greater than or equal to 1.00
50% of Excess Cash Flow
Less than 1.00
25% of Excess Cash Flow
(1) Total Leverage Ratio is calculated as the ratio of (i) Consolidated Net Total Debt on such date to (ii) Consolidated EBITDA (capitalized terms as defined in the Amended and Restated Credit Agreement) for the period of the four consecutive fiscal quarters ending as of the date of the financial statements most recently delivered.
(2) % of Excess Cash Flow is reduced by voluntary repayments of the Amended and Restated Credit Agreement, as defined within the Amended and Restated Credit Agreement.

Excess Cash Flow is calculated in accordance with our Amended and Restated Credit Agreement, and is equal to (i) the sum, without duplication, of Consolidated Net Income, the aggregate amount of all non-cash charges, the amount of the decrease, if any, in Consolidated Working Capital and the amount of non-cash losses on the disposition of property to the extent deducted in arriving at Consolidated Net Income minus (ii) the sum, without duplication, of the amount of all non-cash credits included in arriving at Consolidated Net Income, certain capital expenditures, certain amounts of regularly scheduled principal payments of Indebtedness made in cash, the amount of the increase, if any, in Consolidated Working Capital and the aggregate amount of non-cash gains on the disposition of property to the extent included in arriving at Consolidated Net Income.

Consolidated Net Income is calculated in accordance with our Amended and Restated Credit Agreement and is equal to the net income determined in accordance with GAAP, excluding, without duplication, noncash compensation expenses related to common stock and other equity securities issued to employees, extraordinary and non-recurring gains and loss, income or losses from discontinued operations or disposal of discontinued operations or costs and expense associated with the closure of any minds (including any reclamation or disposal obligations), any non-cash impairment charges or asset write-offs resulting from the application of certain ASC standards, net unrealized gains or losses resulting from non-cash foreign currency remeasurement gains or losses, net unrealized gains or losses results in such period from certain derivatives, non-cash charges including non-cash charges due to cumulative effects of changes in accounting principles, any net income or loss of any person that is not a restricted subsidiary or that is accounted for by equity method accounting except to the extent the dividends or similar distributions are paid in cash to the specified person or restricted subsidiary, the net income (but not loss) of any restricted subsidiary to the extent that the declaration or payment of dividends or similar distributions by that restricted subsidiary of that net income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that restricted subsidiary or its stockholders (other than any restriction that has been waived or released), plus, without duplication, any cash dividends and/or distributions actually received by the Company or restricted subsidiary from any unrestricted subsidiary and/or joint venture to the extent not already included therein.

Additionally, under the Amended and Restated Credit Agreement, our ability to engage in activities such as incurring additional indebtedness, making investments and paying dividends is also tied to certain financial ratios, including Consolidated EBITDA as defined per the Amended and Restated Credit Agreement. Consolidated EBITDA is defined as EBITDA further adjusted to exclude certain non-cash items, non-recurring items, and other adjustments permitted in calculating covenant compliance under the Amended and Restated Credit Agreement. EBITDA, a measure used by management to evaluate our ongoing operations for internal planning and forecasting purposes, is defined as net income (loss) from operations plus interest expense, income tax expense, amortization of acquired intangibles, net and depreciation, depletion and amortization, less interest income and income tax benefit. EBITDA is not a financial measure recognized under United States generally accepted accounting principles and does not purport to be an alternative to net income as a measure of operating performance or to cash flows from operating activities as a measure of liquidity. The amounts shown for EBITDA as presented may differ from amounts calculated and may not be comparable to other similarly titled measures used by other companies.

Consolidated EBITDA is calculated in accordance with our Amended and Restated Credit Agreement, and is equal to Consolidated Net Income plus, without duplication (i) consolidated interest expense; (ii) to the extent deducted in computing such Consolidated Net Income, the sum of all income, franchise or similar taxes; (iii) depreciation, depletion, amortization (including, without limitation, amortization of intangibles, deferred financing fees and any amortization included in pension or other employee benefit expenses) and all other non-cash items reducing Consolidated Net Income (including, without limitation, write-downs and impairment of property, plant, equipment and intangibles and other long-lived assets and the impact of acquisition accounting, but excluding, in each case, non-cash charges in a period which reflect cash expenses paid or to be paid in another period); (iv) non-recurring restructuring costs, expenses and charges, including, without limitation, all business optimization costs and expenses, facility opening, pre-opening and closing and consolidation costs and expenses, advisory and professional fees and stay and retention bonuses; provided that the amount of non-recurring restructuring costs, expenses and

84

charges permitted to be added back pursuant to this clause (iv) for a four-quarter period shall not exceed 20% of Consolidated EBITDA for such period (calculated before giving effect to such add-back); (v) any expenses, costs or charges related to any equity offering, Investment permitted, acquisition, disposition, recapitalization or Indebtedness permitted to be incurred by the indenture (whether or not successful); (vi) all non-recurring or unusual losses, charges and expenses (and less all non-recurring or unusual gains); (vii) all non-cash charges and expenses; (viii) any debt extinguishment costs; (ix) any amount of asset retirement obligations expenses; (x) all Transaction Costs incurred in connection with the Transactions contemplated hereby; (xi) transaction costs, fees and expenses incurred during such period in connection with any acquisition or disposition not prohibited hereunder or any issuance of debt or equity securities by the surviving Parent, the Borrowers or any of its Restricted Subsidiaries, in each case, for such expenses; and (xii) commissions, premiums, discounts, fees or other charges relating to performance bonds, bid bonds, appeal bonds, surety bonds, wage bonds, bonds issued in favor of any Governmental Authority, reclamation and completion guarantees and other similar obligations; provided that, with respect to any Restricted Subsidiary, such items will be added only to the extent and in the same proportion that the relevant Restricted Subsidiary’s net income was included in calculating Consolidated Net Income.

The calculation of Consolidated EBITDA is based on our results of operations in accordance with the Amended and Restated Credit Agreement and therefore, is different from Adjusted EBITDA presented elsewhere in this report. The calculation of Consolidated EBITDA for purposes of the Excess Cash Flow calculation is performed at the end of each fiscal quarter (commencing with the fiscal quarter ending March 31, 2019).

Acquisition-Related Obligations

See Note 16 for additional details and disclosures on acquisition-related obligations.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, operating leases, indemnifications and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. Obligations related to these arrangements are not reflected in our Consolidated Balance Sheet. However, the underlying liabilities that they secure, such as asset retirement obligations, workers’ compensation liabilities, and royalty obligations, are reflected in our Consolidated Balance Sheet.

We are required to provide financial assurance in order to perform the post-mining reclamation required by our mining permits, pay our federal production royalties, pay workers’ compensation claims under workers’ compensation laws in various states, pay federal black lung benefits, and perform certain other obligations. In order to provide the required financial assurance, we generally use surety bonds for post-mining reclamation and workers’ compensation obligations. We can also use bank letters of credit to collateralize certain obligations.

As of December 31, 2018 , we had outstanding surety bonds with a total face amount of $581.4 million to secure various obligations and commitments, including $237.2 million related to the PRB. To secure our reclamation-related obligations, we currently have $137.3 million of collateral supporting these obligations. Once the permits associated with the PRB Transaction have been transferred, the Company estimates approximately $12.6 million comprised of short-term restricted cash and short-term deposits will be returned to operating cash.

To secure our obligations under certain worker’s compensation, black lung, reclamation-related obligations, general liabilities, and financial guarantees, we are required to provide cash collateral. At December 31, 2018 , we had cash collateral in the amounts of $243.6 million, $24.0 million, and $29.1 million classified as short-term and long-term restricted cash, short-term and long-term deposits, and long-term restricted investments, respectively, on our balance sheet.

As of December 31, 2018 , we had real property collateralizing $26.7 million of reclamation bonds.

We meet frequently with our surety providers and have discussions with certain providers regarding the extent of and the terms of their participation in the program. These discussions may cause us to shift surety bonds between providers or to alter the terms of their participation in our program. To the extent that surety bonds become unavailable or our surety bond providers require additional collateral, we would seek to secure our obligations with letters of credit, cash deposits or other suitable forms of collateral. Our failure to maintain, or inability to acquire, surety bonds or to provide a suitable alternative would have a material adverse effect on our liquidity. These failures could result from a variety of factors including lack of availability, higher cost or unfavorable market terms of new surety bonds, and the exercise by third-party surety bond issuers of their right to refuse to renew the surety.

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Other

As a regular part of our business, we review opportunities for, and engage in discussions and negotiations concerning, the acquisition or disposition of coal mining and related infrastructure assets and interests in coal mining companies, and acquisitions or dispositions of, or combinations or other strategic transactions involving companies with coal mining or other energy assets. When we believe that these opportunities are consistent with our strategic plans and our acquisition or disposition criteria, we will make bids or proposals and/or enter into letters of intent and other similar agreements. These bids or proposals, which may be binding or non-binding, are customarily subject to a variety of conditions and usually permit us to terminate the discussions and any related agreement if, among other things, we are not satisfied with the results of due diligence. Any acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. There can be no assurance that additional financing will be available on terms acceptable to us, or at all.

Contractual Obligations
The following is a summary of our significant contractual obligations as of December 31, 2018 :
(in thousands )
2019
2020
2021
2022
2023
After 2023
Total
Long-term debt (1)
$
46,875

$
47,500

$
47,500

$
40,000

$
30,000

$
412,500

$
624,375

Other debt (2)
2,737

2,255

2,143

1,260

—

—

8,395

Acquisition-related obligations
17,875

20,811

7,873

4,247

—

—

50,806

Contingent revenue obligation (3)
9,628

15,330

14,269

14,698

13,210

—

67,135

Equipment purchase commitments (4)
24,339

—

—

—

—

—

24,339

Transportation commitments
3,072

3,102

—

—

—

—

6,174

Operating leases
3,537

3,232

1,945

360

158

458

9,690

Minimum royalties
13,579

12,992

12,687

10,697

9,618

28,056

87,629

Coal purchase commitments (5)
260,205

—

—

—

—

—

260,205

Total
$
381,847

$
105,222

$
86,417

$
71,262

$
52,986

$
441,014

$
1,138,748

(1) Includes Term Loan Credit Facility principal amounts of $27.5 million in 2019, $27.5 million in 2020, $27.5 million in 2021, $27.5 million in 2022, $27.5 million in 2023, and $412.5 million after 2023. Cash interest payable on this obligation, with an interest rate of 7.39%, would be approximately $40.4 million in 2019, $38.5 million in 2020, $36.3 million in 2021, $34.2 million in 2022, $32.2 million in 2023, and $54.4 million after 2023. Also includes Lexington Coal Company (“LCC”) Note Payable principal amounts of $17.5 million in 2019, $17.5 million in 2020, $17.5 million in 2021, and $10.0 million in 2022 and LCC Water Treatment Stipulation principal amounts of $1.9 million in 2019, $2.5 million in 2020, $2.5 million in 2021, $2.5 million in 2022, and $2.5 million in 2023.
(2) Includes capital lease obligation principal amounts of $2.1 million in 2019, $1.5 million in 2020, $1.6 million in 2021, and $1.2 million in 2022. Cash interest payable on these obligations with interest rates ranging between 0.39% and 9.50%, would be approximately $0.2 million in 2019, $0.1 million in 2020, $0.1 million in 2021, and $16 thousand in 2022. Other debt includes principal amounts of $0.6 million in 2019, $0.7 million in 2020, $0.6 million in 2021, and $32 thousand in 2022.
(3) See Note 16 for further disclosures related to this obligation.
(4) Represents obligations under certain equipment purchase agreements that contain minimum quantities to be purchased in 2019.
(5) Includes an estimated $70.9 million in 2019 related to contractually committed variable priced tons from vendors with historical performance resulting in less than 20% of the committed tonnage being delivered.


86

Additionally, we have long-term liabilities relating to asset retirement obligations, pension, black lung benefits, life insurance benefits, and workers’ compensation benefits. The table below reflects the estimated undiscounted cash flows for these obligations:
(in thousands)
2019
2020
2021
2022
2023
After 2023
Total
Asset retirement obligation
$
25,373

$
23,373

$
24,605

$
29,857

$
26,911

$
489,081

$
619,200

Pension benefit obligation (1)
30,019

30,488

31,139

32,146

32,942

1,378,633

1,535,367

Black lung benefit obligation
8,133

6,018

6,105

6,496

6,630

178,496

211,878

Life insurance benefit obligation
787

696

683

674

666

16,809

20,315

Workers’ compensation benefit obligation
13,877

10,269

8,020

6,821

6,084

91,400

136,471

Total
$
78,189

$
70,844

$
70,552

$
75,994

$
73,233

$
2,154,419

$
2,523,231

(1) The estimated undiscounted cash flows will be paid from the defined benefit pension plan assets held within the defined benefit pension plan trust. See Note 22 for further disclosures related to this obligation.

We expect to spend between $170 million and $190 million on capital expenditures during 2019.

Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and on various other factors and assumptions, including the current economic environment that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate our estimates and assumptions on an ongoing basis and adjust such estimates and assumptions as facts and circumstances require. Foreign currency and energy markets, and fluctuations in demand for steel products have combined to increase the uncertainty inherent in such estimates and assumptions. As future events and their effects cannot be determined with precision, actual results may differ significantly from these estimates. Changes in these estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Business Combinations. We account for our business combinations under the acquisition method of accounting. The total cost of acquisitions is allocated to the underlying identifiable net tangible and intangible assets based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, the utilization of independent valuation experts and often involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items.
Reclamation. Our 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. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, sealing portals at deep mines and the treatment of water. We determine the future cash flows necessary to satisfy our reclamation obligations on a permit-by-permit basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. We are also faced with increasingly stringent environmental regulation, much of which is beyond our control, which could increase our costs and materially increase our asset retirement obligations. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based upon third-party costs. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. Our asset retirement obligations are initially recorded at fair value. In order to determine fair value, we use assumptions including a discount rate and third-party margin. Each is discussed further below:
•
Discount Rate. Asset retirement obligations are initially recorded at fair value. We utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives and adjust for our credit standing as necessary after considering funding and assurance provisions. Changes in our credit standing could have a material impact on our asset retirement obligations.

87

•
Third-Party Margin. The measurement of an obligation at fair value is based upon the amount a third-party would demand to perform the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin was added to the estimated costs of these activities. This margin was estimated based upon our historical experience with contractors performing similar types of reclamation activities. The inclusion of this margin will result in a recorded obligation that is greater than our estimates of our cost to perform the reclamation activities. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded within depreciation, depletion and amortization within our Consolidated Statements of Operations at the time that reclamation work is completed.
On at least an annual basis, we review our reclamation liabilities and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revisions to cost estimates and productivity assumptions, to reflect current experience and updated plans. At December 31, 2018 , we had recorded asset retirement obligation liabilities of $228.4 million, including amounts reported as current, and $1.4 million asset retirement obligations liabilities classified as held for sale. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2018 , we estimate that the aggregate undiscounted cost of final mine closures is approximately $619.2 million .
Retirement Plans. We have three non-contributory defined benefit retirement plans (the “Pension Plans”) covering certain of our salaried and non-union hourly employees, all of which are frozen. Benefits are based on either the employee’s compensation prior to retirement or stated amounts for each year of service with us. Funding of the Pension Plans is in accordance with requirements of ERISA, and our contributions can be deducted for federal income tax purposes. We contributed $0 to our Pension Plans for the year ended December 31, 2018. For the year ended December 31, 2018, we recorded a net periodic benefit credit of $0.3 million for our Pension Plans and have recorded net obligations of $180.8 million.
The calculation of the net periodic benefit expense/credit and projected benefit obligation associated with our Pension Plans requires the use of a number of assumptions, which are used by our independent actuaries to make the underlying calculations. Changes in these assumptions can result in different net periodic benefit expense and liability amounts, and actual experience can differ from the assumptions.
•
The expected long-term rate of return on plan assets is an assumption of the rate of return on plan assets reflecting the average rate of earnings expected on the funds invested or to be invested to provide for the benefits included in the projected benefit obligation. We establish 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 Pension Plans investment targets are 40 % equity securities and 60 % debt securities. Investments are rebalanced on a periodic basis to stay within these targeted guidelines. The long-term rate of return assumption used to determine net periodic benefit expense was 5.8 % for the year ended December 31, 2018. The long-term rate of return assumption to be used in 2019 is expected to be 5.8%. Any diff erence between the actual experience and the assumed experience is deferred as an unrecognized actuarial gain or loss and amortized into expense in future periods.
•
The discount rate represents our estimate of the interest rate at which pension benefits could be effectively settled. Assumed discount rates are used in the measurement of the projected and accumulated benefit obligations and the service and interest cost components of the net periodic benefit expense. In estimating that rate, we use rates of return on high quality, fixed income investments. The weighted average discount rate used to determine pension expense was 4.23 % for the year ended December 31, 2018. The differences resulting from actual versus assumed discount rates are amortized into pension expense/credit over the remaining average life of the active plan participants. A one percentage-point increase in the discount rate would increase the net periodic pension cost for the year ended December 31, 2018 by ap proximately $1.9 million and decrease the projected benefit obligation as of December 31, 2018 by approximately $88.0 million. The corresponding effects of a one percentage-point decrease in discount rate would decrease the net periodic pension cost for the year ended December 31, 2018 by approximately $2.9 million and increase the projected benefit obligation as of December 31, 2018 by approximately $111.6 million.
Coal Workers’ Pneumoconiosis. We are required by federal and state statues to provide benefits to employees for awards related to coal workers’ pneumoconiosis disease (black lung). Certain of our subsidiaries are insured for black lung obligations by a third-party insurance provider. Certain subsidiaries in West Virginia are self-insured for state black lung obligations. Certain other subsidiaries are self-insured for black lung benefits and may fund benefit payments through Section 501(c)(21) tax-exempt trust fund. Provisions are made for estimated benefits based on annual evaluations prepared by independent actuaries. Charges are made to operations for self-insured black lung claims, as determined by an independent actuary at the present value of the actuarially computed liability for such benefits over the employee’s applicable term of service. These actuarially determined liabilities use various actuarial assumptions, including the discount rate, future cost trends, demographic

88

assumptions and return on plan assets to estimate the costs and obligations for these items. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could affect our obligation to satisfy these or additional obligations. As of December 31, 2018, we had estimated black lung obligations of approximately $92.2 million, including amounts reported as current and $94 thousand related to discontinued operations, which are net of assets of $2.6 million that are held in a tax-exempt trust fund.
Income Taxes. We recognize deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In evaluating our ability to recover our deferred tax assets within the jurisdiction in which they arise, we consider all available positive and negative evidence, including the expected reversals of deferred tax liabilities, projected future taxable income, taxable income available via carryback to prior years, tax planning strategies, and results of recent operations. We assess the realizability of our deferred tax assets, including scheduling the reversal of our deferred tax assets and liabilities, to determine the amount of valuation allowance needed. Scheduling the reversal of deferred tax asset and liability balances requires judgment and estimation. We believe the deferred tax liabilities relied upon as future taxable income in our assessment will reverse in the same period and jurisdiction and are of the same character as the temporary differences giving rise to the deferred tax assets that will be realized. At December 31, 2018, a valuation allowance of $94.8 million has been provided on federal and state net operating losses and gross deferred tax assets not expected to provide future tax benefits.
Asset Impairment. U.S. GAAP requires that a long-lived asset group that is held and used should be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the long-lived asset group might not be recoverable. Testing long-lived assets for impairment after indicators of impairment have been identified is a two-step process. Step one compares the net undiscounted cash flows of an asset group to its carrying value. If the carrying value of an asset group exceeds the net undiscounted cash flows of that asset group, step two is performed whereby the fair value of the asset group is estimated and compared to its carrying amount. The amount of impairment, if any, is equal to the excess of the carrying value of an asset group over its estimated fair value. The amount of impairment, if any, is allocated to the long-lived assets on a pro-rata basis, except that the carrying value of the individual long-lived assets are not reduced below their estimated fair value. Long-lived assets located in a close geographic area are grouped together for purposes of impairment testing when, after considering revenue and cost interdependencies, circumstances indicate the assets are used together to produce future cash flows. Our asset groups generally consist of the assets and applicable liabilities of one or more mines and preparation plants and associated coal reserves for which cash flows are largely independent of cash flows of other mines, preparation plants and associated reserves.
Goodwill. Goodwill represents the excess of purchase price over the fair value of the identifiable net assets of acquired companies. Goodwill is not amortized; instead, it is tested for impairment annually as of October 31 of each year, or more frequently if indicators of impairment exist.
In order to test for goodwill impairment, the Company compares the fair value of the reporting unit to its carrying value, including goodwill. If the fair value of the reporting unit is lower than its carrying amount, goodwill is written down for the amount by which the carrying amount exceeds the reporting unit's fair value. However, the loss recognized for any given reporting unit cannot exceed the carrying amount of goodwill allocated to that reporting unit. The Company has the option to perform a qualitative assessment of goodwill rather than completing the impairment test. The Company must assess whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount. If the Company concludes that this is the case, it must perform the testing discussed above. Otherwise, the Company does not need to perform any further assessment.

The valuation methodology utilized to estimate the fair value of the reporting units is based on both a market and income approach and is within the range of fair values yielded under each approach. The income approach is based on a discounted cash flow methodology in which expected future net cash flows are discounted to present value, using an appropriate after-tax weighted average cost of capital (discount rate). The market approach is based on a guideline company and similar transaction methodology. Under the guideline company approach, certain metrics from a selected group of publicly traded guideline companies that have similar operations to the Company’s reporting units are used to estimate the fair value of the reporting units. Under the similar transactions approach, recent merger and acquisition transactions for companies that have similar operations to the Company’s reporting units are used to estimate the fair value of the Company’s reporting units.

The income approach is dependent upon a number of significant management estimates about future performance including sales volumes and prices, costs to produce, income taxes, capital spending, working capital changes and the after-tax weighted average cost of capital. Changes in any of these assumptions could materially impact the estimated fair value of our reporting units. Our forecasts of coal prices generally reflect a long-term outlook of market prices expected to be received for

89

our coal. However, coal prices are influenced by global market conditions beyond our control. If actual coal prices are less than our expectations, it could have a material impact on the fair value of our reporting units. Our forecasts of costs to produce coal are based on our operating forecasts and an assumed inflation rate for materials and supplies such as steel, diesel fuel and explosives. However, the costs of the materials and supplies used in our production process such as steel, diesel fuel and explosives are influenced by global market conditions beyond our control. If actual costs are higher or if inflation increases above our expectations, it could have a material impact on the fair value of our reporting units. We also are faced with increasingly stringent safety standards and governmental regulation, much of which is beyond our control, which could increase our costs and materially decrease the fair value of our reporting units. For a further discussion of the factors that could result in a change in our assumptions, see “Risk Factors” in this Annual Report on form 10-K and our other filings with the Securities and Exchange Commission.

Contingent Revenue Obligation. Our contingent revenue obligation was assumed in connection with the Merger. Determining the fair value of this obligation requires management’s judgment and the utilization of independent valuation experts, and involves the use of significant estimates and assumptions with respect to forecasts of future revenues, revenue volatility, and discount rates. If our assumptions do not materialize as expected, actual payments made under the obligation could differ materially from our current estimates. For a further discussion of the factors that could result in a change in our assumptions, see “Risk Factors” in this Annual Report on form 10-K and our other filings with the Securities and Exchange Commission.

New Accounting Pronouncements. See Note 2 for disclosures related to new accounting policies adopted.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

We manage our commodity price risk for coal sales through the use of coal supply agreements. As of March 15, 2019, we expect to ship on sales commitments of approximately 6.5 million tons of NAPP coal for 2019, 96% of which is priced, 9.3 million tons of CAPP - Met coal for 2019, 60% of which is priced, and 4.9 million tons of CAPP - Thermal coal for 2019, 90% of which is priced.
We have exposure to price risk for supplies that are used directly or indirectly in the normal course of production such as diesel fuel, steel and other items such as explosives. We manage our risk for these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivative instruments in the future from time to time, primarily swap contracts with financial institutions, for a certain percentage of our monthly requirements. Swap agreements would essentially fix the price paid for our diesel fuel by requiring us to pay a fixed price and receive a floating price.

We expect to use approximately 6.7 million and 6.9 million gallons of diesel fuel in 2019 and 2020, respectively.

Credit Risk

Our credit risk is primarily with electric power generators and steel producers. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to monitor outstanding accounts receivable against established credit limits. When appropriate (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps include obtaining letters of credit or cash collateral, obtaining credit insurance, requiring prepayments for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay.

Interest Rate Risk

As of December 31, 2018 , we had exposure to changes in interest rates through the asset-based revolving credit facility under our Amended and Restated Asset-Based Revolving Credit Agreement, which bears interest based on the character of the loan (defined as either “Base Rate Loan” or “Eurocurrency Rate Loan”) plus an applicable rate ranging from 1.00% to 1.50% for Base Rate Loans and 2.00% to 2.50% for Eurocurrency Rate Loans, depending on the amount of credit available. As of December 31, 2018 , the Company had no borrowings under the Asset-Based Term Loan Credit Agreement.

As of December 31, 2018 , we also had exposure to changes in interest rates through the term loan under our Amended and Restated Credit Agreement, which bears an interest rate per annum based on the character of the loan (defined as either “Base Rate Loan” or “Eurocurrency Rate Loan”) plus an applicable rate of 4.00% to 5.00% depending on loan type (the “Applicable

90

Rate”), payable bi-monthly in arrears. As of December 31, 2018 , a 50 basis point increase or decrease in interest rates would increase or decrease our annual interest expense by approximately $2.6 million.


91

Item 8. Financial Statements and Supplementary Data


Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Contura Energy, Inc.:

Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Contura Energy, Inc. and subsidiaries (the Company) as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for the years ended December 31, 2018 and 2017 (Successor) and for the period July 26, 2016 to December 31, 2016 (Successor), and the related combined statement of operations, comprehensive loss, business equity, and cash flows for the period January 1, 2016 to July 25, 2016 (Predecessor), and the related notes (collectively, the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for the years ended December 31, 2018 and 2017 (Successor), the period July 26, 2016 to December 31, 2016 (Successor), and the period January 1, 2016 to July 25, 2016 (Predecessor), in conformity with U.S. generally accepted accounting principles.
Basis of Presentation
As discussed in Note 1 to the financial statements, effective July 26, 2016, the Company acquired certain core coal operations of Alpha Natural Resources, Inc. in a transaction accounted for as a business combination. As a result of the acquisition, the consolidated financial information for the Successor periods is presented on a different cost basis than that for the Predecessor period and, therefore, is not comparable.
Change in Accounting Principle
As discussed in Note 2 to the financial statements, the Company changed its method of accounting for revenue recognition in 2018 due to the adoption of ASU 2014-09, Revenue from Contracts with Customers and the related amendments.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP

We have served as the Company’s auditor since 2016.
Greensboro, North Carolina
April 1, 2019

92

CONTURA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND
PREDECESSOR COMBINED STATEMENT OF OPERATIONS
(Amounts in thousands, except share and per share data)

Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Revenues:






Coal revenues
$
2,020,889


$
1,392,481

$
431,692

$
344,692

Freight and handling revenues
—


247,402

70,544

52,076

Other revenues
10,316


10,086

4,060

14,343

Total revenues
2,031,205


1,649,969

506,296

411,111

Costs and expenses:





Cost of coal sales (exclusive of items shown separately below)
1,297,990


1,079,895

319,790

305,276

Freight and handling costs
363,128


247,402

70,544

52,076

Depreciation, depletion and amortization
77,549


34,910

5,973

66,076

Accretion on asset retirement obligations
9,966

9,934

4,800

5,005

Amortization of acquired intangibles, net
(5,392
)

59,007

61,281

11,567

Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization shown separately above)
59,271


67,459

19,135

29,568

Asset impairment and restructuring
—

—

—

3,096

Merger related costs
51,800

—

—

—

Secondary offering costs
—


4,491

—

—

Total other operating (income) loss:





Mark-to-market adjustment for acquisition-related obligations
24


3,221

(10,616
)
—

Gain on settlement of acquisition-related obligations
(580
)

(38,886
)
—

—

Other (income) expense
(16,311
)

178

—

2,184

Total costs and expenses
1,837,445


1,467,611

470,907

474,848

Income (loss) from operations
193,760


182,358

35,389

(63,737
)
Other income (expense):





Interest expense
(38,810
)

(35,977
)
(20,496
)
(2
)
Interest income
1,949


210

23

19

Loss on modification and extinguishment of debt
(12,042
)

(38,701
)
—

—

Equity loss in affiliates
(6,112
)
(3,339
)
(2,287
)
(2,735
)
Mark-to-market adjustment for warrant derivative liability
—

—

(33,975
)
—

Bargain purchase gain
—

1,011

7,719

—

Miscellaneous income, net
(1,254
)

194

(139
)
(13,978
)
Total other expense, net
(56,269
)

(76,602
)
(49,155
)
(16,696
)
Income (loss) from continuing operations before reorganization items and income taxes
137,491


105,756

(13,766
)
(80,433
)
Reorganization items, net
—

—

—

(20,989
)
Income (loss) from continuing operations before income taxes
137,491

105,756

(13,766
)
(101,422
)
Income tax benefit
165,363


67,979

1,920

39,881


93

Net income (loss) from continuing operations
302,854


173,735

(11,846
)
(61,541
)
Discontinued operations:





(Loss) income from discontinued operations before income taxes
(4,994
)

(36,894
)
1,467

(679
)
Income tax benefit (expense) from discontinued operations
1,305


17,681

(551
)
(4,992
)
(Loss) income from discontinued operations
(3,689
)

(19,213
)
916

(5,671
)
Net income (loss)
$
299,165


$
154,522

$
(10,930
)
$
(67,212
)






Basic income (loss) per common share:





Income (loss) from continuing operations
$
27.61


$
17.01

$
(1.15
)
(Loss) income from discontinued operations
(0.33
)

(1.89
)
0.09

Net income (loss)
$
27.28


$
15.12

$
(1.06
)






Diluted income (loss) per common share:





Income (loss) from continuing operations
$
25.86


$
16.13

$
(1.15
)
(Loss) income from discontinued operations
(0.32
)

(1.78
)
0.09

Net income (loss)
$
25.54


$
14.35

$
(1.06
)






Weighted average shares - basic
10,967,014

10,216,464

10,309,310

Weighted average shares - diluted
11,712,653

10,770,005

10,309,310


See accompanying Notes to Consolidated Financial Statements.


94

CONTURA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) AND
PREDECESSOR COMBINED STATEMENT OF COMPREHENSIVE LOSS
(Amounts in thousands)
Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Net income (loss)
$
299,165

$
154,522

$
(10,930
)
$
(67,212
)
Other comprehensive (loss) income, net of tax:
Employee benefit plans:
Current period actuarial (loss) gain
$
(22,895
)
$
(3,832
)
$
3,268

$
(3,415
)
Income tax
1,572

—

(1,181
)
1,227

$
(21,323
)
$
(3,832
)
$
2,087

$
(2,188
)
Less: reclassification adjustments for amounts reclassified to earnings due to amortization of net actuarial loss (gain) and settlements
155

(203
)
—

206

Income tax
(14
)
—

—

(74
)
$
141

$
(203
)
$
—

$
132

Less: reclassification adjustment for amounts reclassified to earnings due to amortization of prior service credit and curtailment loss
—

—

—

3,536

Income tax
—

—

—

(1,271
)
$
—

$
—

$
—

$
2,265

Total other comprehensive (loss) income, net of tax
$
(21,182
)
$
(4,035
)
$
2,087

$
209

Total comprehensive income (loss)
$
277,983

$
150,487

$
(8,843
)
$
(67,003
)

See accompanying Notes to Consolidated Financial Statements.


95

CONTURA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share and per share data)
December 31, 2018
December 31, 2017
Assets


Current assets:


Cash and cash equivalents
$
233,599

$
141,924

Trade accounts receivable, net of allowance for doubtful accounts of $0 as of December 31, 2018 and December 31, 2017
292,617

127,326

Inventories, net
121,965

69,561

Prepaid expenses and other current assets
158,945

83,845

Current assets - discontinued operations
22,475

40,498

Total current assets
829,601

463,154

Property, plant, and equipment, net of accumulated depreciation and amortization of $106,766 and $39,943 as of December 31, 2018 and December 31, 2017
699,990

179,952

Owned and leased mineral rights, net of accumulated depletion and amortization of $11,390 and $6,512 as of December 31, 2018 and December 31, 2017
528,232

16,627

Goodwill
95,624

—

Other acquired intangibles, net of accumulated amortization of $20,267 and $28,662 as of December 31, 2018 and December 31, 2017
154,584

18,458

Long-term restricted cash
227,173

40,421

Deferred income taxes
27,179

78,744

Other non-current assets
183,675

31,612

Non-current assets - discontinued operations
—

7,632

Total assets
$
2,746,058

$
836,600

Liabilities and Stockholders’ Equity


Current liabilities:


Current portion of long-term debt
$
42,743

$
10,730

Trade accounts payable
114,568

76,319

Acquisition-related obligations - current
27,334

15,080

Liabilities held for sale
1,351

27,161

Accrued expenses and other current liabilities
147,348

58,771

Current liabilities - discontinued operations
21,892

54,114

Total current liabilities
355,236

242,175

Long-term debt
545,269

361,973

Acquisition-related obligations - long-term
72,996

20,332

Workers’ compensation and black lung obligations
249,294

41,658

Pension obligations
180,802

—

Asset retirement obligations
203,694

52,434

Deferred income taxes
15,118

—

Other non-current liabilities
52,415

17,618

Non-current liabilities - discontinued operations
94

7,762

Total liabilities
1,674,918

743,952

Commitments and Contingencies (Note 26)




Stockholders’ Equity
Preferred stock - par value $0.01, 5.0 million shares authorized at December 31, 2018 and 2.0 million shares authorized at December 31, 2017, none issued
—

—


96

Common stock - par value $0.01, 50.0 million shares authorized, 20.2 million issued and 19.1 million outstanding at December 31, 2018 and 20.0 million shares authorized, 10.7 million issued and 9.9 million outstanding at December 31, 2017
202

108

Additional paid-in capital
761,301

40,616

Accumulated other comprehensive loss
(23,130
)
(1,948
)
Treasury stock, at cost: 1.1 million shares at December 31, 2018 and 0.8 million shares at December 31, 2017
(70,362
)
(50,092
)
Retained earnings
403,129

103,964

Total stockholders’ equity
1,071,140

92,648

Total liabilities and stockholders’ equity
$
2,746,058

$
836,600


See accompanying Notes to Consolidated Financial Statements.


97

CONTURA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS AND
PREDECESSOR COMBINED STATEMENT OF CASH FLOWS
(Amounts in thousands)
Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Operating activities:
Net income (loss)
$
299,165

$
154,522

$
(10,930
)
$
(67,212
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization
77,549

65,000

43,978

85,379

Amortization of acquired intangibles, net
(5,392
)
59,007

61,281

11,567

Accretion of acquisition-related obligations discount
5,627

7,531

4,936

—

Amortization of debt issuance costs and accretion of debt discount
4,483

2,884

1,340

—

Mark-to-market adjustment for acquisition-related obligations
24

3,221

(10,616
)
—

Gain on settlement of acquisition-related obligations
(580
)
(38,886
)
—

—

(Gain) loss on disposal of assets
(16,852
)
(570
)
216

216

Bargain purchase gain
—

(1,011
)
(7,719
)
—

Accretion on asset retirement obligations
9,966

21,275

10,819

12,422

Employee benefit plans, net
9,231

11,739

3,154

11,917

Deferred income taxes
(66,682
)
(78,744
)
(1,180
)
(34,889
)
Loss on sale of Powder River Basin
—

36,086

—

—

Asset impairment and restructuring
—

—

—

3,755

Non-cash reorganization items, net
—

—

—

3,837

Loss on modification and extinguishment of debt
12,042

38,701

—

—

Stock-based compensation
13,354

20,372

1,424

658

Equity in loss of affiliates
6,112

3,325

2,280

2,726

Mark-to-market adjustment for warrant derivative liability
—

—

33,975

—

Other, net
1,643

—

16

38

Changes in operating assets and liabilities
Trade accounts receivable, net
(84,139
)
34,840

(114,244
)
42,793

Inventories, net
33,232

441

(32,046
)
16,693

Prepaid expenses and other current assets
(44,266
)
(40,425
)
(817
)
5,172

Deposits
(7,493
)
38,447

(55,407
)
(275
)
Other non-current assets
(36,655
)
24,498

(14,681
)
2,956

Trade accounts payable
(7,075
)
6,102

59,242

(6,665
)
Accrued expenses and other current liabilities
(7,345
)
(12,207
)
51,053

3,680

Acquisition-related obligations
(14,500
)
(22,800
)
(9,300
)
—

Asset retirement obligations
(3,175
)
(2,567
)
(514
)
(2,143
)
Other non-current liabilities
(19,893
)
(16,521
)
5,199

(15,596
)
Net cash provided by operating activities
158,381

314,260

21,459

77,029

Investing activities:
Capital expenditures
(81,881
)
(83,121
)
(34,497
)
(23,433
)
Payments on disposal of assets
(10,250
)
—

—

—

Proceeds on disposal of assets
997

2,579

1,787

526


98

Capital contributions to equity affiliates
(5,253
)
(5,691
)
(2,738
)
(2,122
)
Cash, cash equivalents and restricted cash acquired in acquisition, net of amounts paid
198,506

—

143,800

—

Purchase of additional ownership interest in equity affiliate
—

(13,293
)
—

—

Cash paid on sale of Powder River Basin
—

(21,375
)
—

—

Purchase of investment securities - held to maturity
(3,280
)
(406
)
—

—

Maturity of investment securities - held to maturity
3,360

—

—

—

Other, net
(3
)
—

—

—

Net cash provided by (used in) investing activities
102,196

(121,307
)
108,352

(25,029
)
Financing activities:
Proceeds from borrowings on debt
537,750

396,000

42,500

—

Principal repayments of debt
(471,704
)
(369,500
)
—

—

Principal repayments of capital lease obligations
(533
)
(1,009
)
(243
)
(42
)
Form S-4 costs
(3,918
)
—

—

—

Debt issuance costs
(14,931
)
(14,385
)
(243
)
—

Debt extinguishment costs
—

(25,036
)
—

—

Debt amendment costs
—

(4,520
)
—

—

Common stock repurchases and related expenses
(20,270
)
(49,932
)
—

—

Special dividend paid
—

(100,735
)
—

—

Principal repayments of notes payable
(3,844
)
(1,517
)
(536
)
—

Transfers to Alpha
—

—

—

(35,780
)
Other, net
159

352

—

—

Net cash provided by (used in) financing activities
22,709

(170,282
)
41,478

(35,822
)
Net increase in cash and cash equivalents and restricted cash
283,286

22,671

171,289

16,178

Cash and cash equivalents and restricted cash at beginning of period
193,960

171,289

—

4,459

Cash and cash equivalents and restricted cash at end of period
$
477,246

$
193,960

$
171,289

$
20,637

Supplemental cash flow information:
Cash paid for interest
$
27,340

$
40,635

$
356

$
—

Cash paid for taxes
$
37

$
13,328

$
—

$
—

Cash received for income tax refunds
$
14,157

$
—

$
—

$
—

Supplemental disclosure of non-cash investing and financing activities:


Capital leases and capital financing - equipment
$
6,513

$
1,574

$
3,473

$
—

Accrued capital expenditures
$
6,879

$
9,408

$
4,778

$
13,376

Issuance of equity in connection with acquisition
$
664,460

$
—

$
44,644

$
—

Net balance due to Alpha deemed effectively settled
$
47,048

$
—

$
—

$
—

Issuance of 10% Senior Secured First Lien Notes in connection with acquisition
$
—

$
—

$
285,936

$
—

Issuance of GUC Distribution Note in connection with acquisition
$
—

$
—

$
4,208

$
—

Issuance of warrants in connection with acquisition
$
—

$
—

$
1,167

$
—







99

The following table provides a reconciliation of cash and cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts shown in the Consolidated Statements of Cash Flows.
Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Cash and cash equivalents
$
233,599

$
141,924

$
127,948

$
108

Short-term restricted cash (included in Prepaid expenses and other current assets)
16,474

11,615

—

—

Long-term restricted cash
227,173

40,421

43,341

20,529

Total cash and cash equivalents and restricted cash
$
477,246

$
193,960

$
171,289

$
20,637


See accompanying Notes to Consolidated Financial Statements.


100

CONTURA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND
COMBINED STATEMENT OF PREDECESSOR BUSINESS EQUITY
(Amounts in thousands)
Common Stock
Additional Paid-in Capital
Accumulated
Other
Comprehensive Income (Loss)
Treasury Stock at Cost
(Accumulated Deficit) Retained Earnings
Alpha’s Investment
Total Stockholders’ Equity / Predecessor Business Equity
Predecessor
Balances, December 31, 2015
$
—

$
—

$
4,135

$
—

$
(559,922
)
$
1,769,684

$
1,213,897

Net loss
—

—

—

—

(67,212
)
—

(67,212
)
Other comprehensive income, net
—

—

209

—

—

—

209

Net distributions to Alpha
—

—

—

—

—

(26,641
)
(26,641
)
Balances, July 25, 2016
$
—

$
—

$
4,344

$
—

$
(627,134
)
$
1,743,043

$
1,120,253

Successor
Balances, July 26, 2016
$
—

$
—

$
—

$
—

$
—

$
—

$
—

Issuance of common stock in connection with acquisition
100

44,544

—

—

—

—

44,644

Net loss
—

—

—

—

(10,930
)
—

(10,930
)
Other comprehensive income, net
—

—

2,087

—

—

—

2,087

Stock-based compensation and net issuance of common stock for share vesting
3

1,420

—

—

—

—

1,423

Balances, December 31, 2016
$
103

$
45,964

$
2,087

$
—

$
(10,930
)
$
—

$
37,224

Retrospective warrants adjustment
—

1,166

—

—

33,975

—

35,141

Net income
—

—

—

—

154,522

—

154,522

Other comprehensive loss, net
—

—

(4,035
)
—

—

—

(4,035
)
Stock-based compensation and net issuance of common stock for share vesting
4

20,205

—

—

—

—

20,209

Special dividend
—

(27,132
)
—

—

(73,603
)
—

(100,735
)
Common stock repurchase and related expenses
—

—

—

(50,040
)
—

—

(50,040
)
Warrant exercises
1

413

—

(52
)
—

—

362

Balances, December 31, 2017
$
108

$
40,616

$
(1,948
)
$
(50,092
)
$
103,964

$
—

$
92,648

Net income
—

—

—

—

299,165

—

299,165

Other comprehensive loss, net
—

—

(21,182
)
—

—

—

(21,182
)
Stock-based compensation and net issuance of common stock for share vesting
—

13,031

—

—

—

—

13,031

Exercise of stock options
—

146

—

—

—

—

146

Common stock repurchases and related expenses
—

—

—

(20,266
)
—

—

(20,266
)
Warrant exercises
—

12

—

(4
)
—

—

8

Form S-4 costs
—

(3,918
)
—

—

—

—

(3,918
)
Equity consideration for the Alpha Merger
94

664,366

—

—

—

—

664,460

Net balances due to Alpha deemed effectively settled
—

47,048

—

—

—

—

47,048

Balances, December 31, 2018
$
202

$
761,301

$
(23,130
)
$
(70,362
)
$
403,129

$
—

$
1,071,140

See accompanying Notes to Consolidated Financial Statements.

101
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)


( 1 ) Business and Basis of Presentation
Business
Contura Energy, Inc. (“Contura” or the “Company”) is a Tennessee-based coal supplier with affiliate mining operations across major coal basins in Pennsylvania, Virginia and West Virginia. With customers across the globe, high-quality reserves and significant port capacity, Contura reliably supplies both metallurgical coal to produce steel and thermal coal to generate power. Contura was formed to acquire and operate certain of Alpha Natural Resources, Inc.’s (“Alpha”) core coal operations, as part of the Alpha Restructuring. Contura began operations on July 26, 2016 and currently operates mines in the Northern Appalachia and Central Appalachia regions.
A Merger with with ANR, Inc. (“ANR”) and Alpha Natural Resources Holdings, Inc. (“Holdings”, and, together with ANR, the "Alpha Companies”) was completed on November 9, 2018 (the “Merger” or the “Alpha Merger”). Refer to Note 3 for information on terms of the definitive merger agreement (the “Merger Agreement”). Upon the consummation of the transactions contemplated by the Merger Agreement, Contura began trading on the New York Stock Exchange under the ticker “CTRA.” Previously, Contura shares traded on the OTC market under the ticker “CNTE.”

Basis of Presentation

Together, the consolidated statement of operations, statement of comprehensive income (loss), balance sheet, statement of cash flows and statement of stockholders’ equity for the Company are referred to as the “Financial Statements.” The Financial Statements are also referred to as consolidated and references across periods are generally labeled “Balance Sheets,” “Statements of Operations,” and “Statements of Cash Flows.”
The Consolidated Financial Statements include all wholly-owned subsidiaries’ results of operations for the years ended December 31, 2018 and 2017 and the period from July 26, 2016 to December 31, 2016. All significant intercompany transactions have been eliminated in consolidation.

On November 9, 2018, the Company completed the Alpha Merger. For the year ended December 31, 2018, the Alpha Companies’ financial results are included in the Financial Statements for the period from November 9, 2018 through December 31, 2018. The Alpha Companies’ financial results are not included in the Financial Statements in periods prior to November 9, 2018. Refer to Note 3 for information on Alpha Merger.

The Combined Predecessor Financial Statements presented include the assets, liabilities, operating results and cash flows of Contura, prepared on a carve-out basis using Alpha’s historical bases in the assets and liabilities and the historical results of operations of Contura. The Combined Predecessor Financial Statements have been derived from the consolidated financial statements and accounting records of Alpha. All transactions between Contura and Alpha have been included in these Combined Predecessor Financial Statements. The aggregate net effect of such transactions has effectively been considered settled for cash at the time of the transaction and reflected in the combined Predecessor Statement of Cash Flows as “Transfers to Alpha.”

The Combined Predecessor Financial Statements also include expense allocations of $57,217 for the period from January 1, 2016 to July 25, 2016, for certain corporate and overhead functions historically performed by Alpha, including, but not limited to, general corporate expenses related to finance, legal, information technology, human resources, employee benefits and incentives, insurance, stock-based compensation, engineering, asset management, and sales and logistics, which were included in cost of coal sales and selling, general and administrative expenses within both continuing and discontinued operations in the accompanying Statements of Operations. These amounts exclude reorganization items which are discussed in Note 24 . These expenses have been allocated to the Predecessor based on direct usage when identifiable, with the remainder allocated on the basis of revenues, operating expenses, headcount or other relevant measures. The provision for income taxes has been prepared on a separate return basis. Management believes the assumptions underlying the Combined Predecessor Financial Statements, including the assumptions regarding the allocation of corporate expenses from Alpha, are reasonable. Nevertheless, the Combined Predecessor Financial Statements may not include all the expenses that would have been incurred had the Company been a stand-alone Company during the period presented and may not reflect the Company’s consolidated financial position, results of operations and cash flows had the Company been a stand-alone Company during the period. Actual costs that would have been incurred if the Predecessor had been a stand-alone Company would depend on multiple factors,

102
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

including organizational structure and strategic decisions made in various areas, including information technology and infrastructure.
Alpha used a centralized approach to cash management and financing of its operations. The majority of the Company’s cash during the Predecessor period was transferred to Alpha, which funded its operating and investing activities as needed. This arrangement is not reflective of the manner in which the Company would have been able to finance its operations had it been a stand-alone business separate from Alpha during the Predecessor period.
On August 3, 2015 (“Petition Date”), Alpha and each of its wholly-owned domestic subsidiaries other than ANR Second Receivables Funding LLC (collectively the “Alpha Debtors”) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Virginia (“Bankruptcy Court”). The Alpha Debtors pursued a reorganization plan under which certain expenses were incurred and settlements negotiated, which were included within Reorganization items, net, during the Predecessor period. See Note 24 for further reorganization items disclosures. The Bankruptcy Court approved the Alpha Debtors Plan of Reorganization on July 7, 2016 and Alpha Debtors emerged from bankruptcy on July 26, 2016.
On December 8, 2017, the Company closed a transaction with Blackjewel L.L.C. (“Buyer”) to sell the Eagle Butte and Belle Ayr mines located in the Powder River Basin (“PRB”), Wyoming, along with related coal reserves, equipment, infrastructure and other real properties. The PRB results of operations and financial position are reported as discontinued operations in the Consolidated Financial Statements. The historical information in the accompanying Notes to the Consolidated Financial Statements has been restated to reflect the effects of the PRB operations being reported as discontinued operations in the Consolidated Financial Statements. See Note 4 for further information on discontinued operations.

The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).
Reclassifications
Certain amounts in the prior year Consolidated Statements of Cash Flows and Consolidated Statements of Operations have been reclassified to conform to the current year presentation. Additionally, accretion on asset retirement obligations has been reclassified in prior years from cost of coal sales to a separate line item in the Consolidated Statements of Operations to conform to the current year presentation.
( 2 ) Summary of Significant Accounting Policies

Use of Estimates

The preparation of the Company’s Consolidated Financial Statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Significant items subject to such estimates and assumptions include inventories; mineral reserves; allowance for non-recoupable advanced mining royalties; asset impairments; reclamation obligations; post-employment and other employee benefit obligations; useful lives for, depletion and amortization; reserves for workers’ compensation and black lung claims; deferred income taxes; income taxes refundable and receivable; reserves for contingencies and litigation; liabilities subject to compromise; reorganization items, net; fair value of financial instruments; and fair value adjustments for acquisition accounting. Also, certain amounts in the Predecessor Financial Statements have been allocated in a way that management believes is reasonable and consistent in order to depict the historical financial position, operating results and cash flows of Contura on a carve-out basis. Estimates are based on facts and circumstances believed to be reasonable at the time; however, actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash held with reputable depository institutions and highly liquid, short-term investments with original maturities of three months or less. Cash and cash equivalents are stated at cost, which approximates fair value. At December 31, 2018 , the Company’s cash equivalents consisted of highly rated money market funds.


103
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Restricted Cash

Restricted cash represents deposits that are restricted as to withdrawal as required by certain agreements entered into by the Company and provide collateral in the amounts of $90,759 , $29,611 , $86,217 , $27,386 and $2,833 as of December 31, 2018 for securing the Company’s obligations under certain worker’s compensation, black lung, reclamation-related obligations, general liabilities, and financial guarantees, respectively, which have been written on the Company’s behalf. As of December 31, 2017 collateral was provided in the amounts of $17,105 , $29,265 , and $5,666 for securing the Company’s obligations under certain worker’s compensation, reclamation-related obligations, and financial guarantees, respectively, which have been written on the Company’s behalf. Additionally, the Company has $6,841 of short-term restricted cash held in escrow related to the Company’s contingent revenue payment obligation as of December 31, 2018. Refer to Note 16 for further information regarding the contingent payment revenue obligation. The Company’s restricted cash is primarily invested in interest bearing accounts. This restricted cash is classified as both short-term and long-term on the Company’s Consolidated Balance Sheets.

Restricted Investments

Amounts included in restricted investments primarily consist of certificates of deposit that are restricted as to withdrawal as required by certain agreements entered into by the Company and provide collateral in the amounts of $1,888 , $27,049 , and $200 as of December 31, 2018 for securing the Company’s obligations under certain worker’s compensation, reclamation-related obligations, and general liabilities, respectively, which have been written on the Company’s behalf. Amounts included in restricted investments as of December 31, 2017 includes a treasury bill that was restricted as to withdrawal as required by certain agreements by the Company and provided collateral in the amount of $406 for securing the Company’s obligations under certain worker’s compensation liabilities. Restricted investments are classified as long-term within other non-current assets on the Company’s Consolidated Balance Sheets.

Deposits

Deposits represent cash deposits held at third parties as required by certain agreements entered into by the Company to provide cash collateral. The Company had cash collateral in the form of deposits in the amounts of $24,002 and $1,390 as of December 31, 2018 and $15,238 and $735 as of December 31, 2017 to secure the Company’s obligations under reclamation-related obligations and various other operating agreements, respectively. These deposits are classified as both short-term and long-term on the Company’s Consolidated Balance Sheets.

Trade Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company establishes provisions for losses on accounts receivable when it is probable that all or part of the outstanding balance will not be collected. The Company regularly reviews its accounts receivable balances and establishes or adjusts the allowance as necessary primarily using the specific identification method. The allowance for doubtful accounts was $0 at December 31, 2018 and 2017 . Account balances are written off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

Inventories

Coal is reported as inventory at the point in time the coal is extracted from the mine. Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Saleable coal represents coal stockpiles which require no further processing prior to shipment to a customer.

Coal inventories are valued at the lower of average cost or net realizable value. The cost of coal inventories is determined based on the average cost of production, which includes labor, supplies, equipment costs, operating overhead, depreciation, and other related costs. Net realizable value considers the projected future sales price of the product, less estimated preparation and selling costs.

Material and supplies inventories are valued at average cost, less an allowance for obsolete and surplus items.


104
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Assets and Liabilities Held for Sale

The criteria to determine whether a disposal group should be classified as held-for-sale include: management with the authority to do so commits to a plan to sell the disposal group; the disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such disposal groups; an active program to locate a buyer and other actions required to complete the plan to sell the disposal group have been initiated; the sale of the disposal group is probable and expected to be completed within one year; the disposal group is being actively marketed for sale at a price that is reasonable in relation to its current value; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the disposal group is classified as held for sale on the Company’s Balance Sheet with the assets and liabilities separately presented and measured at the lower of its carrying amount or estimated fair value less costs to sell. Depreciation, depletion and amortization expense is not recorded on assets to be divested once they are classified as held for sale. When the disposal group that is held for sale includes asset retirement obligations, the associated liability continues to be accreted once it is classified as held for sale until the disposal group is sold.

As of December 31, 2018 , assets and liabilities held for sale in the amounts of $0 and $1,351 , respectively, represent the fair value of the disposal group (comprised of asset retirement obligations) within the Company’s CAPP - Met segment. The transaction closed in the first quarter of 2019, and the gain on sale is not expected to be material. As of December 31, 2017 , assets and liabilities held for sale in the amounts of $171 and $27,161 , respectively, represent the fair value of the disposal group (comprised of property, plant and equipment and associated asset retirement obligations) at a preparation plant within the Company’s CAPP - Met segment. Upon permit transfer, the transaction closed on April 2, 2018. The Company paid $10,000 in connection with the transaction, which was paid into escrow on March 27, 2018 and transferred to the buyer at the transaction close date, and expects to pay a series of additional cash payments in the aggregate amount of $1,500 , per the terms stated in the agreement, and recorded a gain on sale of $16,386 within other (income) expense within the Company’s Statements of Operations.

Discontinued Operations

In accordance with Accounting Standards Codification (“ASC”) 205-20-45, the Company treats a disposal transaction as a discontinued operation when the disposal of a component or group of components represents a strategic shift that will have a major effect on the Company’s operations and financial results. In the period in which the discontinued operations criteria are met, the assets and liabilities of the discontinued operations are separately presented on the Company's Balance Sheets and the results of operations, including any gain or loss recognized, is reclassified to discontinued operations on the Company's Income Statement. See Note 4 for further information on discontinued operations.

Deferred Longwall Move Expenses

The Company defers the direct costs, including labor and supplies, associated with moving longwall equipment, the related equipment refurbishment costs, costs to drill gob gas vent holes and plug existing gas wells in advance of the longwall panel in prepaid expenses and other current assets. These deferred costs are amortized on a units-of-production basis into cost of coal sales over the life of the related panel of coal mined by the longwall equipment. The amount of deferred longwall move expenses was $9,822 and $13,790 as of December 31, 2018 and 2017 , respectively, included within other current assets and other non-current assets in the Company’s Balance Sheets.

Advanced Mining Royalties

Lease rights to coal reserves are often acquired in exchange for royalty payments. Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable against future production royalties. These advance payments are deferred and charged to operations as the coal reserves are mined. The Company regularly reviews recoverability of advance mining royalties and establishes or adjusts the allowance for advance mining royalties as necessary using the specific identification method. Advance royalty balances are generally charged off against the allowance when they are no longer recoupable.

105
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)


Advanced mining royalties (net of allowance) were $2,730 and $855 as of December 31, 2018 and 2017 , respectively, and are reported in other non-current assets in the Balance Sheets. The changes in the allowance for advance mining royalties reported in other non-current assets in the Balance Sheets were as follows:
Predecessor
Balance at December 31, 2015
$
3,368

Provision for non-recoupable advance mining royalties
1,862

Balance at July 25, 2016
$
5,230

Successor
Balance at July 26, 2016
$
—

Provision for non-recoupable advance mining royalties
225

Balance at December 31, 2016
225

Provision for non-recoupable advance mining royalties
629

Write-offs of advance mining royalties
(22
)
Balance at December 31, 2017
832

Provision for non-recoupable advance mining royalties
1,338

Write-offs of advance mining royalties
(51
)
Balance at December 31, 2018
$
2,119


Property, Plant, and Equipment

Costs for mine development incurred to expand capacity of operating mines or to develop new mines are capitalized and charged to operations on the units-of-production method over the estimated proven and probable reserve tons directly benefiting from the capital expenditures. Mine development costs include costs incurred for site preparation and development of the mines during the development stage less any incidental revenue generated during the development stage. Mining equipment, buildings and other fixed assets are stated at cost and depreciated on a straight-line basis over estimated useful lives ranging from one to forty-seven years. Leasehold improvements are amortized using the straight-line method, over the shorter of the estimated useful lives or term of the lease. Major repairs and betterments that significantly extend original useful lives or improve productivity are capitalized and depreciated over the period benefited. Maintenance and repairs are expensed as incurred. When equipment is retired or disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposal is recognized in other (income) expense in the Company’s Statements of Operations. Costs to obtain owned and leased mineral rights are capitalized and amortized to operations as depletion expense using the units-of-production method. Only proven and probable reserves are included in the depletion base.

Owned and Leased Mineral Rights

Owned and leased mineral rights, net of accumulated depletion, for the years ended December 31, 2018 and 2017 were $528,232 and $16,627 , respectively, and are reported in assets in the Company’s Consolidated Balance Sheets. These amounts include $47,276 and $15,088 of asset retirement obligation assets, net of accumulated depletion, associated with active mining operations for the years ended December 31, 2018 and 2017, respectively. See Note 3 for information on owned and leased mineral rights assumed with the Merger.

Costs to obtain owned and leased mineral rights are capitalized and amortized to operations as depletion expense using the units-of-production method. Only proven and probable reserves are included in the depletion base. Depletion expense is included in depreciation, depletion and amortization on the accompanying Consolidated Statements of Operations and was $6,804 , $2,954 , ($4,033) , and $29,389 for the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016, respectively.

Depletion expense for the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016 and the period from January 1, 2016 to July 25, 2016 includes an expense of $1,907 , credits of ($821) , ($6,852) , and $0 , respectively, related to revisions to asset retirement obligations. See Note 17 for further disclosures related to asset retirement obligations.

106
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)


Acquired Intangibles

As a result of the Merger in 2018, the Company recognized assets for acquired above market-priced coal supply agreements and acquired mine permits and liabilities for acquired below market-priced coal supply agreements. During the prior year periods, the acquisition from Alpha, as well as other acquisitions during the Predecessor period, resulted in the recognition of assets for above market-priced coal supply agreements and liabilities for below market-priced coal supply agreements on the date of the acquisition. The coal supply agreements were valued based on the present value of the difference between the expected net contractual cash flows based on the stated contract terms, and the estimated net contractual cash flows derived from applying forward market prices at the merger or acquisition date for new contracts of similar terms and conditions. The acquired mine permits were valued based on the benefit and cost savings received by the Company as of the merger date. Coal supply agreement assets and acquired mine permits are reported in other acquired intangibles, net within the Consolidated Balance Sheets and coal supply agreement liabilities are reported in other non-current liabilities in the Consolidated Balance Sheets.

The following tables summarize the other acquired intangibles as of December 31, 2018 and 2017:

December 31, 2017
Acquisitions
Write-off of fully amortized contracts
Amortization
December 31, 2018
Assets:
Above-market coal supply agreements
$
47,120

$
735

$
(26,310
)
$
—

$
21,545

Accumulated amortization
(28,662
)
—

26,310

(14,506
)
(16,858
)
Above-market coal supply agreements, net of accumulated amortization
$
18,458

$
735

$
—

$
(14,506
)
$
4,687

Acquired mine permits
—

153,306

—

—

153,306

Accumulated amortization
—

—

—

(3,409
)
(3,409
)
Acquired mine permits, net of accumulated amortization
$
—

$
153,306

$
—

$
(3,409
)
$
149,897

Liabilities:
Below-market coal supply agreements
—

57,219

—

—

57,219

Accumulated amortization
—

—

—

(23,307
)
(23,307
)
Below-market coal supply agreements, net of accumulated amortization
$
—

$
57,219

$
—

$
(23,307
)
$
33,912


December 31, 2016
Acquisitions
Write-off of fully amortized contracts
Amortization
December 31, 2017
Assets:
Above-market coal supply agreements
$
149,000

$
—

$
(101,880
)
$
—

$
47,120

Accumulated amortization
(61,851
)
—

101,880

(68,691
)
(28,662
)
Above-market coal supply agreements, net of accumulated amortization
$
87,149

$
—

$
—

$
(68,691
)
$
18,458

Liabilities:
Below-market coal supply agreements
570

—

(570
)
—

—

Accumulated amortization
(570
)
—

570

—

—

Below-market coal supply agreements, net of accumulated amortization
$
—

$
—

$
—

$
—

$
—


107
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)


The acquired mine permits are amortized over the estimated life of the associated mine. The coal supply agreement assets and liabilities are amortized over the actual number of tons shipped over the life of each contract. Amortization of mine permits acquired as a result of the Merger was $3,409 for the year ended December 31, 2018, which is reported within amortization of acquired intangibles, net in the Consolidated Statement of Operations. Amortization of above-market coal supply agreements was $14,506 , $68,691 , $61,851 , and $11,567 , and amortization of below-market coal supply agreements was ($23,307) , $0 , ($570) , and $0 , resulting in a net (credit) expense of ($8,801) , $68,691 , $61,281 , and $11,567 for the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016 and the period from January 1, 2016 to July 25, 2016, which is reported within amortization of acquired intangibles, net in the Consolidated Statement of Operations.

Future net amortization expense related to acquired intangibles is expected to be as follows:
2019
$
(4,085
)
2020
18,824

2021
13,024

2022
13,044

2023
11,318

Thereafter
68,547

Total net future amortization expense
$
120,672


Asset Impairment

Long-lived assets, such as property, plant, and equipment, and acquired intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset groups may not be recoverable. Recoverability of assets or asset groups to be held and used is measured by a comparison of the carrying amount of an asset or asset group to the estimated undiscounted future cash flows expected to be generated by the asset or asset group. Long-lived assets located in a close geographic area are grouped together for purposes of impairment testing when, after considering revenue and cost interdependencies, circumstances indicate the assets are used together to produce future cash flows. The Company’s asset groups generally consist of the assets and applicable liabilities of one or more mines and preparation plants and associated coal reserves for which cash flows are largely independent of cash flows of other mines, preparation plants and associated coal reserves. If the carrying amount of an asset or asset group exceeds its estimated future cash flows, the potential impairment is equal to the amount by which the carrying amount of the asset or asset group exceeds the fair value of the asset or asset group. The amount of impairment, if any, is allocated to the long-lived assets on a pro-rata basis, except that the carrying value of the individual long-lived assets are not reduced below their estimated fair value. See Note 12 for further disclosures related to asset impairments.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of the net identifiable tangible and intangible assets of acquired companies. Goodwill is not amortized; instead, it is tested for impairment annually or more frequently if indicators of impairment exist. The Company early adopted Accounting Standards Update (“ASU”) 2017-04 for the period ended December 31, 2017, which eliminated Step 2 of the quantitative goodwill impairment test.

The Company first assesses goodwill on a qualitative basis. If the qualitative assessment indicates that an impairment potentially exists, then the Company tests its goodwill for impairment by comparing the fair value of each reporting unit to its carrying amount. Goodwill impairment exists when the estimated implied fair value of goodwill is less than its carrying value. As of December 31, 2018 , the Company had goodwill of $95,624 related to the Merger. See Note 3 for further disclosures related to the Merger.

108
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Asset Retirement Obligations

Minimum standards for mine reclamation have been established by various regulatory agencies and dictate the reclamation requirements at the Company’s operations. The Company’s asset retirement obligations consist principally of costs to reclaim acreage disturbed at surface operations, estimated costs to reclaim support acreage, treat mine water discharge and perform other related functions at underground mines. The Company records these reclamation obligations at fair value in the period in which the legal obligation associated with the retirement of the long-lived asset is incurred. Changes to the liability at operations that are not currently being reclaimed are offset by increasing or decreasing the carrying amount of the related long-lived asset. Changes to the liability at operations that are currently being reclaimed are recorded to depreciation, depletion and amortization. Over time, the liability is accreted and any capitalized cost is depreciated or depleted over the useful life of the related asset. To settle the liability, the obligation is paid, and to the extent there is a difference between the liability and the amount of cash paid, a gain or loss upon settlement is recorded. The Company annually reviews its estimated future cash flows for its asset retirement obligations. See Note 17 for further disclosures related to asset retirement obligations.

Income Taxes

The Company recognizes deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In evaluating its ability to recover deferred tax assets within the jurisdiction in which they arise, the Company considers all available positive and negative evidence, including the expected reversals of taxable temporary differences, projected future taxable income, taxable income available via carryback to prior years, tax planning strategies, and results of recent operations. The Company assesses the realizability of its deferred tax assets, including scheduling the reversal of its deferred tax assets and liabilities, to determine the amount of valuation allowance needed. Scheduling the reversal of deferred tax asset and liability balances requires judgment and estimation. The Company believes the deferred tax liabilities relied upon as future taxable income in its assessment will reverse in the same period and jurisdiction and are of the same character as the temporary differences giving rise to the deferred tax assets that will be realized.

For the Predecessor Financial Statements, the Company’s income tax provision was determined as if it filed income tax returns on a stand-alone basis. In jurisdictions where the Company had been included in the tax returns filed by Alpha, any income taxes payable resulting from the related income tax provision have been reflected in the balance sheet within Alpha’s investment. See Note 21 for further disclosures related to income taxes.

Revenue Recognition

The Company adopted ASC 606, with a date of initial application of January 1, 2018, using the modified retrospective method. As a result, the Company made changes to its accounting policy for revenue recognition as outlined below.

Subsequent to the adoption of ASC 606, the Company measures revenue based on the consideration specified in a contract with a customer and recognizes revenue as a result of satisfying its promise to transfer goods or services in a contract with a customer using the following general revenue recognition five-step model: (1) identify the contract; (2) identify performance obligations; (3) determine transaction price; (4) allocate transaction price; (5) recognize revenue. Freight and handling costs paid to third-party carriers and invoiced to coal customers are recorded as freight and handling costs and freight and handling fulfillment revenues within coal revenues, respectively.

Prior to the adoption of ASC 606, the Company earned revenues primarily through the sale of coal produced at Company operations and coal purchased from third parties. The Company recognized revenue using the following general revenue recognition criteria: (i) persuasive evidence of an arrangement exists; (ii) delivery had occurred or services have been rendered; (iii) the price to the buyer was fixed or determinable; and (iv) collectability was reasonably assured.

Delivery on the Company’s coal sales was determined to be complete for revenue recognition purposes when title and risk of loss had passed to the customer in accordance with stated contractual terms and there are no other future obligations related to the shipment. For domestic shipments, title and risk of loss generally passed as the coal is loaded into transport carriers for delivery to the customer. For international shipments, title generally passed at the time coal is loaded onto the shipping vessel.

Freight and handling costs paid to third-party carriers and invoiced to coal customers were recorded as freight and handling

109
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

costs and freight and handling revenues, respectively.

Deferred Financing Costs

The costs to obtain new debt financing or amend existing financing agreements are generally deferred and amortized to interest expense over the life of the related indebtedness or credit facility using the effective interest method. Unamortized deferred financing costs are presented in the Consolidated Balance Sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts or premiums.

Reorganization Items and Other Bankruptcy Related Costs

ASC Topic 852, Reorganizations, requires separate disclosure of reorganization items such as realized gains and losses from the settlement of pre-petition liabilities, and provisions for losses resulting from the reorganization of the business, as well as professional fees directly related to the process of reorganizing under Chapter 11. Refer to Note 24 for further details regarding reorganization items.

Workers’ Compensation and Pneumoconiosis (Black Lung) Benefits

Workers’ Compensation

As of December 31, 2018 , the Company primarily utilizes high-deductible insurance programs for workers’ compensation claims at its operations. Prior to July 26, 2016, the Company was self-insured for workers’ compensation claims at certain of its operations and was covered by third-party insurance providers at other locations, in addition to participating in the Wyoming state-run fund. The liabilities for workers’ compensation claims are estimates of the ultimate losses incurred based on the Company’s experience, and include a provision for incurred but not reported losses. Adjustments to the probable ultimate liabilities are made annually based on an actuarial study and adjustments to the liability are recorded based on the results of this study. These short-term and long-term obligations are included in the Consolidated Balance Sheets within accrued expenses and other current liabilities and workers’ compensation and black lung obligations, respectively, with an offsetting insurance receivable within other non-current assets. As of December 31, 2018 , the workers’ compensation liability is net of a discount of $24,655 related to fair value adjustments associated with acquisition accounting. See Note 22 for further disclosures related to workers’ compensation.

Black Lung Benefits

The Company is required by federal and state statutes to provide benefits to employees for awards related to black lung. As of December 31, 2018 , the Company primarily utilizes high-deductible insurance programs for these benefits. Prior to July 26, 2016, the Company was self-insured at certain locations and covered by a third-party insurance provider at other locations. Charges are made to operations for black lung claims, as determined by an independent actuary at the present value of the actuarially computed liability for such benefits over the employee’s applicable term of service. The Company recognizes in its balance sheet the amount of the Company’s unfunded Accumulated Benefit Obligation (“ABO”) at the end of the year. Amounts recognized in accumulated other comprehensive income (loss) are adjusted out of accumulated other comprehensive income (loss) when they are subsequently recognized as components of net periodic benefit cost. These short-term and long-term obligations are included in the Consolidated Balance Sheets within accrued expenses and other current liabilities and workers’ compensation and black lung obligations, respectively. See Note 22 for further disclosures related to black lung benefits.

Pension

The Company is required to recognize the overfunded or underfunded status of a defined benefit pension plan as an asset or liability in its Consolidated Balance Sheets and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income (loss). The Company is required to measure plan assets and benefit obligations as of the date of the Company’s fiscal year-end Consolidated Balance Sheet and provide the required disclosures as of the end of each fiscal year. See Note 22 for further disclosures related to pension.

110
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Life Insurance Benefits

As part of the Alpha Restructuring and the Retiree Committee Settlement Agreement, the Company assumed the liability for life insurance benefits for certain disabled and non-union retired employees. Provisions are made for estimated benefits based on annual evaluations prepared by independent actuaries. Adjustments to the probable ultimate liabilities are made annually based on an actuarial study and adjustments to the liability are recorded based on the results of this study. These obligations are included in the Balance Sheet as accrued expenses and other current liabilities and other non-current liabilities. See Note 22 for further disclosures related to life insurance benefits.

Earnings (Loss) Per Share

Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted-average number of outstanding common shares for the period. Diluted earnings (loss) per share reflects the potential dilution that could occur if instruments that may require the issuance of common shares in the future were settled and the underlying common shares were issued. Diluted earnings (loss) per share is computed by increasing the weighted-average number of outstanding common shares computed in basic earnings (loss) per share to include the additional common shares that would be outstanding after issuance and adjusting net income (loss) for changes that would result from the issuance. Only those securities that are dilutive are included in the calculation. See Note 7 for further disclosures related to earnings (loss) per share.

Stock-Based Compensation

The Company recognizes expense for stock-based compensation awards based on their grant-date fair value. The expense is recorded over the respective service period of the underlying award. The Company recognizes forfeitures of stock-based compensation awards as they occur. See Note 23 for further disclosures related to stock-based compensation arrangements.

Warrants

The Company issued Series A Warrants on July 26, 2016 and classified the warrants as a derivative liability as they possess an underlying amount (stock price), a notional amount (number of shares), require no initial net investment, and allow for net share settlement. Through June 30, 2017, the warrants were fair-valued using a Black-Scholes pricing model and a mark to market non-cash adjustment at each reporting period with changes in value reflected in earnings. The Company early adopted ASU 2017-11 for the period ended June 30, 2017, with retrospective adjustments to the Consolidated Balance Sheet through an adjustment to retained earnings as of the beginning of 2017 for all prior period mark-to-market adjustments and adjustments to the Consolidated Statement of Operations through the reversal of all year-to-date mark-to-market adjustments.

The exercise price and the warrant share number will be adjusted in respect of certain dilutive events with respect to the common stock (namely, dividends or distributions on the common stock, share splits and combinations, above-market tender offers for common stock by Contura or a subsidiary thereof, and discounted issuances of common stock or rights or options to purchase common stock or securities convertible or exchangeable into common stock). Additionally, in the case of any reorganization (i.e., a consolidation, merger or sale of all or substantially all of the consolidated assets of Contura) pursuant to which the common stock is converted into cash, securities or other property, the warrants would become exercisable for such property. See Note 20 for further disclosures related to warrants.

Equity Method Investments

Investments in unconsolidated affiliates that the Company has the ability to exercise significant influence over, but not control, are accounted for under the equity method of accounting. Under the equity method of accounting, the Company records its proportionate share of the entity’s net income or loss at each reporting period in the Statements of Operations in other income (expense), with a corresponding entry to increase or decrease the carrying value of the investment. The carrying value of the Company’s equity method investments was $15,236 and $16,095 as of December 31, 2018 and 2017 , respectively.

New Accounting Pronouncements

Revenue Recognition: In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from contracts with customers (Topic 606), which, along with amendments issued in 2015 and 2016, replaced substantially all current U.S. GAAP guidance on this topic and eliminate industry-specific guidance. In addition, the standard requires

111
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The guidance permitted two methods of adoption: full retrospective method (retrospective application to each prior reporting period presented) or modified retrospective method (retrospective application with the cumulative effect of initially applying the guidance recognized at the date of initial application and providing certain additional disclosures). The Company adopted ASU 2014-09 as of January 1, 2018, using the modified retrospective method. The Company applied the guidance only to contracts that were not completed as of the date of adoption, with no cumulative adjustment to retained earnings as a result of the adoption of this guidance. Subsequent to adoption, freight and handling revenues are now classified within coal revenues. Under ASC 606, the Company has elected to treat all shipping and handling costs as fulfillment costs and to recognize these amounts within coal revenues upon control transfer. Prior to the adoption of ASC 606, all freight and handling activities occurring subsequent to control transfer were accounted for as deferred revenue and recognized within freight and handling revenues as the Company fulfilled the related shipping activity. Refer to Note 5 for further disclosure requirements under the new standard. The following table summarizes the impact of the adoption of ASC 606 to the Company’s Consolidated Statements of Operations:
Year Ended December 31, 2018
As reported
Adjustments (1)
Balances prior to adoption of ASC 606
Revenues:

Coal revenues
$
2,020,889

$
(363,128
)
$
1,657,761

Freight and handling revenues
—

362,346

362,346

Other revenues
10,316

—

10,316

Total revenues
$
2,031,205

$
(782
)
$
2,030,423

Freight and handling costs
$
363,128

$
(782
)
$
362,346

(1) Adjustments primarily represent freight and handling revenues being treated as fulfillments costs and included within coal revenues under ASC 606. The remainder of these adjustments represent freight and handling activity occurring subsequent to control transfer also impacting freight and handling costs and prepaid expenses.

Financial Instruments: In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). The amendments in this update, along with amendments issued in 2018, address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The Company adopted ASU 2016-01 during the first quarter of 2018. The adoption of this update did not have a material impact on the recognition, measurement, presentation, or disclosure of the Company’s financial instruments.

Leases : In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”). ASU 2016-02, along with amendments issued in 2017 and 2018 (collectively, the “New Leases Standard”), requires a lessee to recognize a right-of-use asset and a lease liability on the balance sheet. Additional qualitative disclosures along with specific quantitative disclosures will also be required.

I n July 2018, the FASB issued a new optional transition method to simplify the application of the New Leases Standard. Under the optional transition method, comparative periods presented in the financial statements in the period of adoption will not need to be restated. Instead, a company would initially apply the new lease requirements at the effective date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The company would continue to report comparative periods presented in the financial statements in the period of adoption under current GAAP and provide the applicable required disclosures for such periods. For public business entities, the New Leases Standard is effective for annual reporting periods beginning after December 15, 2018, with early adoption permitted. The Company adopted the New Lease Standards as of January 1, 2019.

The Company elected the optional transition method to implement the New Leases Standard. Additionally, the Company elected the package of practical expedients for all leases which permits the Company to not reassess expired or existing contracts to determine: whether they are or contain leases, lease classification, and initial direct costs. Management elected the optional transition expedient which allows the Company to continue applying the current policy for accounting for expired or existing land easement contracts not previously accounted for under current GAAP. New or modified land easements executed

112
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

after adoption will be considered under the New Leases Standard. The Company elected the practical expedient as an accounting policy election for all asset classifications to not separate lease and non-lease components and instead account for them as a single lease component. Management made the accounting policy election for all asset classifications to apply current GAAP to leases which meet the definition of short-term lease under the New Leases Standard (i.e., 12 months or less), and therefore did not recognize a right-of-use and a lease liability for these leases. Management expects the impact of adopting the New Leases Standard to result in an initial lease liability with offsetting right-of-use assets of approximately $14,000 to $19,000 . The Company also expects to report additional quantitative and qualitative disclosures required under the New Leases Standard that are not presently required under current GAAP.

Statement of Cash Flows: In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments . This update addresses whether to present certain specific cash flow items as operating, investing or financing activities. The Company adopted ASU 2016-15 during the first quarter of 2018. The classification requirements under the new guidance are either consistent with the Company’s historical practices or are not applicable to its activities and therefore do not have a material impact on classification of cash receipts and cash payments in the Company’s Statements of Cash Flows.

In November 2016, the FASB issued ASU 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”). The amendments in this update provide guidance on restricted cash presentation in the statement of cash flows. The Company adopted ASU 2016-18 during the first quarter of 2018. As a result of this guidance, the Company has combined restricted cash with unrestricted cash and cash equivalents when reconciling the beginning and end of period balances on its Consolidated Statements of Cash Flows. The amendments also require a company to disclose information about the nature of the restrictions and amounts described as restricted cash and restricted cash equivalents. Such disclosures are included in Note 26 .

Business Combinations: In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). The amendments in this update provide clarification on the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The new guidance is to be applied prospectively on or after the effective date. The Company adopted ASU 2017-01 during the first quarter of 2018. The adoption of this ASU did not have a material impact on the Company’s financial statements.

Retirement Benefits: In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost . The amendments in this update require that an employer disaggregate the service cost component from the other components of net periodic benefit cost. In addition, only the service cost component will be eligible for capitalization. The new guidance is to be applied retrospectively for income statement effects and prospectively for balance sheet effects. Additionally, the new guidance allows a practical expedient that permits employers to use the amounts disclosed in its pension and other postretirement benefit plan note for the prior comparative periods as the estimation basis for applying the retrospective presentation requirements. The Company adopted ASU 2017-07 during the first quarter of 2018, electing to use the practical expedient as the estimation basis for applying the retrospective presentation requirements. The retrospective application resulted in a $831 , $371 , and $14,451 reduction in cost of coal sales with the corresponding offset to miscellaneous income, net for the year ended December 31, 2017 , the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016, respectively.

Stock Compensation: In May 2017, the FASB issued ASU 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting (“ASU 2017-09”). The amendments in this update provide clarification on which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic 718. The new guidance is to be applied prospectively on or after the adoption date. The Company adopted ASU 2017-09 during the first quarter of 2018. The adoption of this ASU did not have a material impact on the Company’s financial statements.

In June 2018, the FASB issued ASU 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). The amendments in this update expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. For public business entities, the standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The adoption of this ASU is not expected to have a material impact on the Company's financial statements and related disclosures.

Fair Value Measurement : In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820), Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”). The

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CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

amendments in this update modify the disclosure requirements for fair value measurements. For public business entities, the standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The adoption of this ASU is not expected to have a material impact on the Company’s financial statements and related disclosures.

Defined Benefit Plans: In August 2018, the FASB issued ASU 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20) Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). The amendments in this update modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For public business entities, the standard is effective for fiscal years ending after December 15, 2020. The Company is currently assessing the impact of this ASU on the Company’s financial statements and related disclosures.

( 3 ) Mergers and Acquisitions

Merger with Alpha Natural Resources Holdings, Inc. and ANR, Inc.

On November 9, 2018, Contura, along with the Alpha Companies, completed the Merger in which the Company acquired 100% of the outstanding Class C-1 shares of ANR and the 100% of the outstanding shares of Holdings. Under the terms of the Merger Agreement, the Alpha Companies stockholders received 0.4417 Contura common shares for each ANR Class C-1 share and each share of common stock of Holdings they owned, representing approximately 48.5% ownership in the merged entity, or an aggregate 9,378,199 shares of Contura common stock. Prior to the closing of the transaction, the Alpha Companies stockholders also received a special cash dividend (the “Dividend”) in an amount equal to $ 2.725 for each Class C-1 share and each share of common stock of Holdings they owned. Each outstanding share of Class C-2 common stock of ANR (held exclusively by Holdings) was canceled. The fair value of the issued Contura common stock was equal to the $75.00 closing price of Contura’s common stock on the day of acquisition.

On July 16, 2018, Contura, along with the Alpha Companies, announced the confidential submission by Contura of a registration statement on Form S-4 with the U.S. Securities and Exchange Commission (“SEC”) relating to the previously announced proposed Merger between the companies. On October 16, 2018, the SEC declared effective the registration statement on Form S-4, as amended, (“Form S-4”) filed by Contura in connection with the transaction, which included a joint proxy statement of the Alpha Companies and a prospectus of Contura relating to the transaction.

The transaction is expected to enhance the Company’s competitive position in both domestic and international coal markets. The Company possesses diverse high-quality, metallurgical and thermal coal mines, allowing for near-term organic growth opportunities. The transaction is also expected to generate costs synergies, including those resulting from coal blending and marketing optimization and purchasing, operating and administrative efficiencies.

During 2018, the Company recorded $3,918 as a reduction to equity for costs incurred in connection with the submission of the Form S-4 related to (i) legal fees for drafting the registration statement and other legal advice directly related to the registration statement, (ii) financial reporting advisory fees directly related to the registration statement including preparation of the pro forma financial statements and other financial information included in the registration statement and (iii) and other registration related fees.

Purchase Price

The following table presents the details of the preliminary purchase price allocation of $688,534 :

Provisional as of November 9, 2018
Fair value of common stock issued
$
703,365

Issued and redeemed equity awards (1)
32,217

Net balances due to Alpha deemed effectively settled
(47,048
)
Purchase Price (2)
$
688,534



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CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

(1) Amount includes $20,681 of tax withholdings related to share settlements of option exercises, $1,905 paid to certain former ANR employees pursuant to change in control provisions, $6,570 of shares repurchased from certain former ANR directors pursuant to the Merger Agreement, $3,056 of pre-Merger service period value of RSU ANR employee awards and $5 in cash paid in lieu of fractional shares of Contura common stock issued pursuant to the Merger Agreement. Of these amounts, $24,074 were obligations assumed and paid by Contura.
(2) Purchase price of $688,534 is comprised of equity consideration of $664,460 and cash consideration of $24,074 .

Preliminary Allocation of Purchase Price

As of December 31, 2018, the fair value allocation for the acquisition is preliminary and will be finalized when the valuation and the related internal controls over financial reporting are completed. Differences between the preliminary and final allocation could be material. The Company’s estimates and assumptions are subject to change during the measurement period (up to one year from the closing of the acquisition), as the Company finalizes the accounting for the purchase price of the assets acquired and liabilities assumed. The primary areas of the purchase price allocation that are not yet finalized relate to the areas of property plant and equipment, owned and leased mineral rights, inventory, acquired intangibles, goodwill, asset retirement obligations, taxes, accounts payable, certain actuarial liabilities and other contingencies. The Company continues to review the significant amount of data and assumptions used in these areas which could cause a reallocation of the purchase price. The below table is a preliminary allocation of the assets acquired and the liabilities the Company assumed in the acquisition as of November 9, 2018, the date of the acquisition.


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CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

The total purchase price has been preliminarily allocated to the net tangible and intangible assets of Alpha Companies as follows:
Provisional as of November 9, 2018
Cash and cash equivalents
$
29,939

Trade and other receivables
60,714

Inventories
85,635

Short-term restricted cash
10,592

Other current assets
38,495

Property, plant, and equipment, net
504,852

Owned and leased mineral rights
516,201

Other intangible assets
154,041

Long-term restricted cash
182,049

Long-term restricted investments
28,809

Other non-current assets
68,022

Total assets
$
1,679,349

Accounts payable
69,049

Accrued expenses and other current liabilities
76,774

Long-term debt, including current portion
144,832

Acquisition related obligations
74,346

Pension obligations
158,005

Asset retirement obligation, including current portion
163,636

Deferred income taxes, including current portion
134,924

Other intangible liabilities
57,219

Other non-current liabilities
207,654

Total liabilities
$
1,086,439

Goodwill
$
95,624

Allocation of purchase price
$
688,534


In connection with Merger, the Company recorded provisional goodwill of $95,624 , which represents the excess of the purchase price over the estimated fair value of tangible and intangible asset acquired, net of liabilities assumed. The goodwill is attributed primarily to the following factors: (i) anticipated operating and administrative synergies, and (ii) deferred income taxes arising from the differences between the preliminary purchase price allocated to the assets and liabilities acquired based on fair value and the tax basis of these assets and liabilities. The goodwill is not deductible for tax purposes. The Company’s provisional estimate of goodwill is not yet finalized and has not been allocated to the Company’s reportable segments.

The following table represents the intangible assets and the weighted-average amortization periods as of the acquisition date:

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CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Provisional Amount
Weighted-Average Amortization Period
( In Years )
Mining permits
$
153,306

11.60
Above-market coal supply agreements
735

1.03
Below-market coal supply agreements
(57,219
)
2.10
Total acquired intangibles:
$
96,822

9.51

The Statements of Operations include acquisition related expenses (on a pre-tax basis) of $20,571 in merger related costs for the year ended December 31, 2018. Acquisition related expenses include professional fees related to legal, tax, advisory integration services and contract related matters.

Total revenues reported in the Statements of Operations for the year ending December 31, 2018 included revenues of $149,161 from operations acquired from the Alpha Companies. The amount of earnings from continuing operations acquired from the Alpha Companies included in the consolidated results of operations for the year ending December 31, 2018 is not readily determinable due to various intercompany transactions and allocations that have occurred in connection with the integration of the operations of the newly combined company.

The following unaudited pro forma information has been prepared for illustrative purposes only and assumes the Merger occurred on January 1, 2017. The unaudited pro forma results have been prepared based on estimates and assumptions, which the Company believes are reasonable; however, they are not necessarily indicative of the consolidated results of operations had the Merger occurred on January 1, 2017, or of future results of operations.

Year Ended December 31, 2018
Year Ended December 31, 2017
Total revenues

As reported
$
2,031,205

$
1,649,969

Pro forma
$
2,630,824

$
2,309,503

Income from continuing operations
As reported
$
302,854

$
173,735

Pro forma
$
320,306

$
234,382


These amounts have been calculated after applying the Company's accounting policies and adjusting the results of ANR to reflect the additional depreciation, amortization, depletion, and cost of coal sales that would have been charged assuming the fair value adjustments to property, plant and equipment, as well as intangibles, asset retirement obligations, and inventory had been applied at January 1, 2017, together with the consequential tax effects.

The pro forma results for the year ended December 31, 2018 include $51,800 of merger-related costs, which includes $20,571 of acquisition-related expenses and $31,229 of expenses related primarily to severance payments and one-time bonus payments, $17,064 of incremental cost of coal sales related to the inventory step-up included in the purchase price allocation, and a tax benefit of $134,924 related to the reduction of the Company's deferred tax asset valuation allowance.

( 4 ) Discontinued Operations

The discontinued operations include the Company’s former PRB segment. On December 8, 2017, the Company closed a transaction (“PRB Transaction”) with Blackjewel L.L.C. (“Blackjewel”) to sell the Eagle Butte and Belle Ayr mines located in the PRB. During the permit transfer period, the Company will maintain the required reclamation bonds and related collateral. As of December 31, 2018 , the Company had outstanding surety bonds with a total face amount of $237,150 to secure various obligations and commitments related to the PRB. The Powder River Basin Resource Council filed objections to the permit transfer with the Wyoming Environmental Quality Council on November 16, 2018. The objections are scheduled to be heard on May 15 and 16, 2019. The Company currently believes the objections are without merit. Once the permits have been

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CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

transferred, the Company estimates approximately $12,600 comprised of short-term restricted cash and short-term deposits will be returned to operating cash. If the permit transfer process is not completed as expected, it could have material, adverse effects on the Company.

The major components of net income (loss) from discontinued operations in the Consolidated Statements of Operations are as follows:
Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Revenues:


Total revenues (1)
$
1,296

$
346,621

$
183,123

$
196,827

Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)
$
—

$
311,119

$
140,803

$
164,920

Depreciation, depletion and amortization
$
—

$
30,090

$
38,005

$
19,303

Other expenses
$
4,150

$
—

$
—

$
659

Other non-major expense items, net
$
2,140

$
5,475

$
2,848

$
12,624

Loss on sale
$
—

$
36,831

$
—

$
—

(1) Total revenues for the year ended December 31, 2018 consisted entirely of other revenues.

Refer to Note 7 for earnings (loss) per share information related to discontinued operations.

The major components of asset and liabilities that are classified as discontinued operations in the Consolidated Balance Sheets are as follows:
December 31, 2018
December 31, 2017
Assets:


Accounts Receivable
$
5

$
20,443

Prepaid expenses and other current assets
$
22,470

$
18,974

Other current assets
$
—

$
1,081

Other non-current assets
$
—

$
7,632

Liabilities:


Trade accounts payable, accrued expenses and other current liabilities
$
21,892

$
54,114

Other non-current liabilities
$
94

$
7,762


As of December 31, 2018 , the residual assets and liabilities related to the discontinued operations are primarily comprised of taxes for which Contura is considered to be the primary obligor but which the Buyer is contractually obligated to pay. The Company has recorded the taxes as a liability with an offsetting receivable from the Buyer.

The major components of cash flows related to discontinued operations are as follows:

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CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Depreciation, depletion and amortization
$
—

$
30,090

$
38,005

$
19,303

Capital expenditures
$
—

$
(10,420
)
$
(11,123
)
$
(8,071
)
Other significant operating non-cash items related to discontinued operations:
Accretion on asset retirement obligations
$
—

$
11,341

$
6,019

$
7,400

Asset impairment and restructuring
$
—

$
—

$
—

$
659


Blackjewel Surety Bonding
During the third quarter of 2018, Blackjewel procured surety bonds for a total of $220,500 to facilitate the transfer of record by the State of Wyoming of the Belle Ayr and Eagle Butte mine permits from Contura Coal West, LLC to Blackjewel as required by the Asset Purchase Agreement dated as of December 7, 2017, among Blackjewel, Contura Energy, Inc. (“Contura”), Contura Coal West, LLC, Contura Wyoming Land, LLC, Contura Coal Sales, LLC, and Contura Energy Services, LLC.
Contura agreed to backstop a total of $44,800 of Blackjewel’s bonding obligations with respect to the Belle Ayr and Eagle Butte permits by entering into secondary general indemnification agreements and providing letters of credit totaling $18,800 to the sureties as collateral for Contura’s indemnification obligations. This arrangement provides cost reimbursement for the issuing sureties. Indemnity bonds were issued by a third-party insurer in favor of Contura in a total amount of $26,000 to insure Blackjewel’s performance obligations to Contura with respect to cancellation of the general indemnification agreements and return of the letters of credit.
Blackjewel agreed that, by June 30, 2019, it will (i) enter into financing arrangements of $44,800 to be held as collateral by the sureties and (ii) cause each surety to release and return each letter of credit and cancel the Contura general indemnification agreements.
Blackjewel’s performance obligations are also collateralized by a security interest in mobile equipment granted to Contura under 8.6(c) of the Asset Purchase Agreement. Further, in connection with this arrangement, approximately $8,000 in surety cash collateral previously supporting reclamation bonds was returned to Contura by certain of its sureties.

The Company recorded the fair value of the guarantee within discontinued operations to account for the Blackjewel surety bonding arrangement with no material impact on the Company's Financial Statements.

( 5 ) Revenue

Revenue Recognition Accounting Policy

The Company adopted ASC 606, with a date of initial application of January 1, 2018, using the modified retrospective method. As a result, the Company made changes to its accounting policy for revenue recognition as outlined below.

Subsequent to the adoption of ASC 606, the Company measures revenue based on the consideration specified in a contract with a customer and recognizes revenue as a result of satisfying its promise to transfer goods or services in a contract with a customer using the following general revenue recognition five-step model: (1) identify the contract; (2) identify performance obligations; (3) determine transaction price; (4) allocate transaction price; (5) recognize revenue. Freight and handling costs paid to third-party carriers and invoiced to coal customers are recorded as freight and handling costs and freight and handling fulfillment revenues within coal revenues, respectively.

Disaggregation of Revenue from Contracts with Customers

ASC 606 requires that entities disclose disaggregated revenue information in categories (such as type of good or service, geography, market, type of contract, etc.) that depict how the nature, amount, timing, and uncertainty of revenue and cash flow are affected by economic factors. ASC 606 explains that the extent to which an entity’s revenue is disaggregated depends on the

119
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

facts and circumstances that pertain to the entity’s contracts with customers and that some entities may need to use more than one type of category to meet the objective for disaggregating revenue.

The Company earns revenues primarily through the sale of coal produced at Company operations and coal purchased from third parties. The Company extracts, processes and markets met and thermal coal from surface and deep mines for sale to electric utilities, steel and coke producers, and industrial customers. The Company conducts mining operations only in the United States with mines in Northern and Central Appalachia. The Company has four reportable segments: CAPP - Met, CAPP - Thermal, NAPP, and Trading and Logistics. In addition to the four reportable segments, the All Other category includes general corporate overhead and corporate assets and liabilities, the elimination of certain intercompany activity, and the Company’s discontinued operations. See Note 28 for further segment information.

The following tables disaggregate the Company’s coal revenues by segment and by met and thermal coal to depict how the nature, amount, timing, and uncertainty of the Company’s coal revenues and cash flows are affected by economic factors:

Successor
Year Ended December 31, 2018
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Met
$
635,195

$
3,584

$
49,683

$
690,285

$
—

$
1,378,747

Thermal
13,846

32,101

231,492

1,575

—

279,014

Freight and handling fulfillment revenues
—

—

—

363,128

—

363,128

Total coal revenues
$
649,041

$
35,685

$
281,175

$
1,054,988

$
—

$
2,020,889


Successor
Year Ended December 31, 2017
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Met
$
454,746

$
—

$
19,235

$
631,838

$
—

$
1,105,819

Thermal
4,060

—

282,554

48

—

286,662

Total coal revenues
$
458,806

$
—

$
301,789

$
631,886

$
—

$
1,392,481

Freight and handling revenues
$
—

$
—

$
—

$
247,402

$
—

$
247,402


Successor
Period from July 26, 2016 to December 31, 2016
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Met
$
137,373

$
—

$
11,380

$
163,750

$
—

$
312,503

Thermal
608

—

118,581

—

—

119,189

Total coal revenues
$
137,981

$
—

$
129,961

$
163,750

$
—

$
431,692

Freight and handling revenues
$
—

$
—

$
—

$
70,544

$
—

$
70,544



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CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Predecessor
Period from January 1, 2016 to July 25, 2016
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Met
$
127,248

$
—

$
13,061

$
7,248

$
—

$
147,557

Thermal
4,392

—

191,412

1,331

—

197,135

Total coal revenues
$
131,640

$
—

$
204,473

$
8,579

$
—

$
344,692



Freight and handling revenues
$
34,822

$
—

$
14,121

$
3,133

$
—

$
52,076



Performance Obligations

The Company considers each individual transfer of coal on a per shipment basis to the customer a performance obligation. The pricing terms of the Company’s contracts with customers include fixed pricing, variable pricing, or a combination of both fixed and variable pricing. All the Company’s revenue derived from contracts with customers is recognized at a point in time. The following table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied as of December 31, 2018 .
2019
2020
2021
2022
2023
Total
Estimated coal revenues (1)
$
239,650

$
129,985

$
95,590

$
69,943

$
84,268

$
619,436

(1) Amounts only include estimated coal revenues associated with contracts with customers with fixed pricing with original expected duration of more than one year. The Company has elected to not disclose the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period for performance obligations with either of the following conditions: 1) the remaining performance obligation is part of a contract that has an original expected duration of one year or less; or 2) the remaining performance obligation has variable consideration that is allocated entirely to a wholly unsatisfied performance obligation.

Contract Balances

During the year ended December 31, 2018 the Company paid amounts under certain contracts related to the modification of contract terms. These payments were deferred and allocated to the remaining performance obligations after contract modification. The following table includes the opening and closing balances of contract assets from modifications with contracts with customers, which are included within prepaid expenses and other current assets on the Company’s Consolidated Balance Sheets:

December 31,
2018
December 31,
2017
Contract assets (1)
$
950

$
—

(1) Amounts primarily relate to payments made upon modification of coal contracts.


( 6 ) Accumulated Other Comprehensive (Loss) Income
The following tables summarize the changes to accumulated other comprehensive income (loss) during the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016:

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CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Successor
Balance
January 1, 2018
Other comprehensive income (loss) before reclassifications
Amounts reclassified from accumulated other comprehensive income (loss)
Balance
December 31, 2018
Employee benefit costs
$
(1,948
)
$
(21,323
)
$
141

$
(23,130
)
Successor
Balance
January 1, 2017
Other comprehensive income (loss) before reclassifications
Amounts reclassified from accumulated other comprehensive income (loss)
Balance December 31, 2017
Employee benefit costs
$
2,087

$
(3,832
)
$
(203
)
$
(1,948
)
Successor
Balance
July 26, 2016
Other comprehensive income (loss) before reclassifications
Amounts reclassified from accumulated other comprehensive income (loss)
Balance December 31, 2016
Employee benefit costs
$
—

$
2,087

$
—

$
2,087

Predecessor
Balance
January 1, 2016
Other comprehensive income (loss) before reclassifications
Amounts reclassified from accumulated other comprehensive income (loss)
Balance July 25, 2016
Employee benefit costs
$
4,135

$
(2,188
)
$
2,397

$
4,344


The following table summarizes the amounts reclassified from accumulated other comprehensive income (loss) and the Statements of Operations line items affected by the reclassification during the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016:
Details about accumulated other comprehensive income (loss) components
Amounts reclassified from accumulated other comprehensive (loss) income
Affected line item in the Statements of Operations
Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Employee benefit costs:
Amortization of actuarial loss (gain)
$
155

$
(203
)
$
—

$
206

(1) Miscellaneous income
Amortization of prior service cost
—

—

—

824

(1) Miscellaneous income
Curtailment gain
—

—

—

2,712

(1) Miscellaneous income
Total before income tax
$
155

$
(203
)
$
—

$
3,742

Income tax expense
(14
)
—

—

(1,345
)
Income tax expense
Total, net of income tax
$
141

$
(203
)
$
—

$
2,397

(1) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit costs for black lung and life insurance. See Note 22 .

( 7 ) Earnings (Loss) Per Share
The number of shares used to calculate basic earnings (loss) per common share is based on the weighted average number of the Company’s outstanding common shares during the respective period. The number of shares used to calculate diluted earnings (loss) per common share is based on the number of common shares used to calculate basic earnings (loss) per share plus the dilutive effect of stock options and other stock-based instruments held by the Company’s employees and directors

122
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

during the period, and the Company’s outstanding Series A warrants. The warrants become dilutive for earnings (loss) per common share calculations when the market price of the Company’s common stock exceeds the exercise price. For the year ended December 31, 2018 , 129,520 stock options were excluded from the computation of dilutive earnings (loss) per share because they would have been anti-dilutive. For the year ended December 31, 2017 , 129,520 stock options and 108,657 other stock based instruments were excluded from the computation of dilutive earnings (loss) per share because they would have been anti-dilutive. These potential shares could dilute earnings (loss) per share in the future. For the period from July 26, 2016 to December 31, 2016, 248,784 stock options, 11,701 restricted stock units and 69,651 Series A warrants were excluded from the computation of dilutive earnings (loss) per share because they would have been anti-dilutive. In periods of net loss, the number of shares used to calculate diluted earnings per share is the same as basic earnings per share.

The following table presents the net income (loss) per common share for the year ended December 31, 2018 and 2017 and the period from July 26, 2016 to December 31, 2016:
Successor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Net income (loss)
Income (loss) from continuing operations
$
302,854

$
173,735

$
(11,846
)
(Loss) income from discontinued operations
(3,689
)
(19,213
)
916

Net income (loss)
$
299,165

$
154,522

$
(10,930
)
Basic
Weighted average common shares outstanding - basic
10,967,014

10,216,464

10,309,310

Basic income (loss) per common share:
Income (loss) from continuing operations
$
27.61

$
17.01

$
(1.15
)
(Loss) income from discontinued operations
(0.33
)
(1.89
)
0.09

Net income
$
27.28

$
15.12

$
(1.06
)
Diluted
Weighted average common shares outstanding - basic
10,967,014

10,216,464

10,309,310

Diluted effect of warrants
280,969

170,178

—

Diluted effect of stock options
262,714

274,456

—

Diluted effect of restricted share units and restricted stock shares
201,956

108,907

—

Weighted average common shares outstanding - diluted
11,712,653

10,770,005

10,309,310

Diluted income (loss) per common share:
Income (loss) from continuing operations
$
25.86

$
16.13

$
(1.15
)
(Loss) income from discontinued operations
(0.32
)
(1.78
)
0.09

Net income (loss)
$
25.54

$
14.35

$
(1.06
)

The Alpha Merger was completed on November 9, 2018. Refer to Note 3 for disclosures related to the Merger Agreement.


123
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

( 8 ) Inventories, net
Inventories, net consisted of the following:
December 31, 2018
December 31, 2017
Raw coal
$
33,607

$
7,003

Saleable coal
63,767

55,357

Materials, supplies and other, net
24,591

7,201

Total inventories, net
$
121,965

$
69,561


( 9 ) Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consisted of the following:
Successor
December 31,
2018
December 31,
2017
Prepaid freight
$
9,839

$
9,374

Deferred longwall move expenses
9,308

13,062

Notes and other receivables
16,116

7,406

Short-term restricted cash
16,474

11,615

Short-term deposits
16,181

12,366

Prepaid insurance
8,162

2,401

Refundable income taxes
74,536

21,175

Other prepaid expenses
8,329

6,446

Total prepaid expenses and other current assets
$
158,945

$
83,845


( 10 ) Property, Plant, and Equipment, net

Property, plant, and equipment consisted of the following:
Successor
December 31,
2018
December 31,
2017
Plant and mining equipment
$
695,756

$
153,951

Mine development
47,550

19,460

Land
38,810

10,252

Office equipment, software and other
1,169

483

Construction in progress
23,471

35,749

Total property, equipment and mine development costs
806,756

219,895

Less accumulated depreciation, depletion and amortization
106,766

39,943

Total property, plant, and equipment, net
$
699,990

$
179,952


Included in plant and mining equipment are assets under capital leases totaling $20,888 and $740 with accumulated depreciation of $1,162 and $317 as of December 31, 2018 and December 31, 2017 , respectively.
Depreciation and amortization expense associated with property, plant, equipment, and non-mineral asset retirement obligation assets, net, was $70,745 , $31,956 , $10,006 , $36,687 for the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016, respectively.

Depreciation expense for the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31,

124
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

2016 and the period from January 1, 2016 to July 25, 2016 includes an expense of $233 , credits of ($898) , ($805) , and $0 , respectively, related to revisions to asset retirement obligations. See Note 17 for further disclosures related to asset retirement obligations.

Interest costs applicable to major asset additions are capitalized during the construction period. During the years ended December 31, 2018 and December 31, 2017 interest costs of $1,352 and $1,334 , respectively, were capitalized. No interest costs were capitalized for the period from July 26, 2016 to December 31, 2016 and the period from January 1, 2016 to July 25, 2016.

As of December 31, 2018, the Company had commitments to purchase approximately $24,339 of new equipment, expected to be acquired at various dates in 2019.

( 11 ) Other Non-Current Assets
Other non-current assets consisted of the following:
Successor
December 31,
2018
December 31,
2017
Long-term deposits
$
9,211

$
3,607

Long-term restricted investments
29,137

406

Equity method investments
15,236

16,095

Federal income tax receivable
43,770

—

Workers' compensation receivables
67,776

6,038

Other
18,545

5,466

Total other non-current assets
$
183,675

$
31,612



( 12 ) Asset Impairment and Restructuring
A long-lived asset group that is held and used is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the long-lived asset or asset group might not be recoverable. For the period ended July 25, 2016, the Company recorded severance expenses and other restructuring-related charges of $955 . Of this amount, $600 was recorded on CAPP - Met and $334 was recorded on NAPP for the period ended July 25, 2016. For the period ended July 25, 2016, the Company recorded losses related to non-core property divestitures of $1,067 and $1,074 on CAPP - Met and NAPP, respectively.
There were no asset impairments or restructuring charges during the years ended December 31, 2018 and 2017 or for the period from July 26, 2016 to December 31, 2016.

( 13 ) Dividend and Stock Repurchases
2017 Dividend and Tender Offer

The Company entered into the First Amendment to the Asset-Based Revolving Credit Agreement on June 9, 2017 and the First Amendment to Term Loan Credit Agreement on June 13, 2017. The amendments, among other things, permitted an aggregate amount of $150,000 of cash to be used for the (i) payment of a one-time cash dividend on its common stock no later than July 28, 2017, and (ii) repurchase of its common stock at any time no later than December 31, 2017, subject to certain terms and conditions.

On June 16, 2017, the Company declared a special cash distribution of approximately $92,786 in the aggregate (the “Special Dividend”), payable to eligible holders of record of its common stock as of the close of business on July 5, 2017. In addition, pursuant to the terms of the Company’s management incentive plan, dividend equivalent payments of approximately $7,949 in the aggregate (including the amounts payable with respect to each share underlying outstanding stock option awards and restricted stock unit awards and outstanding restricted common stock under the Management Incentive Plan (the “MIP”))

125
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

were paid to plan participants. The dividend equivalent payments were made on July 11, 2017, and the Special Dividend was paid on July 12, 2017. Pursuant to terms of the debt amendments, the Company made an offer to all Term Loan Credit Facility lenders to repay the loans at par concurrently with the payment of the Special Dividend, in an aggregate principal amount equal to $10,000 . All the Term Loan Facility lenders accepted the offer, and the Company repaid $10,000 on July 13, 2017.

On September 15, 2017, the Company repurchased 309,310 shares of its common stock issued pursuant to awards under the MIP for a total purchase amount of $17,445 , or $56.40 per share. On September 26, 2017, the Company announced that it had commenced a modified “Dutch Auction” tender offer to repurchase up to $31,800 of common stock. On December 21, 2017, Contura repurchased an aggregate of 530,000 shares of common stock at a purchase price of $60.00 per share. The total repurchase price of $32,595 (comprised of $31,800 of share repurchases and $795 of related fees) was recorded in the fourth quarter of 2017 as treasury stock in the Consolidated Balance Sheet. Upon completion of the tender offer, provisions within the Company’s Term Loan Credit Facility and Asset-Based Revolving Credit Agreement limited the ability of the Company to make future repurchases of its common stock.

2018 Stock Repurchase Plan

The Company entered into the Amended and Restated Credit Agreement and the Amended and Restated Asset-Based Revolving Credit Agreement on November 9, 2018. These agreements, among other things, permitted an aggregate amount of $15,000 of cash to be used for the repurchase of its common stock in any twelve month period after the closing date of the agreement, subject to certain terms and conditions. On December 6, 2018, the Company announced that its Board of Directors had approved a stock repurchase plan (the “Company Repurchase Plan”) to acquire up to $15,000 in the aggregate of the company’s common stock. As of December 31, 2018, the Company had repurchased an aggregate of 223,218 shares under the plan for an aggregate purchase price of approximately $15,007 (comprised of $15,000 of share repurchases and $7 of related fees).

( 14 ) Accrued Expenses and Other Current Liabilities
Accrued expenses and other current liabilities consisted of the following:
Successor
December 31,
2018
December 31,
2017
Wages and benefits
$
51,026

$
30,408

Workers' compensation (1)
16,676

5,580

Black lung (1)
8,133

202

Taxes other than income taxes
24,140

3,478

Current portion of asset retirement obligations
24,754

6,771

Freight accrual
10,785

2,109

Other
11,834

10,223

Total accrued expenses and other current liabilities
$
147,348

$
58,771

(1) See Note 22 for further disclosures related to workers’ compensation and black lung.


126
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

( 15 ) Long-Term Debt
Long-term debt consisted of the following:
December 31, 2018
December 31, 2017
Term Loan Credit Facility - due March 2024
$
—

$
387,000

Term Loan Credit Facility - due November 2025
550,000

—

LCC Note Payable
62,500

—

LCC Water Treatment Obligation
11,875

—

Other
8,395

3,768

Debt discount and issuance costs
(44,758
)
(18,065
)
Total long-term debt
588,012

372,703

Less current portion
(42,743
)
(10,730
)
Long-term debt, net of current portion
$
545,269

$
361,973


Term Loan Credit Facility - due November 2025
On November 9, 2018, the Company entered into an Amended and Restated Credit Agreement with Jefferies Finance LLC, as administrative agent and collateral agent, and the other lenders party thereto (as defined therein) that provides for a senior secured term loan facility in the aggregate amount of $550,000 with a maturity date of November 9, 2025 (the “New Term Loan Credit Facility”). Principal repayments equal to $6,875 are due each March, June, September and December (commencing with March 31, 2019) with the final principal repayment installment repaid on the maturity date and in any event shall be in an amount equal to the aggregate principal amount outstanding as such date. The Term Loan Credit Facility bears an interest rate per annum based on the character of the loan (defined as either “Base Rate Loan” or “Eurocurrency Rate Loan”) plus an applicable rate of 4.00% to 5.00% depending on loan type (the “Applicable Rate”), payable bi-monthly in arrears. As of December 31, 2018 , the Term Loan Credit Facility was classified as a Eurocurrency Rate Loan with an interest rate of 7.39% , calculated as the eurocurrency rate during the period plus an applicable rate of 5.00% . As of December 31, 2018, the carrying value of the New Term Loan Credit Facility is $521,667 , with $20,625 classified as current, within the Consolidated Balance Sheet.
In connection with entering into the Amended and Restated Credit Agreement, the Company repaid the outstanding principal balance of $380,667 under the Credit Agreement dated March 17, 2017 and the outstanding principal balance of $82,811 under the term loan agreement dated October 23, 2017, between ANR and Cantor Fitzgerald Securities (the “Alpha Term Loan”). In connection with the Amended and Restated Credit Agreement, the Company recorded a loss on modification of debt of $9,370 , primarily related to modification fees paid under the refinance, and a loss on extinguishment of debt of $2,591 , primarily related to a prepayment premium on the Alpha Term Loan and the write-off of outstanding debt discounts under the Credit Agreement dated March 17, 2017, which are recorded in loss on modification and extinguishment of debt within the Consolidated Statements of Operations.
The New Term Loan Credit Facility contains negative and affirmative covenants including certain financial covenants. The Company was in compliance with all covenants under this agreement as of December 31, 2018 . Commencing with the fiscal quarter ended March 31, 2019, the Company must make prepayments on the term loan principal balance under the terms of the Amended and Restated Credit Agreement equal to the excess cash flow in any quarter, as defined in the agreement (the “Excess Cash Flow Payments”). Any payments shall be made no later than 70 days after the end of each fiscal quarter (or 130 days in the case of the last fiscal quarter of any fiscal year).
All obligations under the New Term Loan Credit Facility are substantially guaranteed by the Company’s existing wholly owned domestic subsidiaries, and are required to be guaranteed by the Company’s future wholly owned domestic subsidiaries. Certain obligations under the New Term Loan Credit Facility are secured by a senior lien, subject to certain exceptions (including the ABL Priority Collateral described below), by substantially all of the Company’s assets and the assets of the Company’s subsidiary guarantors (“Term Loan Priority Collateral”), in each case subject to exceptions. The obligations under the Term Loan Credit Facility are also secured by a junior lien, again subject to certain exceptions, against the ABL Priority Collateral.


127
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Term Loan Credit Facility - due March 2024
On March 17, 2017, the Company entered into a Credit Agreement with Jefferies Finance LLC, as administrative agent and collateral agent, and the other lenders party thereto (as defined therein) that provided for a term loan facility (the “Old Term Loan Credit Facility”) in an aggregate amount of $400,000 with a maturity date of March 17, 2024. Principal repayments equal to $1,000 were due each March, June, September and December (commencing with June 30, 2017) with the final principal repayment installment repaid on the maturity date and in an amount equal to the aggregate principal amount outstanding on such date. The Old Term Loan Credit Facility had an interest rate per annum based on the character of the loan (defined as either “Base Rate Loan” or “Eurocurrency Rate Loan”) plus an applicable rate of 4.00% to 5.00% depending on loan type (the “Applicable Rate”), payable bi-monthly in arrears. As of December 31, 2017, the Old Term Loan Credit Facility was classified as a Eurocurrency Rate Loan with an interest rate of 6.63% , calculated as the eurocurrency rate during the period plus an applicable rate of 5.00% . As of December 31, 2017, the carrying value of the Old Term Loan Credit Facility was $368,935 , with $7,323 classified as current, within the Consolidated Balance Sheet.

In connection with entering into the Credit Agreement, the Company paid all of its $300,000 outstanding 10.00% Senior
Secured First Lien Notes due 2021. The proceeds of the Term Loan Credit Facility were also used to repay the $42,500
outstanding Term Facility due 2020, the $8,500 outstanding Closing Tranche Term Loan due 2018 and the $5,500 outstanding
GUC Distribution Note due 2018. For the twelve months ended December 31, 2017, the Company recorded a loss on early extinguishment of debt of $38,701 , primarily related to a prepayment premium on the 10.00% Senior Secured First Lien Notes and the write-off of outstanding debt discounts on the 10.00% Senior Secured First Lien Notes and GUC Distribution Note.

The Company entered into the First Amendment to the Term Loan Credit Agreement on June 13, 2017. The amendment, among other things, permitted an aggregate amount of $150,000 of cash to be used for the (i) payment of a one-time cash dividend on its common stock no later than July 28, 2017, and (ii) repurchase of its common stock at any time no later than December 31, 2017, subject to certain terms and conditions. Pursuant to terms of the amendment, the Company made an offer to all Old Term Loan Credit Facility lenders to repay the loans at par concurrently with the payment of the Special Dividend, in an aggregate principal amount equal to $10,000 . All the Term Loan Facility lenders accepted the offer, and the Company repaid $10,000 on July 13, 2017.

All obligations under the Old Term Loan Credit Facility were unconditionally guaranteed by the Company’s existing wholly owned domestic subsidiaries, and were required to be guaranteed by the Company’s future wholly owned domestic subsidiaries. Certain obligations under the Old Term Loan Credit Facility were secured by a senior lien, subject to certain exceptions (including the ABL Priority Collateral described below), by substantially all of the Company’s assets and the assets of the Company’s subsidiary guarantors (“Old Term Loan Priority Collateral”), in each case subject to exceptions. The obligations under the Old Term Loan Credit Facility were also secured by a junior lien, again subject to certain exceptions, against the ABL Priority Collateral.

Asset-Based Revolving Credit Agreement

On November 9, 2018, the Company entered into the Amended and Restated Asset-Based Revolving Credit Agreement, with Citibank N.A. as administrative agent, collateral agent, and swingline lender and the other lenders party thereto (the “Lenders”), and Citibank N.A., Barclays Bank PLC, BMO Harris Bank N.A. and Credit Suisse AG as letter of credit issuers (“LC Lenders”). The Amended and Restated Asset-Based Revolving Credit Agreement amended and restated the Asset-Based Revolving Credit Agreement dated April 3, 2017, in its entirety, and includes a senior secured asset-based revolving credit facility (the “ABL Facility”). Under the ABL Facility, the Company may borrow cash from the Lender or cause the LC Lenders to issue letters of credit, on a revolving basis, in an aggregate amount of up to $225,000 , of which no more than $200,000 may be drawn through letters of credit. Any borrowings under the ABL Facility will have a maturity date of April 3, 2022 and will bear interest based on the character of the loan (defined as either “Base Rate Loan” or “Eurocurrency Rate Loan”) plus an applicable rate ranging from 1.00% to 1.50% for Base Rate Loans and 2.00% to 2.50% for Eurocurrency Rate Loans, depending on the amount of credit available. Any letters of credit issued under the ABL Facility will bear a commitment fee rate ranging from 0.25% to 0.375% depending on the amount of availability per terms of the agreement, and a 0.25% fronting fee payable to the ABL Facility’s administrative agent. The Amended and Restated Asset-Based Revolving Credit Agreement provides that a specified percentage of billed, unbilled and approved foreign receivables and raw and clean inventory meeting certain criteria are eligible to be counted for purposes of collateralizing the amount of financing available, subject to certain terms and conditions. The Company recorded a loss on early extinguishment of debt of $81 related to the write-off of unamortized issuance costs on the Old ABL Facility, which is recorded in loss on modification and extinguishment of debt

128
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

within the Consolidated Statements of Operations. As of December 31, 2018 , the Company had no borrowings and $28,700 letters of credit outstanding under the ABL Facility.
The Amended and Restated Asset-Based Revolving Credit Agreement, as amended, and related documents contain negative and affirmative covenants including certain financial covenants. The Company was in compliance with all covenants under these agreements as of December 31, 2018 .

The ABL Credit Facility is guaranteed by substantially all of Contura’s direct and indirect subsidiaries (together with Contura, the “Loan Parties”) and secured by all or substantially all assets of the Loan Parties, including equity in its direct domestic subsidiaries and first-tier foreign subsidiaries, as collateral for the obligations under the New ABL Credit Facility. The New ABL Credit Facility has a first lien on ABL priority collateral and a second lien on term loan priority collateral.

The Company entered into the First Amendment to the Asset-Based Revolving Credit Agreement on June 9, 2017. The amendment, among other things, permitted an aggregate amount of $150,000 of cash to be used for the (i) payment of a onetime cash dividend on its common stock no later than July 28, 2017, and (ii) repurchase of its common stock at any time no later than December 31, 2017, subject to certain terms and conditions.

On April 3, 2017, the Company entered into an Asset-Based Revolving Credit Agreement with Citibank N.A. as administrative agent, collateral agent, and swingline lender and the other lenders party thereto (the “Old Lenders”), and Citibank N.A., BMO Harris Bank N.A. and Credit Suisse AG as letter of credit issuers (“Old LC Lenders”). The Asset-Based Revolving Credit Agreement included a senior secured asset-based revolving credit facility (the “Old ABL Facility”). Under the Old ABL Facility, the Company could borrow cash from the Old Lender or cause the Old LC Lenders to issue letters of credit, on a revolving basis, in an aggregate amount of up to $125,000 , of which no more than $80,000 could be drawn through letters of credit. Any borrowings under the Old ABL Facility had a maturity date of April 4, 2022 and incurred interest based on the character of the loan (defined as either “Base Rate Loan” or “Eurocurrency Rate Loan”) plus an applicable rate ranging from 1.00% to 1.50% for Base Rate Loans and 2.00% to 2.50% for Eurocurrency Rate Loans, depending on the amount of credit that was available. Any letters of credit issued under the Old ABL Facility incurred a commitment fee rate ranging from 0.25% to 0.375% depending on the amount of availability per terms of the agreement, and a 0.25% fronting fee that was payable to the Old ABL Facility’s administrative agent. The Asset-Based Revolving Credit Agreement provided that a specified percentage of billed, unbilled and approved foreign receivables and raw and clean inventory meeting certain criteria were eligible to be counted for purposes of collateralizing the amount of financing available, subject to certain terms and conditions. As of December 31, 2017, the Company had no borrowings and $11,300 letters of credit outstanding under the Old ABL Facility.

LCC Note Payable

As a result of the Merger, the Company assumed a note payable to Lexington Coal Company (“LCC”) in the aggregate amount of $62,500 (the “LCC Note Payable”) and with a maturity date of July 26, 2022. The LCC Note Payable has no stated interest. Principal repayments equal to $17,500 are due each July during 2019, 2020 and 2021, with the final principal payment of $10,000 due on the maturity date. The carrying value of the LCC Note Payable was $49,361 within the Consolidated Balance Sheet at December 31, 2018 .

LCC Water Treatment Stipulation

As a result of the Merger, the Company assumed an obligation to contribute $12,500 into Lexington Coal Company’s water treatment restricted cash accounts (the “LCC Water Treatment Stipulation”). Contributions equal to $625 are due each January, April, July and October from 2019 through 2023. The LCC Water Treatment Stipulation has no stated interest. The carrying value of the LCC Water Treatment Stipulation was $8,589 within the Consolidated Balance Sheet at December 31, 2018 .

Capital Leases

The Company entered into capital leases for certain property and other equipment during 2018 and 2017. The Company’s liability for capital leases totaled $6,423 and $426 , with $2,110 and $226 reported within the current portion of long-term debt as of December 31, 2018 and December 31, 2017, respectively.

Future Maturities


129
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Future maturities of long-term debt as of December 31, 2018 are as follows:
2019
$
49,612

2020
49,755

2021
49,643

2022
41,260

2023
30,000

Thereafter (1)
412,500

Total long-term debt
$
632,770

(1) Includes principal payments on the Term Loan Credit Facility - due November 2025 of $27,500 and $385,000 for the years ended December 31, 2024 and 2025, respectively.

( 16 ) Acquisition-Related Obligations
Acquisition-related obligations consisted of the following:
December 31, 2018
December 31, 2017
Contingent Revenue Obligation
$
59,880

$
—

Environmental Settlement Obligations
19,306

—

Reclamation Funding Liability
22,000

32,000

Retiree Committee VEBA Funding Settlement Liability
3,500

7,000

UMWA Funds Settlement Liability
6,000

7,000

Other
—

580

Discount
(10,356
)
(11,168
)
Total acquisition-related obligations - long-term
100,330

35,412

Less current portion
(27,334
)
(15,080
)
Acquisition-related obligations, net of current portion
$
72,996

$
20,332


The Company entered into various settlement agreements with Alpha and/or the Alpha bankruptcy successor ANR and third parties as part of the Alpha bankruptcy reorganization process. The Company assumed acquisition-related obligations through those settlement agreements which became effective on July 26, 2016, the effective date of Alpha’s plan of reorganization. Additionally, as a result of the Merger the Company assumed certain acquisition-related obligations pursuant to the terms stipulated within the bankruptcy settlement previously entered into by the Alpha Companies.

Contingent Revenue Obligation

As a result of the Merger, the Company assumed a contingent revenue payment obligation (the “Contingent Revenue Obligation”) to certain of the Alpha Companies creditors pursuant to the terms stipulated within the bankruptcy settlement previously entered into by the Alpha Companies. Pursuant to terms of the obligation, the annual obligation will be limited to revenues derived from legacy operations for the Alpha Companies and will not include revenues related to legacy Contura operations or new operations acquired after the Merger. The Contingent Revenue Obligation consists of a contingent revenue payment of 1.5% of annual gross revenues of the legacy operations for the Alpha Companies up to $500,000 and 1.0% of annual gross revenue of the legacy operations for the Alpha Companies in excess of $500,000 through the period ended December 31, 2022. See Note 19 for further disclosures related to the fair value assignment and methods used. As of December 31, 2018, the carrying value of the Contingent Revenue Obligation is $59,880 , with $9,459 classified as current, all of which was classified as an acquisition-related obligation in the Consolidated Balance Sheets.

Environmental Settlement Obligations

As a result of the Merger, the Company assumed certain environmental settlement obligations (the “Environmental Settlement Obligations”) pursuant to the terms stipulated within the bankruptcy settlement previously entered into by the Alpha Companies. These obligations include payments to a third-party environmental agency and the funding of certain reclamation related projects through 2022. As of December 31, 2018, the carrying value of the Environmental Settlement Obligations is

130
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

$14,768 , net of discount of $4,538 , with $3,375 classified as current, all of which was classified as an acquisition-related obligation in the Consolidated Balance Sheets.

Reclamation Funding Agreement

Pursuant to the Reclamation Funding Agreement dated July 12, 2016, the Company must pay the aggregate amount of $50,000 into the various Restricted Cash Reclamation Accounts as follows: $8,000 immediately upon the effective date of the agreement; $10,000 on the anniversary of the effective date in each of 2017, 2018, and 2019; and $12,000 on the anniversary of the effective date in 2020. The initial $8,000 payment was paid as part of the Alpha bankruptcy settlement process and is not reflected in the cash flows of the Company for the period from July 26, 2016 to December 31, 2016. As of December 31, 2018, the carrying value of the Funding of Restricted Cash Reclamation liability is $18,106 , net of discount of $3,894 , with $10,000 classified as current, all of which was classified as an acquisition-related obligation in the Consolidated Balance Sheets.

( 17 ) Asset Retirement Obligations

The following table summarizes the changes in asset retirement obligations for the years ended December 31, 2018 and 2017:
Total asset retirement obligations at December 31, 2016
$
83,062

Accretion for the period
9,934

Sites added during the period
356

Revisions in estimated cash flows (1)
(4,419
)
Expenditures for the period
(2,567
)
Reclassification to liabilities held for sale (2)
(27,161
)
Total asset retirement obligations at December 31, 2017
$
59,205

Accretion for the period
8,961

Sites added during the period (3)
163,636

Revisions in estimated cash flows (1)
1,100

Expenditures for the period
(3,175
)
Reclassification to liabilities held for sale (2)
(1,279
)
Total asset retirement obligations at December 31, 2018
228,448

Less current portion
(24,754
)
Long-term portion
$
203,694

(1)
The revisions in estimated cash flows for the year ended December 31, 2018 were primarily comprised of ($4,753) in mine life extensions within NAPP and added reserves within CAPP - Met (of which approximately $2,140 was recorded to depreciation, depletion, and amortization), offset by $3,653 in discount rate adjustments. For the year ended December 31, 2017 the revisions in estimated cash flows were primarily comprised of ($6,360) in mine life extensions within NAPP and added reserves within CAPP - Met (of which approximately ($1,700) was recorded to depreciation, depletion, and amortization), offset by $2,744 in discount rate adjustments.
(2)
See Note 2 for further information on liabilities held for sale.
(3)
Represents amounts assumed in connection with the Merger.


131
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

( 18 ) Other Non-Current Liabilities
Other non-current liabilities consisted of the following:
Successor
December 31,
2018
December 31,
2017
Life insurance benefits
$
10,581

$
11,806

Below-market obligations, net
33,912

—

Other
7,922

5,812

Total other non-current liabilities
$
52,415

$
17,618



( 19 ) Fair Value of Financial Instruments and Fair Value Measurements
The estimated fair values of financial instruments are determined based on relevant market information. These estimates involve uncertainty and cannot be determined with precision.
The carrying amounts for cash and cash equivalents, trade accounts receivable, net, prepaid expenses and other current assets, short-term and long-term restricted cash, short-term and long-term deposits, trade accounts payable, and accrued expenses and other current liabilities approximate fair value as of December 31, 2018 and 2017 due to the short maturity of these instruments.
The following tables set forth by level, within the fair value hierarchy, the Company’s long-term debt at fair value as of December 31, 2018 and 2017 :
December 31, 2018
Carrying
Amount (1)
Total Fair
Value
Quoted Prices
in Active
Markets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Term Loan Credit Facility - due November 2025
$
521,667

$
540,375

$
540,375

$
—

$
—

LCC Note Payable
49,361

50,606

—

—

50,606

LCC Water Treatment Obligation
8,589

8,827

—

—

8,827

Total long term debt
$
579,617

$
599,808

$
540,375

$
—

$
59,433

December 31, 2017
Carrying
Amount (1)
Total Fair
Value
Quoted Prices
in Active
Markets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Term Loan Credit Facility - due March 2024
$
368,935

$
381,195

$
381,195

$
—

$
—

(1) Net of debt discounts and debt issuance costs.

The following tables set forth by level, within the fair value hierarchy, the Company’s acquisition-related obligations at fair value as of December 31, 2018 and 2017 :

132
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

December 31, 2018
Carrying
Amount (1)
Total Fair Value
Quoted Prices in Active Markets (Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant Unobservable Inputs (Level 3)
Retiree Committee VEBA Funding
Settlement Liability
$
3,337

$
3,391

$
—

$
—

$
3,391

UMWA Funds Settlement Liability
4,239

4,729

—

—

4,729

Reclamation Funding Liability
18,106

19,362

—

—

19,362

Environmental Settlement Obligations
14,768

14,936

—

—

14,936

Total acquisition-related obligations
$
40,450

$
42,418

$
—

$
—

$
42,418

December 31, 2017
Carrying
Amount (1)
Total Fair Value
Quoted Prices in Active Markets (Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant Unobservable Inputs (Level 3)
Retiree Committee VEBA Funding
Settlement Liability
$
6,290

$
6,692

$
—

$
—

$
6,692

UMWA Funds Settlement Liability
4,366

5,654

—

—

5,654

Reclamation Funding Liability
24,176

28,365

—

—

28,365

Total acquisition-related obligations
$
34,832

$
40,711

$
—

$
—

$
40,711

(1) Net of discounts.

The following table sets forth by level, within the fair value hierarchy, the Company’s financial and non-financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2018 and December 31, 2017. Financial and non-financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the determination of fair value for assets and liabilities and their placement within the fair value hierarchy levels.

December 31, 2018
Total Fair Value
Quoted Prices in Active Markets (Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant Unobservable Inputs (Level 3)
Contingent Revenue Obligation
$
59,880

$
—

$
—

$
59,880


The following table is a reconciliation of the financial and non-financial assets and liabilities that were accounted for at fair value on a recurring basis and that were categorized within Level 3 of the fair value hierarchy:

December 31, 2017
Acquisitions
Loss (Gain) Recognized in Earnings
Transfer In (Out) of Level 3 Fair Value Hierarchy
December 31, 2018
Contingent Revenue Obligation
$
—

$
59,856

$
24

$
—

$
59,880


For the twelve months ended December 31, 2018, the Company fair valued assets and liabilities on a non-recurring basis in connection with acquisition accounting (see Note 3 ).

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the tables above:

133
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Level 1 Fair Value Measurements
Term Loan Credit Facility - due March 2024 - The fair value is based on observable market data.

Term Loan Credit Facility - due November 2025 - The fair value is based on observable market data.

Level 3 Fair Value Measurements

LCC Note Payable, LCC Water Treatment Obligation, Retiree Committee VEBA Funding Settlement Liability, UMWA Funds Settlement Liability, Environmental Settlement Obligations and Reclamation Funding Liability - Observable transactions are not available to aid in determining the fair value of these items. Therefore, the fair value was derived by using the expected present value approach in which estimated cash flows are discounted using a risk-free interest rate adjusted for market risk.

Contingent Revenue Obligation - The fair value of the contingent revenue obligation was estimated using a Black-Scholes pricing model and is marked to market at each reporting period with changes in value reflected in earnings. The inputs included in the Black-Scholes pricing model are the Company's forecasted future revenue, the stated royalty rate, the remaining periods in the obligation; annual risk-free interest rate based on the US Constant Maturity Treasury Curve and annualized volatility. The annualized volatility was calculated by observing volatilities for comparable companies with adjustments for the Company's size and leverage.

Acquisition accounting - The Company accounts for business combinations under the acquisition method of accounting. The total cost of acquisitions is allocated to the underlying identifiable net tangible and intangible assets based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, the utilization of independent valuation experts and often involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. A combination of income, market and cost approaches are used for the valuation where appropriate, depending on the assets or liabilities being valued. The valuation inputs in these models and analyses give consideration to market participant assumptions.

( 20 ) Warrants
On July 26, 2016 (the “Initial Issue Date”), the Company issued 810,811 warrants, each with an initial Exercise Price, as defined in the Series A Warrants Agreement (the “Warrants Agreement”), of $55.93 per share of common stock and exercisable for one share of the Company’s common stock, par value $0.01 per share. Pursuant to the Warrants Agreement dated as of July 26, 2016, no fractional shares shall be issued upon warrant exercises. The warrants are exercisable for cash or on a cashless basis at any time from the Initial Issue Date until July 26, 2023.
Pursuant to the Warrants Agreement dated as of July 26, 2016, the Exercise Price and the Warrant Share Number, as defined in the Warrants Agreement, were adjusted as a result of the occurrence of the Special Dividend. The Warrant Share Number was adjusted from 1.00 to 1.15 , and the Exercise Price was adjusted from $55.93 per share to $48.741 per share as of the July 5, 2017 record date.

The United States Bankruptcy Court for the Eastern District of Virginia issued an order and final decree on June 28, 2018, granting a motion to close the Chapter 11 case of Alpha Natural Resources, Inc. and its affiliates, as reorganized debtors (the “Reorganized Debtors”), and authorizing the Reorganized Debtors to make a distribution (the “Distribution”) of additional cash as defined in the Warrants Agreement. The Distribution was effected on October 26, 2018 (the “Distribution Date”) in the aggregate amount of approximately $18,350 . Pursuant to the Warrants Agreement dated as of July 26, 2016, the Exercise Price was adjusted as a result of the occurrence of the Distribution. The Exercise Price was adjusted from $48.741 per share to $46.911 per share as of the Distribution Date. The Warrant Share Number remains equal to 1.15 .

As of December 31, 2018 , of the 810,811 warrants that were originally issued, 801,730 remain outstanding, with a total of 921,990 shares underlying the un-exercised warrants. For the year ended December 31, 2018 , the Company issued 325 shares of common stock resulting from exercises of its Series A Warrants, and, pursuant to the terms of the Warrants Agreement, withheld 125 of the issued shares in satisfaction of the Warrant Exercise Price, which were subsequently reclassified as treasury stock.


134
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

( 21 ) Income Taxes

In the Predecessor periods, the Predecessor was included in Alpha's consolidated federal income tax return and consolidated and combined income tax returns in certain states. For purposes of these Consolidated Financial Statements, income taxes related to the Predecessor are presented as if it were a separate taxpayer for the Predecessor period. Therefore, the calculated amount of federal and state current income taxes differs from amounts previously recorded and paid by the Parent on behalf of Contura.
Total income tax expense (benefit) provided on income before income taxes was allocated as follows:
Successor
Predecessor
Year Ended December 31,
2018
Year Ended December 31,
2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Continuing operations
$
(165,363
)
$
(67,979
)
$
(1,920
)
$
(39,881
)
Discontinued operations
(1,305
)
(17,681
)
551

4,992

Total
$
(166,668
)
$
(85,660
)
$
(1,369
)
$
(34,889
)
Significant components of income tax expense (benefit) from continuing operations were as follows:
Successor
Predecessor
Year Ended December 31,
2018
Year Ended December 31,
2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Current tax (benefit) expense:
Federal
$
(99,965
)
$
10,078

$
(390
)
$
—

State
(21
)
687

180

—

Total current
$
(99,986
)
$
10,765

$
(210
)
$
—

Deferred tax (benefit) expense:
Federal
$
(49,322
)
$
(78,744
)
$
(1,628
)
$
(29,961
)
State
(16,055
)
—

(82
)
(9,920
)
Total deferred
$
(65,377
)
$
(78,744
)
$
(1,710
)
$
(39,881
)
Total income tax (benefit) expense:
Federal
$
(149,287
)
$
(68,666
)
$
(2,018
)
$
(29,961
)
State
(16,076
)
687

98

(9,920
)
Total
$
(165,363
)
$
(67,979
)
$
(1,920
)
$
(39,881
)

135
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

A reconciliation of statutory federal income tax expense (benefit) on income from continuing operations to the actual income tax expense (benefit) is as follows:
Successor
Predecessor
Year Ended December 31,
2018
Year Ended December 31,
2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Federal statutory income tax expense (benefit)
$
28,873

$
37,015

$
(4,818
)
$
(35,497
)
Increase (reductions) in taxes due to:
Percentage depletion allowance
(3,770
)
(5,164
)
(1,096
)
(5,209
)
Federal tax rate change
—

179,825

—

—

SAB 118 finalization
(6,735
)
—

—

—

Estimated sequestration impact
(7,139
)
5,640

—

—

State taxes, net of federal tax impact
6,569

1,059

(226
)
(1,365
)
State tax rate and NOL change, net of federal tax impact
(4,779
)
(4,705
)
—

(5,151
)
Change in valuation allowances
(208,474
)
(280,094
)
(8,950
)
69

Net operating loss carryback
(59,404
)
—

—

—

Amended return - capital loss impact
69,430

—

—

—

Non-taxable bargain purchase gain
—

(354
)
(2,702
)
—

Non-deductible mark-to-market adjustment - warrant derivative
—

—

11,891

—

Non-deductible transaction costs
1,706

—

—

6,962

Stock-based compensation
(687
)
(1,144
)
—

—

Charitable contribution carryforward expiration
9,634

—

3,537

—

Provision to return adjustment
5,022

—

—

—

Other, net
4,391

(57
)
444

310

Income tax benefit
$
(165,363
)
$
(67,979
)
$
(1,920
)
$
(39,881
)

136
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Deferred income taxes result from temporary differences between the reporting of amounts for financial statement purposes and income tax purposes. The net deferred tax assets and liabilities included in the Balance Sheet include the following amounts:
Successor
Year Ended December 31,
2018
Year Ended December 31,
2017
Deferred tax assets:
Property, plant and mineral reserves
$
—

$
65,618

Asset retirement obligations
59,973

19,365

Reserves and accruals not currently deductible
9,163

8,362

Workers’ compensation benefit obligations
56,859

12,502

Pension obligations
47,256

—

Equity method investments
3,506

3,176

Charitable contribution carryforwards
724

11,312

Alternative minimum tax credit carryforwards
68,774

78,744

Loss carryforwards, net of Section 382 limitation
109,850

175,846

Acquisition-related obligations
25,590

7,383

Other
11,909

6,022

Gross deferred tax assets
393,604

388,330

Less valuation allowance
(94,802
)
(298,892
)
Deferred tax assets
$
298,802

$
89,438

Deferred tax liabilities:
Property, plant and mineral reserves
$
(189,232
)
$
—

Acquired intangibles, net
(31,540
)
(4,273
)
Prepaid expenses
(6,882
)
(5,186
)
Restricted cash
(55,112
)
—

Other
(3,975
)
(1,235
)
Total deferred tax liabilities
(286,741
)
(10,694
)
Net deferred tax assets
$
12,061

$
78,744

Changes in the valuation allowance were as follows:
Successor
Predecessor
Year Ended December 31,
2018
Year Ended December 31,
2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Valuation allowance beginning of period
$
298,892

$
531,054

$
539,856

$
153

(Decrease) increase in valuation allowance recorded to income tax expense (benefit)
(208,474
)
(288,177
)
(8,802
)
3,143

Increase in valuation allowance not affecting income tax expense
4,384

56,015

—

—

Valuation allowance end of period
$
94,802

$
298,892

$
531,054

$
3,296

On December 22, 2017, President Trump signed into law legislation commonly referred to as the “Tax Cuts and Jobs Act” (“TCJA”). Effective for tax years beginning after December 31, 2017, the TCJA reduced the corporate income tax rate from 35% to 21%. As a result of the reduction in the corporate income tax rate, the Company recorded a reduction to the value of its net deferred tax assets before the valuation allowance of $179,825 , resulting in an offsetting release in the valuation

137
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

allowance of $179,825 , during the year ended December 31, 2017. The TCJA also repealed the corporate alternative minimum tax (“AMT”), provided a mechanism for corporations to monetize alternative minimum tax credits (“AMT Credits”) during the 2018 to 2021 tax years, and made changes to net operating loss provisions (“NOL”) to repeal NOL carrybacks, allow NOLs to be carried forward indefinitely, and limit the utilization of an NOL carryforward to 80% of taxable income generated. The changes to the NOL provisions apply to NOLs generated in 2018 and future tax years.
During the one-year measurement period ended December 22, 2018, the Company finalized its accounting for the AMT Credits under SAB 118, resulting in the recording of an income tax benefit of $6,735 . Based on the accounting policy election made, the Company classifies the AMT Credits as a deferred tax asset until the taxable year in which the credit can be claimed on the tax return. In that year, the Company reclassifies the amount from a deferred tax asset to an income tax receivable. As of December 31, 2018, the Company recorded a current income tax receivable of $68,774 for AMT Credits expected to be refunded on the 2018 tax return. The remaining $68,774 of AMT Credits are recorded as a deferred tax asset and a $10,529 valuation allowance is recorded against the deferred tax asset. The Internal Revenue Service (“IRS”) may issue additional guidance in the form of regulations or notices regarding certain technical issues related to the monetization of the AMT Credits.
The Company acquired the core assets of Alpha as part of the Alpha Restructuring in transactions intended to be treated as a tax-free reorganization for U.S. federal income tax purposes. As a result of these transactions, the Company inherited the tax basis of the core assets and the net operating loss and other carryforwards of Alpha. On December 31, 2016, the net operating loss carryforwards and other carryforwards were reduced under Internal Revenue Code Section 108 due to the cancellation of indebtedness resulting from the Alpha Restructuring. Due to the change in ownership, the net operating loss and other carryforwards inherited in the Alpha Restructuring are subjected to significant limitations on their use in future years.
Due to the Company’s formation through acquisition of certain core coal assets as part of the Alpha Restructuring, the Company does not have a long history of operating results. Additionally, significant ownership change limitations limit the ability of the Company to utilize its net operating loss and other carryforwards in future years. The Company currently is relying primarily on the reversal of taxable temporary differences, along with consideration of taxable income via carryback to prior years and tax planning strategies, to support the realization of deferred tax assets. The Company assesses the realizability of its deferred tax assets, including scheduling the reversal of its deferred tax liabilities, to determine the amount of valuation allowance needed. Scheduling the reversal of deferred tax asset and liability balances requires judgment and estimation. The Company believes the deferred tax liabilities relied upon as future taxable income in its assessment will reverse in the same period and jurisdiction and are of the same character as temporary differences giving rise to the deferred tax assets that will be realized. The valuation allowance recorded represents the portion of deferred tax assets for which the Company is unable to support realization through the methods described above. The Company has concluded that it is more likely than not that the remaining deferred tax assets, net of valuation allowances, are realizable.
At December 31, 2018 , the Company has regular tax net operating loss carryforwards for Federal income tax purposes of approximately $1,374,000 . This includes $1,002,000 that are available to offset regular Federal taxable income subject to an annual Internal Revenue Code Section 382 limitation of approximately $1,000 , $62,000 that are subject to an annual Section 382 limitation of approximately $18,300 , $305,000 that are expected to be subject to an annual Section 382 limitation of approximately $17,500 , and $5,000 of current year and carryover charitable contributions that converted to a net operating loss. The Federal net operating loss carryforwards will expire between years 2030 and 2037. The Company has capital loss carryforwards of approximately $126,000 , of which $71,000 are subject to an annual Section 382 limitation of approximately $1,000 and $55,000 are expected to be subject to an annual Section 382 limitation of approximately $17,500 . The capital loss carryforwards will expire between years 2021 and 2022. A full valuation allowance is recorded against the capital loss carryforwards. The Company also has charitable contribution carryforwards of $3,447 , which will expire between years 2019 and 2022.
The Company does not have any unrecognized tax benefits. The Company’s policy is to classify interest and penalties related to uncertain tax positions as part of income tax expense. As of December 31, 2018 and 2017 , the Company had no accrued interest and penalties.
As of December 31, 2018 , tax years 2015 - 2018, which include the impact of net operating loss and other carryforwards and tax basis acquired from Alpha, remain open to federal and state examination.

138
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

( 22 ) Employee Benefit Plans
The Company provides several types of benefits for its employees, including postemployment life insurance, defined benefit and defined contribution pension plans, and workers’ compensation and black lung benefits. The Company does not participate in any multi-employer plans.
Postemployment Health Care and Life Insurance, Defined Benefit and Defined Contribution Pension Plans (“Pension and Postretirement”)
In the Predecessor period, certain of the Company’s employees participated in plans sponsored by Alpha. Alpha managed its pension and postretirement benefit plans on a combined basis, and claims data and liability information related to the Company are aggregated and combined, by plan, with those related to other Alpha businesses. As a result, no pension and postretirement assets or liabilities are included in the Balance Sheets during the prior year Successor period as a result of the acquisition from Alpha and pension and postretirement expenses have been recorded on a multi-employer plan basis for the Predecessor period.
Alpha’s employee pension costs and obligations are developed from actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, salary growth, long-term return on plan assets, retirement rates, mortality rates, and other factors. The selection of assumptions is based on historical trends and known economic and market conditions at the time of valuation, as well as independent studies of trends performed by actuaries. However, actual results may differ substantially from the estimates that were based on the critical assumptions. The Company used a December 31 measurement date for all of the plans. Actual results that differ from the Company’s assumptions are accumulated and amortized over future periods and, therefore, generally affect its recognized expense in such future periods. While management believes that the assumptions used are appropriate, significant differences in actual experience or significant changes in assumptions would affect the Company’s pension costs and obligations. The Company recognized $19,476 in expenses related to these allocations from Alpha during the period from January 1, 2016 to July 25, 2016, which are reflected in continuing and discontinued operations in the Combined Statements of Operations. These expenses are part of the Alpha allocations described in the basis of presentation portion of Note 1 .
Company Administered Defined Benefit Pension Plans
In connection with the Merger, the Company assumed three qualified non-contributory defined benefit pension plans, which cover certain salaried and non-union hourly employees. Participants accrued benefits either based on certain formulas, the participant’s compensation prior to retirement or plan specified amounts for each year of service with the Company. Benefits are frozen under these plans. The qualified non-contributory defined benefit pension plans are collectively referred to as the “Pension Plans.”
Annual funding contributions to the Pension Plans are made as recommended by consulting actuaries based upon the ERISA funding standards. Plan assets consist of equity and fixed income funds, private equity funds and a guaranteed insurance contract.

139
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

The following tables set forth the plans’ accumulated benefit obligations, fair value of plan assets and funded status. The change in benefit obligations and change in fair value of plan assets represents activity related to the post-Merger period.
Successor
Year Ended
December 31, 2018
Change in benefit obligations:
Accumulated benefit obligation at beginning of period:
$
—

Interest cost
4,500

Actuarial loss
22,410

Benefits paid
(5,295
)
Acquisition
653,867

Accumulated benefit obligation at end of period
$
675,482

Change in fair value of plan assets:
Fair value of plan assets at beginning of period
$
—

Actual return on plan assets
4,112

Benefits paid
(5,295
)
Acquisition
495,863

Fair value of plan assets at end of period
$
494,680

Funded status
$
(180,802
)
Accrued benefit cost at end of period (1)
$
(180,802
)
(1) Amount is classified as long-term on the Company’s Balance Sheets.

Gross amounts related to pension obligations recognized in accumulated other comprehensive (income) loss consisted of the following as of December 31, 2018:
Successor
December 31, 2018
Net actuarial loss
$
23,075

The following table details the components of net periodic benefit cost (credit):
Successor
Year Ended December 31, 2018
Interest cost
$
4,500

Expected return on plan assets
(4,777
)
Net periodic benefit credit
$
(277
)

140
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss are as follows:
Successor
Year Ended
December 31, 2018
Current year actuarial loss
$
23,075

Total recognized in other comprehensive loss
23,075

Total recognized in net periodic benefit credit and other comprehensive loss
$
22,798


The following table presents information applicable to plans with accumulated benefit obligations in excess of plan assets:
Successor
December 31, 2018
Projected benefit obligation
$
675,482

Accumulated benefit obligation
$
675,482

Fair value of plan assets
$
494,680

The current portion of the Company’s Pension Plans liability is the amount by which the actuarial present value of benefits included in the benefit obligation payable in the next twelve months exceeds the fair value of plan assets. However, even though the plan may be underfunded, if there are sufficient plan assets to make expected benefit payments to plan participants in the succeeding twelve months, no current liability is recognized. Under this standard, no current pension liability would be presented.
The weighted-average actuarial assumption used in determining the benefit obligations as of December 31, 2018 was as follows:
Successor
December 31, 2018
Discount rate
4.33
%
The weighted-average actuarial assumptions used to determine net periodic benefit cost for the year ended December 31, 2018 were as follows:
Successor
Year Ended December 31, 2018
Discount rate for benefit obligation
4.50
%
Discount rate for interest cost
4.23
%
Expected return on plan assets
5.80
%
The discount rate assumptions were determined from a high-quality corporate bond yield-curve timing of the Company’s projected cash out flows.
The expected long-term return on assets of the Pension Plans is established each year by the Company’s Benefits Committee in consultation with the plans’ actuaries and outside investment advisors. This rate is determined by taking into consideration the Pension Plans’ target asset allocation, expected long-term rates of return on each major asset class by reference to long-term historic ranges, inflation assumptions and the expected additional value from active management of the Pension Plans’ assets. For the determination of net periodic benefit cost in 2019, the Company will utilize an expected long-term return on plan assets of 5.80% .

141
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Assets of the Pension Plans are held in trusts and are invested in accordance with investment guidelines that have been established by the Company’s Benefits Committee in consultation with outside investment advisors. The target allocation for 2019 and the actual asset allocation as reported at December 31, 2018 are as follows:
Target Allocation Percentages 2019
Percentage of Plan Assets 2018
Equity funds
40
%
40
%
Fixed income funds
60
%
57
%
Other types of investments
—
%
3
%
Total
100
%
100
%
The asset allocation targets have been set with the expectation that the Pension Plans’ assets will fund the expected liabilities within an appropriate level of risk. In determining the appropriate target asset allocations, the Benefits Committee considers the demographics of the Pension Plans’ participants, the funding status of each plan, the Company’s contribution philosophy, the Company’s business and financial profile and other associated risk factors. The Pension Plans’ assets are periodically rebalanced among the major asset categories to maintain the asset allocation within a specified range of the target allocation percentage.
For the year ended December 31, 2018, $0 of cash contributions were made to the Pension Plans. The Company expects to contribute $6,397 to the Pension Plans in 2019.
The following represents expected future pension benefit payments for the next ten years:
2019
$
30,019

2020
30,488

2021
31,139

2022
32,146

2023
32,942

2024-2028
170,545

$
327,279


142
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

The fair values of the Company’s Pension Plans’ assets as of December 31, 2018, by asset category are as follows:
Asset Category
Total
Quoted Market Prices in Active Market for Identical Assets (Level 1)
Significant Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
Equity securities:
Multi-asset fund (1)
$
195,278

$
—

$
195,278

$
—

Fixed income funds:
Bond fund (2)
283,517

—

283,517

—

Commingled short-term fund (3)
1,654

1,654

—

—

Other types of investments:
Guaranteed insurance contract
10,886

—

—

10,886

Total
$
491,335

$
1,654

$
478,795

$
10,886

Receivable (4)
921

Total assets at fair value
492,256

Private equity funds measured at net asset value practical expedient (5)
2,424

Total plan assets
$
494,680

(1) This fund contains equities (domestic and international), real estate and bonds.
(2) This fund contains bonds representing a diversity of sectors and maturities. This fund also includes mortgage-backed securities and U.S. Treasuries.
(3) This fund contains cash and highly liquid short-term investments in a collective investment fund.
(4) Receivable for investments sold at December 31, 2018, which approximates fair value.
(5) In accordance with Accounting Standards Update 2015-07, investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the total value of assets of the plans.

Changes in Level 3 plan assets for the period ended December 31, 2018 were as follows:
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Guaranteed Insurance Contract
Beginning balance, December 31, 2017
$
—

Acquisition
11,266

Actual return on plan assets:
Relating to assets still held at the reporting date
11

Purchases, sales and settlements
(391
)
Ending balance, December 31, 2018
$
10,886

The following is a description of the valuation methodologies used for assets measured at fair value:
Level 1 Plan Assets: Assets consist of individual security positions that are easily traded on recognized market exchanges. These securities are priced and traded daily, and therefore the fund is valued daily.
Level 2 Plan Assets: Funds consist of individual security positions that are mostly securities easily traded on recognized market exchanges. These securities are priced and traded daily, and therefore the fund is valued daily.
Level 3 Plan Assets: Assets are valued monthly or quarterly based on the Market Value provided by managers of the underlying fund investments. The Market Value provided typically reflects the fair value of each underlying fund investment, including unrealized gains and losses.

143
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)


Workers’ Compensation and Pneumoconiosis (Black lung)
In March 2010, the Patient Protection and Affordable Care Act (“PPACA”) was enacted, potentially impacting the Company’s costs of providing healthcare benefits to its employees and workers’ compensation benefits related to occupational disease resulting from coal workers’ pneumoconiosis (black lung disease). The PPACA has both short-term and long-term implications on benefit plan standards. Implementation of this legislation is expected to extend through 2020. In the short term, the Company’s healthcare costs could increase due to, among other things, an increase in the maximum age for covered dependents to receive benefits, changes to benefits for occupational disease related illnesses, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual. In the long term, the Company’s healthcare costs could increase due to, among other things, an excise tax on “high cost” plans and the elimination of annual dollar limits per covered individual.
Beginning in 2022, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. The Company anticipates that certain government agencies will provide additional regulations or interpretations concerning the application of this excise tax. The Company will continue to evaluate the impact of the PPACA, including any new regulations or interpretations.
The Company is required by federal and state statutes to provide benefits to employees for awards related to workers’ compensation and black lung.
In connection with the Merger, the Company assumed various workers’ compensation and black lung obligations. Subsequent to the Merger, the Company’s subsidiaries are insured for worker’s compensation and black lung obligations by a third-party insurance provider with the exception of certain subsidiaries in which the Company is a qualified self-insurer for workers’ compensation and/or black lung related obligations. Certain of the Company’s subsidiaries are self-insured for black lung benefits and may fund benefit payments through a Section 501(c) (21) tax-exempt trust fund.
Pursuant to the Merger Agreement, the Company assumed a reinsurance contract with a third party. In 2017, the Alpha Companies made a lump sum payment in exchange for the reinsurance company’s agreement to administer and pay certain future workers compensation and state black lung obligations in the state of Kentucky. Pursuant to the Merger Agreement, the Company assumed the estimated liability for these future claims. As the liabilities are paid by the insurance company, the prepaid insurance amounts will be reduced by a corresponding amount.

Starting July 26, 2016 through November 8, 2018, the Company’s subsidiaries were primarily insured with a high deductible plan for workers’ compensation and black lung obligations by a third-party insurance provider, except for an immaterial employee population where the Company was a qualified self-insurer for workers’ compensation obligations, and the Company’s discontinued operations in Wyoming, where the Company participated in a compulsory state-run fund for workers’ compensation.

For the period prior to July 26, 2016, the Company’s subsidiaries were insured for worker’s compensation and black lung obligations by a third-party insurance provider with the exception of certain subsidiaries where the Company was a qualified self-insurer for workers’ compensation and/or black lung related obligations, and with the exception of the discontinued operations in Wyoming where the Company participated in a compulsory state-run fund for workers’ compensation obligations. Prior to July 26, 2016, certain of the Company’s subsidiaries were self-insured for black lung benefits and could fund benefit payments through an existing Section 501(c)(21) tax-exempt trust fund.

The Company accrues for workers’ compensation liability by recognizing costs when it is probable that a covered liability has been incurred and the cost can be reasonably estimated. The Company’s estimates of these costs are adjusted based upon actuarial studies and include a provision for incurred but not reported losses. Actual losses may differ from these estimates, which could increase or decrease the Company’s costs. Additionally, the liability for black lung benefits is estimated by an independent actuary by prorating the accrual of actuarially projected benefits over the employee’s applicable term of service. Adjustments to the probable ultimate liability for workers’ compensation and black lung are made annually based on actuarial valuations.

At December 31, 2018 , the Company had $181,989 of workers’ compensation liability, including a current portion of $16,676 recorded in accrued expenses and other current liabilities, offset by $2,661 and $67,776 of expected insurance

144
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

receivable recorded in prepaid expenses and other current assets and other non-current assets, respectively in the Consolidated Balance Sheets. At December 31, 2017 , the Company had $29,199 of workers’ compensation liability, including a current portion of $5,580 recorded in accrued expenses and other current liabilities, offset by $6,038 of expected insurance receivable recorded in other non-current assets in the Consolidated Balance Sheets.
Self-insured workers’ compensation expense for the period from January 1, 2016 to July 25, 2016 was $281 . Certain of the Company’s subsidiaries’ self-insured workers’ compensation obligations were secured by letters of credit in the amount of $4,190 for the period from January 1, 2016 to July 25, 2016.
For the Company’s subsidiaries that are insured with a high-deductible insurance plan for workers’ compensation and black lung claims, the insurance premium expense for the years ended December 31, 2018 and 2017 , the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016 was $5,868 , $4,948 , $2,099 , and $1,037 , respectively.
Workers’ compensation expense for high-deductible insurance plans for the years ended December 31, 2018 and 2017 , the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016 was $7,953 , $9,366 , $2,085 , and $7,282 , respectively.
The following tables set forth the accumulated black lung benefit obligations, fair value of plan assets and funded status for the years ended December 31, 2018 and 2017 :
Successor
Year Ended December 31, 2018
Year Ended December 31, 2017
Change in benefit obligation:
Accumulated benefit obligation at beginning of period
$
18,370

$
13,501

Service cost
930

651

Interest cost
1,185

633

Actuarial loss
272

3,661

Benefits paid
(1,462
)
(76
)
Acquisition
75,510

—

Accumulated benefit obligation at end of period
$
94,805

$
18,370

Change in fair value of plan assets:
Fair value of plan assets at beginning of period
$
—

$
—

Actual return on plan assets
28

—

Benefits paid
(1,462
)
(76
)
Employer contributions
1,462

76

Acquisition
2,569

—

Fair value of plan assets at end of period (1)
2,597

—

Funded status
$
(92,208
)
$
(18,370
)
Accrued benefit cost at end of period
$
(92,208
)
$
(18,370
)
Summary of accrued benefit cost at end of period:
Continuing operations
(92,114
)
(18,241
)
Discontinued operations
(94
)
(129
)
Total accrued benefit cost at end of period
$
(92,208
)
$
(18,370
)

(1) Assets of the plan are held in a Section 501(c)(21) tax-exempt trust fund and consist primarily of government debt securities. All assets are classified as Level 1 and valued based on quoted market prices.


145
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

The table below presents amounts recognized in the Balance Sheets:
Successor
December 31, 2018
December 31, 2017
Current liabilities
$
8,133

$
202

Long-term liabilities
83,981

18,039

Long-term liabilities - discontinued operations
94

129

$
92,208

$
18,370

Gross amounts related to the black lung obligations recognized in accumulated other comprehensive (income) loss consisted of the following as of December 31, 2018 and 2017 :
Successor
December 31, 2018
December 31, 2017
Net actuarial loss
$
1,684

$
1,628

Accumulated other comprehensive loss
$
1,684

$
1,628

The following table details the components of the net periodic benefit cost for black lung obligations:
Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Service cost
$
930

$
651

$
300

$
353

Interest cost
1,185

633

225

703

Expected return on plan assets
(11
)
—

—

(27
)
Amortization of net actuarial loss (gain)
199

(149
)
—

206

Amortization of prior service cost
—

—

—

824

Curtailment loss
—

—

—

2,712

Net periodic expense
$
2,303

$
1,135

$
525

$
4,771

Summary net periodic expense:
Continuing operations
$
2,304

$
1,125

$
521

$
4,639

Discontinued operations
(1
)
10

4

132

Total net periodic expense
$
2,303

$
1,135

$
525

$
4,771


146
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Other changes in the black lung plan assets and benefit obligations recognized in other comprehensive (income) loss are as follows:
Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Actuarial loss (gain)
$
255

$
3,661

$
(2,182
)
$
3,415

Amortization of net actuarial (loss) gain
(199
)
149

—

(206
)
Amortization of prior service cost
—

—

—

(824
)
Curtailment gain
—

—

—

(2,712
)
Total recognized in other comprehensive loss (income)
$
56

$
3,810

$
(2,182
)
$
(327
)
Total recognized in net periodic benefit cost and other comprehensive loss (income)
$
2,359

$
4,945

$
(1,657
)
$
4,444

The weighted-average assumptions related to black lung obligations used to determine the benefit obligation as of December 31, 2018 and 2017 were as follows:
Successor
December 31, 2018
December 31, 2017
Discount rate
4.36
%
3.71
%
Federal black lung benefit trend rate
2.50
%
2.50
%
Black lung medical benefit trend rate
5.00
%
5.00
%
Black lung benefit expense inflation rate
2.50
%
2.50
%
The weighted-average assumptions related to black lung obligations used to determine net periodic benefit cost were as follows:
Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Discount rate for benefit obligation
4.37
%
4.29
%
3.62
%
3.90
%
Discount rate for service cost
3.90
%
4.32
%
3.66
%
N/A

Discount rate for interest cost
3.83
%
4.20
%
3.49
%
N/A

Federal black lung benefit trend rate
2.50
%
2.50
%
2.50
%
3.00
%
Black lung medical benefit trend rate
5.00
%
5.00
%
5.00
%
N/A

Black lung benefit expense inflation rate
2.50
%
2.50
%
2.50
%
N/A

Expected return on plan assets
2.50
%
N/A

N/A

2.50
%

147
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Estimated future cash payments related to black lung obligations for the next 10 years ending after December 31, 2018 are as follows:
Year ending December 31:
2019
$
8,133

2020
6,018

2021
6,105

2022
6,496

2023
6,630

2024-2028
16,386

$
49,768

Life Insurance Benefits
As part of the Alpha Restructuring and the Retiree Committee Settlement Agreement, the Company assumed the liability for life insurance benefits for certain disabled and non-union retired employees. Provisions are made for estimated benefits and adjustments to the probable ultimate liabilities are made annually based on an actuarial study prepared by independent actuaries. These obligations are included in the Consolidated Balance Sheet as accrued expenses and other current liabilities and other non-current liabilities. The Company had $11,368 and $12,640 of life insurance benefits liability related to obligations assumed in the acquisition at December 31, 2018 and 2017 , respectively.
The following tables set forth the accumulated life insurance benefit obligations, fair value of plan assets and funded status for the years ended December 31, 2018 and 2017 :
Successor
December 31, 2018
December 31, 2017
Change in benefit obligation:
Accumulated benefit obligation at beginning of period
$
12,640

$
12,553

Interest cost
388

406

Actuarial (gain) loss
(1,164
)
171

Benefits paid
(496
)
(490
)
Accumulated benefit obligation at end of period
$
11,368

$
12,640

Change in fair value of plan assets:
Benefits paid (1)
(496
)
(490
)
Employer contributions (1)
496

490

Fair value of plan assets at end of period
$
—

$
—

Funded status
(11,368
)
(12,640
)
Accrued benefit cost at end of year
$
(11,368
)
$
(12,640
)
Amounts recognized in the consolidated balance sheets:
Current liabilities
$
787

$
834

Long-term liabilities
10,581

11,806

$
11,368

$
12,640


(1)
Amount is comprised of premium payments to commercial life insurance provider.


148
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Gross amounts related to the life insurance benefit obligations recognized in accumulated other comprehensive income consisted of the following as of December 31, 2018 and 2017 :
Successor
December 31, 2018
December 31, 2017
Net actuarial gain
$
(1,979
)
$
(861
)
Accumulated other comprehensive income
$
(1,979
)
$
(861
)
The following table details the components of the net periodic benefit cost for life insurance benefit obligations:
Successor
Year Ended December 31, 2018
Year Ended December 31, 2017
Interest cost
$
388

$
406

Amortization of net actuarial gain
(46
)
(54
)
Net periodic expense
$
342

$
352

Other changes in the life insurance plan assets and benefit obligations recognized in other comprehensive income (loss) are as follows:
Successor
Year Ended December 31, 2018
Year Ended December 31, 2017
Actuarial (gain) loss
$
(1,164
)
$
171

Amortization of net actuarial gain
46

54

Total recognized in other comprehensive (loss) income
$
(1,118
)
$
225

The weighted-average assumptions related to life insurance benefit obligations used to determine the benefit obligation as of December 31, 2018 and 2017 was as follows:
Successor
2018
2017
Discount rate
4.21
%
3.56
%
The weighted-average assumptions related to life insurance benefit obligations used to determine net periodic benefit cost were as follows:
Successor
Year Ended December 31, 2018
Year Ended December 31, 2017
Discount rate for benefit obligations
3.56
%
4.03
%
Discount rate for interest cost
3.18
%
3.18
%

149
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Estimated future cash payments related to life insurance benefit obligations for the next 10 years ending after December 31, 2018 are as follows:
Year ending December 31:
2019
$
787

2020
696

2021
683

2022
674

2023
666

2024-2028
3,272

$
6,778

Defined Contribution and Profit Sharing Plans

The Company sponsors defined contribution plans to assist its eligible employees in providing for retirement. Generally, under the terms of these plans, employees make voluntary contributions through payroll deductions and the Company makes matching and/or discretionary contributions, as defined by each plan. The Company’s total contributions to these plans for the years ended December 31, 2018 and 2017 and the period from July 26, 2016 to December 31, 2016 were $10,242 , $8,823 , and $1,080 , respectively.

In the Predecessor period, certain of the Company’s employees participated in defined contribution and profit sharing plans sponsored by Alpha. The amount of contributions allocated to the Company related to the plans was $0 for the period from January 1, 2016 to July 25, 2016.

Self-Insured Medical Plan

The Company is self-insured for health benefit coverage for all of its active employees. Estimated liabilities for health and medical claims are recorded based on the Company’s historical experience and include a component for incurred but not paid claims. During the years ended December 31, 2018 and 2017 and the period from July 26, 2016 to December 31, 2016, the Company incurred total expenses of $37,958 , $31,318 , and $13,927 , respectively, which primarily includes claims processed and an estimate for claims incurred but not paid.

In the Predecessor period, certain of the Company’s employees participated in self-insured medical plans sponsored by Alpha. The amount of contributions allocated to the Company related to the plans was $18,121 for the period from January 1, 2016 to July 25, 2016, which is reflected within cost of coal sales and selling, general and administrative expenses in the Results of Operations.

( 23 ) Stock-Based Compensation Awards
The MIP is currently authorized for the issuance of awards of up to 1,201,202 shares of common stock, and as of December 31, 2018, there were 57,958 shares of common stock available for grant under the MIP. The Long-Term Incentive Plan (the “LTIP”) is currently authorized for the issuance of awards of up to 1,000,000 shares of common stock, and as of December 31, 2018, there were 828,280 shares of common stock available for grant under the LTIP. Pursuant to the Merger Agreement, the Company assumed the ANR Inc. 2017 Equity Incentive Plan (the “ANR EIP”), which had underlying ANR shares which were converted to 89,766 Contura shares. The ANR EIP is no t authorized for additional issuance of awards of shares of common stock, and as of December 31, 2018, there were no shares of common stock available for grant under the ANR EIP.
During the year ended December 31, 2018, the Company granted certain key employees 18,063 time-based restricted stock units under the MIP with a grant date fair value of $65.00 , based on the Company’s stock price at the date of grant. These time-based units will vest on the first anniversary of the date of the grant. As of the date of the awards, the Company did not have sufficient authorized and unissued common shares to settle these awards and the awards will be settled with cash, unless shares are available for issuance under the MIP on the applicable vesting date. Therefore, these awards are classified as a liability. The Company’s liability for all outstanding liability awards totaled $1,058 and $163 as of December 31, 2018 and December 31, 2017, respectively.

150
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Additionally, during the year ended December 31, 2018, the Company granted 7,310 time-based restricted stock units under the MIP to its non-employee directors. These time-based units granted to the Company’s non-employee directors will vest on the first to occur of (i) the day before the one-year anniversary of the date of grant, (ii) the director’s separation from service (as defined in Section 409A) due to the directors’ death or disability, (iii) a change in control, subject in each case to the director’s continuous service with the Company through such date, and (iv) the date immediately prior to an Initial Public Offering (“IPO”), contingent upon the consummation of the IPO. Upon vesting and settlement of time-based share units, the Company issues authorized and unissued shares of the Company’s common stock to the recipient. The time-based restricted stock units granted on May 1, 2018 have a grant date fair value of $64.97 , based on the Company’s stock price at the date of grant.

Additionally, during the year ended December 31, 2018, the Company granted certain key employees 169,849 time-based restricted stock units under the LTIP with a grant date fair value of $75.00 , based on the Company’s stock price at the trading day before the date of grant. These time-based units will vest ratably in accordance with the vesting schedule, subject to the participant’s continuous service with the Company through each applicable vesting date.

Additionally, during the year ended December 31, 2018, the Company granted 2,997 time-based restricted stock units under the LTIP to its non-employee directors. These time-based units granted to the Company’s non-employee directors will vest on the first to occur of (i) April 30, 2019, (ii) the director’s separation from service (as defined in Section 409A) due to the directors’ death or disability, and (iii) a change in control, subject in each case to the director’s continuous service with the Company through such date. Upon vesting and settlement of time-based share units, the Company issues authorized and unissued shares of the Company’s common stock to the recipient. The time-based restricted stock units granted on November 12, 2018 have a grant date fair value of $75.00 , based on the Company’s stock price at the trading day before the date of grant.

Additionally, during the year ended December 31, 2018, the Company assumed the ANR EIP award of 89,766 time-based restricted stock units to certain key employees with a grant date fair value of $75.00 , based on the Company’s stock price at the Merger date. These time-based units will vest ratably in accordance with the original award terms, subject to the participant’s continuous service with the Company through each applicable vesting date.

During the year ended December 31, 2017, the Company granted 437,450 shares of restricted stock and 129,520 non-qualified stock options under the MIP to certain of its officers and key employees under the MIP. The restricted stock shares and non-qualified stock options vest ratably over a three -year period or in the event of a change in control, will fully vest subject to the recipient’s continued employment through such date.

The restricted stock awards granted on March 7, 2017 and July 13, 2017 have a grant date fair value of $65.50 and $68.00 , respectively, based on the Company’s stock price at the date of grant. The non-qualified stock options, granted on March 7, 2017, have an exercise price of $66.13 with a 10 -year expiration from the date of grant. The non-qualified stock options have a grant date fair value of $37.44 based on a Black-Scholes pricing model. The Black-Scholes pricing model incorporates the assumptions as presented in the following table:
Stock price
$
65.50

Exercise price
$
66.13

Expected term (1)
6.00

Annual risk-free interest rate (2)
2.18
%
Annualized volatility (3)
60.9
%
(1)
The expected term represents the period of time that awards granted are expected to be outstanding.
(2)
The annual risk-free interest rate is based on the U.S. Constant Maturity Curve with a term equal to the award’s expected term on date of grant.
(3)
The annualized volatility is calculated by observing volatilities for comparable companies with adjustments for the Company’s size and leverage.

Additionally, during the year ended December 31, 2017, the Company granted 5,504 time-based restricted stock units under the MIP to its non-employee directors. These time-based units granted to the Company’s non-employee directors will vest on the first to occur of (i) the stated anniversary of the date of grant, (ii) the director’s separation from service (as defined in Section 409A of the Internal Revenue Code) due to the directors’ death or disability, and (iii) a change in control, subject in

151
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

each case to the director’s continuous service with the Company through such date. Upon settlement of time-based stock units, the Company issues authorized and unissued shares of the Company’s common stock to the recipient. The time-based restricted stock units granted on May 31, 2017, June 9, 2017, and July 13, 2017 have a grant date fair value of $74.00 , $73.00 , and $68.00 , respectively, based on the Company’s stock price at the date of grant. Of these awards, none remained outstanding as of December 31, 2018.
Additionally, during the year ended December 31, 2017, the Company awarded certain of its non-employee directors 6,700 time-based restricted stock units under the MIP with a grant date fair value of $62.55 , based on the Company’s stock price at the date of grant. As of the date of the awards the Company did not have sufficient authorized and unissued common shares to settle these awards and the awards will be settled with cash, unless shares become available for issuance under the MIP. Therefore, these awards are classified as a liability. These time-based units will vest on the first to occur of (i) the stated anniversary of the date of grant, (ii) the director’s separation from service (as defined in Section 409A of the Internal Revenue Code) due to the directors’ death or disability, and (iii) a change in control, subject in each case to the director’s continuous service with the Company through such date.
In connection with the Company’s declaration and payment of the Special Dividend and pursuant to the terms of the MIP, dividend equivalent payments of approximately $7,949 in the aggregate (including the amounts payable with respect to each share underlying outstanding stock option awards and restricted stock unit awards and outstanding restricted common stock under the MIP) were paid to plan participants. The dividend equivalent payments were made on July 11, 2017, which accelerated stock-based compensation expense by $5,113 and reduced the Company’s additional paid-in capital by $7,949 .
On July 26, 2016, under the MIP, the Company granted certain of its officers and key employees 309,310 shares of common stock, 145,648 stock options with an exercise price of $2.50 per share, and 145,648 stock options with an exercise price equal to the 30-day volume-weighted average price for the period beginning July 27, 2016 and ending thirty days thereafter, but in any case not less than $2.50 per share and not more than $5.00 per share. The units granted to the officers and key employees were fully vested on the grant date.
An iterative variant approach of the option pricing method was utilized in estimating the fair value of the restricted shares and stock options granted on July 26, 2016, due to the lack of an active market price at that date. The Company solved iteratively for the common share price such that the total fair value across all the outstanding equity units equaled the Company’s equity value as of the Acquisition Date in order to account for the dilutive impact of the options and warrants on common stock.
Using the value of common stock, the Company estimated the fair value of the stock options using the Black Scholes option pricing model. In estimating the fair value of the restricted shares, the Company applied the selected discount for lack of marketability to the common stock value to account for trading restrictions and different rights. Significant assumptions are as follows:
Total equity value
$44,644
Strike price
$2.50 per share and $5.00 per share for the fixed strike prices and the VWAP options, respectively
Expected life
The expected life was estimated by using the mid-point between the earliest time to exercise and the contractual expiration date
Volatility
85.0%
Cost of equity
40.0%
Risk-free rate
Estimated based on the U.S. Constant Maturity Treasury yield curve as of the Acquisition Date and linear interpolation to match for the respective term
Discount for lack of marketability
41.0% using the protective put method
Additionally, during the period from July 26, 2016 to December 31, 2016, the Company granted 28,122 time-based restricted stock units under the MIP to its non-employee directors based on the Company’s stock price at the date of grant, 18,748 of which remained outstanding as of December 31, 2018.
As of December 31, 2018, the Company had three types of stock-based awards outstanding: time-based restricted stock shares, time-based restricted share units, and stock options. Stock-based compensation expense totaled $13,354 , $20,372 , and $1,424 for the years ended December 31, 2018 and 2017 and the period from July 26, 2016 to December 31, 2016, respectively.

152
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

For the years ended December 31, 2018 and 2017 and the period from July 26, 2016 to December 31, 2016, approximately 90% , 94% , and 91% , respectively, of stock-based compensation expense was reported as selling, general and administrative expenses and the remainder was recorded as cost of coal sales.
The Company is authorized to repurchase common shares from employees (upon the election by the employee) to satisfy the employees’ statutory tax withholdings upon the vesting of stock grants. Shares that are repurchased to satisfy the employees’ statutory tax withholdings are recorded in treasury stock at cost. During the year ended December 31, 2018, the Company repurchased 76,648 shares of its common stock issued pursuant to awards under the MIP, LTIP and ANR EIP for a total purchase amount of $5,240 , or $68.36 average price paid per share. The Company did not repurchase any common shares from employees to satisfy the employees’ statutory tax withholdings upon vesting of stock grants during the year ended December 31, 2017 or the period from July 26, 2016 to December 31, 2016. On September 15, 2017, the Company repurchased 309,310 shares of its common stock issued pursuant to awards under the MIP for a total purchase amount of $17,445 , or $56.40 per share.
Restricted Stock Shares
Restricted stock shares activity for the years ended December 31, 2018 and 2017 and the period from July 26, 2016 to December 31, 2016 is summarized in the following table:
Number of
Shares
Weighted-
Average
Grant Date
Fair Value
Non-vested shares outstanding at July 26, 2016
—

$
—

Granted
309,310

$
2.50

Vested
(309,310
)
$
2.50

Forfeited or Expired
—

$
—

Non-vested shares outstanding at December 31, 2016
—

$
—

Granted
437,450

$
65.55

Vested
—

$
—

Forfeited or Expired
—

$
—

Non-vested shares outstanding at December 31, 2017
437,450

$
65.55

Granted
—

$
—

Vested
(172,651
)
$
65.55

Forfeited or Expired
—

$
—

Non-vested shares outstanding at December 31, 2018
264,799

$
65.55

As of December 31, 2018, there was $3,580 of unrecognized compensation cost related to non-vested time-based share units which is expected to be recognized as expense over a weighted-average period of 1 year.

153
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Restricted Share Units
Time-Based Share Units
Time-based share unit activity for the years ended December 31, 2018 and 2017 and the period from July 26, 2016 to December 31, 2016 is summarized in the following table:
Number of
Shares
Weighted-
Average
Grant Date
Fair Value
Non-vested shares outstanding at July 26, 2016
—

$
—

Granted
28,122

$
16.00

Vested
—

$
—

Forfeited or Expired
—

$
—

Non-vested shares outstanding at December 31, 2016
28,122

$
16.00

Granted
5,504

$
73.37

Vested (1)
(28,122
)
$
16.00

Forfeited or Expired
—

$
—

Non-vested shares outstanding at December 31, 2017
5,504

$
73.37

Granted
269,922

$
74.73

Vested
(22,417
)
$
74.67

Forfeited or Expired
(1,134
)
$
73.61

Non-vested shares outstanding at December 31, 2018
251,875

$
74.71

(1) Includes 18,748 shares with deferred settlement pursuant to the award agreement.
As of December 31, 2018, there was $14,371 of unrecognized compensation cost related to non-vested time-based share units which is expected to be recognized as expense over a weighted-average period of 1.8 years.
Time-based cash share unit activity for the years ended December 31, 2018 and 2017 is summarized in the following table:
Number of
Shares
Weighted-
Average
Fair Value (1)
Non-vested shares outstanding at December 31, 2016
—

$
—

Granted
6,700

$
62.55

Vested
—

$
—

Forfeited or Expired
—

$
—

Non-vested shares outstanding at December 31, 2017
6,700

$
59.38

Granted
18,063

$
65.00

Vested (2)
(6,700
)
$
71.66

Forfeited or Expired
—

$
—

Non-vested shares outstanding at December 31, 2018
18,063

$
65.74

(1) The time-based cash units are accounted for as liability awards. Therefore, the weighted-average fair value is calculated using the Company's stock price at the respective granted dates, vested date, and outstanding dates.
(2) Pursuant to the award agreement, these shares were settled in equity and have deferred settlement pursuant to the award agreement.

As of December 31, 2018, there was $130 of unrecognized compensation cost related to non-vested time-based share units which is expected to be recognized as expense over a weighted-average period of 0.11 years.

154
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Stock Options
Fixed Price Stock Options
On July 26, 2016, the Company granted certain of its officers and key employees 145,648 stock options with an exercise price of $2.50 per share and a grant date fair value of $1.67 . The units granted included 110,573 incentive stock option shares and 35,075 non-qualified stock option shares. The units granted to the officers and key employees were fully vested on the grant date.
Fixed price stock option activity for the years ended December 31, 2018 and 2017 and the period from July 26, 2016 to December 31, 2016 is summarized in the following table:
Number of
Shares
Weighted-
Average
Exercise
Price
Weighted-
Average
Remaining
Contractual
Term (Years)
Outstanding at July 26, 2016
—

$
—

Granted
145,648

$
2.50

10.00
Exercised
—

$
—

Forfeited or Expired
—

$
—

Outstanding at December 31, 2016
145,648

$
2.50

9.57
Exercisable at December 31, 2016
145,648

$
2.50

9.57
Granted
—

$
—


Exercised
—

$
—


Forfeited or Expired
—

$
—


Outstanding at December 31, 2017
145,648

$
2.50

8.57
Exercisable at December 31, 2017
145,648

$
2.50

8.57
Granted
—

$
—


Exercised
(19,520
)
$
2.50

7.92
Forfeited or Expired
—

$
—


Outstanding at December 31, 2018
126,128

$
2.50

7.57
Exercisable at December 31, 2018
126,128

$
2.50

7.57
As of December 31, 2018, the options outstanding and exercisable had an aggregate intrinsic value of $63.24 calculated as the difference between the exercise price and the Company’s stock price at December 31, 2018. As of December 31, 2018, there was no unrecognized compensation cost related to the fixed price stock options.
30-Day Volume-Weighted Average Price (“VWAP”) Stock Options
During the year ended December 31, 2017, the Company granted 129,520 non-qualified stock options to certain of its officers and key employees under the MIP. The non-qualified stock options vest ratably over a three -year period or in the event of a change in control, will fully vest subject to the recipient’s continued employment through such date. The non-qualified stock options, granted on March 7, 2017, have an exercise price of $66.13 with a 10 -year expiration from the date of grant. The non-qualified stock options have a grant date fair value of $37.44 based on a Black-Scholes pricing model.
On July 26, 2016, the Company granted certain of its officers and key employees 145,648 stock options with an exercise price equal to the 30-day VWAP price for the period beginning July 27, 2016 and ending thirty days thereafter, but in any case not less than $2.50 per share and not more than $5.00 per share and a grant date fair value of $1.51 . The units granted included 70,573 incentive stock option shares and 75,075 non-qualified stock option shares. The units granted to the officers and key employees were fully vested on the grant date.

155
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

30-day VWAP stock option activity for the years ended December 31, 2018 and 2017 and the period from July 26, 2016 to December 31, 2016 is summarized in the following table:
Number of
Shares
Weighted-
Average
Exercise
Price
Weighted-
Average
Remaining
Contractual
Term (Years)
Outstanding at July 26, 2016
—

$
—

Granted
145,648

$
5.00

10.00
Exercised
—

$
—

Forfeited or Expired
—

$
—

Outstanding at December 31, 2016
145,648

$
5.00

9.57
Exercisable at December 31, 2016
145,648

$
5.00

9.57
Granted
129,520

$
66.13

9.18
Exercised
—

$
—

Forfeited or Expired
—

$
—

Outstanding at December 31, 2017
275,168

$
33.77

8.86
Exercisable at December 31, 2017
145,648

$
5.00

8.57
Granted
—

$
—

Exercised
(19,520
)
$
5.00

7.92
Forfeited or Expired
—

$
—

Outstanding at December 31, 2018
255,648

$
35.97

7.88
Exercisable at December 31, 2018
177,152

$
22.61

7.74
As of December 31, 2018, the options outstanding and exercisable that were granted July 26, 2016 and March 7, 2017 had an aggregate intrinsic value of $60.74 and ($0.39) , respectively, calculated as the difference between the exercise price and the Company’s stock price at December 31, 2018. As of December 31, 2018, there was $519 of unrecognized compensation cost related to the 30-day VWAP stock options which is expected to be recognized as expense over a weighted-average period of 1 year.
Alpha
In the Predecessor period, Alpha sponsored the following employee stock plans in which certain Company employees participated:
On May 22, 2014, Alpha’s stockholders approved the Amended and Restated 2012 Long-Term Incentive Plan (the “2012 LTIP”). The principal purpose of the 2012 LTIP was to advance the interests of Alpha and its stockholders by providing incentives to certain eligible persons who contribute significantly to the strategic and long-term performance objectives and growth of Alpha. On May 22, 2014, Alpha’s stockholders approved an additional 3,100,000 shares of common stock for issuance under the 2012 LTIP Plan. The 2012 LTIP was authorized for the issuance of awards of up to 13,100,000 shares of common stock, and as of July 25, 2016, 7,218,657 shares of common stock were available for grant under the 2012 LTIP. The 2012 LTIP provided for a variety of awards, including options, stock appreciation rights, restricted stock, restricted share units (both time-based and performance-based), and any other type of award deemed by the compensation committee in its discretion to be consistent with the purpose of the 2012 LTIP. Prior to the approval of the 2012 LTIP, Alpha issued awards under the 2010 Long Term Incentive Plan (the “2010 LTIP”) and the Alpha Appalachia 2006 Stock and Incentive Compensation Plan (the “2006 SICP”). Upon approval of the 2012 LTIP, no additional awards were issued under the 2010 LTIP or the 2006 SICP. The 2012 LTIP, the 2010 LTIP and the 2006 SICP are collectively referred to as the “Stock Plans.” Alpha also had stock-based awards outstanding under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (the “2005 LTIP”) and the Foundation Amended and Restated 2004 Stock Incentive Plan (the “2004 SIP”).
Upon vesting of restricted share units (both time-based and performance-based) or the exercise of options, shares were issued from the 2012 LTIP, the 2010 LTIP, the 2006 SICP, the 2005 LTIP, and the 2004 SIP, respective of which plan the awards were granted.

156
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Alpha was authorized to repurchase common shares from employees (upon the election by the employee) to satisfy the employees’ minimum statutory tax withholdings upon the vesting of restricted stock and restricted share units (both time-based and performance-based). Shares that were repurchased to satisfy the employees’ minimum statutory tax withholdings were recorded in treasury stock at cost. During the period from January 1, 2016 to July 25, 2016, Alpha repurchased 0 common shares from employees.
At July 25, 2016, Alpha had three types of stock-based awards outstanding: restricted share units (both time-based and performance-based), restricted cash units (both time-based and performance-based), and stock options. As a result of Alpha’s bankruptcy filing, Alpha was no longer settling pre-petition awards. Stock-based compensation expense recorded by the Company totaled $465 for the period from January 1, 2016 to July 25, 2016. For the period from January 1, 2016 to July 25, 2016, approximately 78% of stock-based compensation expense was reported as selling, general and administrative expenses and the remainder was recorded as cost of coal sales. The total excess tax benefit recognized for stock-based compensation was $0 for the period from January 1, 2016 to July 25, 2016.
Restricted Share Units
Time-Based Share Units
During the period from January 1, 2016 to July 25, 2016, Alpha granted 0 time-based share units or time-based cash units under the 2012 LTIP to certain executive officers, directors and key employees. Time-based cash units were accounted for as liability awards and subject to variable accounting. The grant date fair value of the time-based share units were based on the Company’s stock price at the respective date.
Alpha’s time-based share unit activity for the period from January 1, 2016 to July 25, 2016 is summarized in the following table:
Number of
Shares
Weighted-Average
Grant Date
Fair Value
Alpha
Non-vested shares outstanding at December 31, 2015
4,722,199

$
3.24

Granted
—

$
—

Earned
—

$
—

Forfeited or Expired
(511,048
)
$
2.13

Non-vested shares outstanding at July 25, 2016
4,211,151

$
3.37

Alpha’s time-based cash unit activity for the period from January 1, 2016 to July 25, 2016 is summarized in the following table:
Number of
Shares
Weighted-Average
Grant Date
Fair Value (1)
Alpha
Non-vested shares outstanding at December 31, 2015
9,950,460

$
0.01

Granted
—

$
—

Earned
—

$
—

Forfeited or Expired
(550,653
)
$
1.46

Non-vested shares outstanding at July 25, 2016
9,399,807

$
1.35

(1)
The time-based cash units were accounted for as liability awards and subject to variable accounting. Therefore, the weighted-average fair value was calculated using Alpha’s stock price at the respective granted date, vested date and forfeited/expired date.

The fair value of time-based share unit awards that vested in the period from January 1, 2016 to July 25, 2016 was $0 . As of July 25, 2016, Alpha had $2,184 of unrecognized compensation cost related to non-vested time-based share units which was

157
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

expected to be recognized as expense over a weighted-average period of 1.33 years. Additionally, as of July 25, 2016, Alpha had $36 of unrecognized compensation cost related to non-vested time-based cash units which was expected to be recognized as expense over a weighted-average period of 1.31 years. The unrecognized compensation cost, related to non-vested time-based cash units which are accounted for as liability awards and subject to variable accounting, was calculated using Alpha’s July 25, 2016 stock price.
Performance-Based Share Units
Performance-based share units awarded to executive officers and key employees generally cliff vested after three years, subject to continued employment (with accelerated vesting upon a change of control). Performance-based share units granted represented the number of shares of common stock to be awarded based on the achievement of targeted performance levels related to pre-established operating income goals, strategic goals, total stockholder return goals, and cash flow from operations goals over a three year period and could range from 0 percent to 200 percent of the targeted amount. The grant date fair value of the awards with performance conditions was based on the closing price of Alpha’s common stock on the established grant date and was amortized over the performance period. The grant date fair value of the awards with market conditions was based upon a Monte Carlo simulation and was amortized over the performance period. For awards with performance conditions, Alpha reassessed at each reporting date whether achievement of each of the performance conditions was probable, as well as estimated forfeitures, and adjusted the accruals of compensation expense as appropriate. For awards with market conditions, Alpha recognized expense over the applicable service periods and did not adjust expense based on the actual achievement or nonachievement of the market condition because the probability of achievement was considered in the grant date fair value of the award. Upon vesting of performance-based share units, Alpha issued authorized and unissued shares of Alpha’s common stock to the recipient. During the period from January 1, 2016 to July 25, 2016, Alpha awarded 0 total stockholder return performance-based share units.
Alpha’s performance-based share unit activity is summarized in the following table:
Number of
Shares (1)
Weighted-Average Grant Date Fair Value
Alpha
Non-vested shares outstanding at December 31, 2015
4,395,717

$
6.39

Granted
—

$
—

Earned
—

$
—

Forfeited or Expired
(1,363,126
)
$
7.63

Non-vested shares outstanding at July 25, 2016
3,032,591

$
5.83

(1)
Shares in the table above were based on the maximum shares that can be awarded based on the achievement of the performance criteria.

Non-Qualified Stock Options

Alpha’s stock option activity for the period from January 1, 2016 to July 25, 2016 is summarized in the following table:
Number of
Shares
Weighted-
Average
Exercise
Price
Weighted-Average
Remaining
Contractual
Term (Years)
Alpha
Outstanding at December 31, 2015
359,027

$
26.20

3.50
Exercisable at December 31, 2015
359,027

$
26.20

3.50
Exercised
—

$
—

Forfeited or Expired
(58,350
)
$
22.87

Outstanding at July 25, 2016
300,677

$
26.84

2.89
Exercisable at July 25, 2016
300,677

$
26.84

2.89

158
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

As of July 25, 2016, the options outstanding and exercisable had an aggregate intrinsic value of $0 . Cash received from the exercise of stock options during the period from January 1, 2016 to July 25, 2016 was $0 . As of July 25, 2016, there was no unrecognized compensation cost related to stock options.
The total intrinsic value of options exercised during the period from January 1, 2016 to July 25, 2016 was $0 . Alpha historically used authorized and unissued shares to satisfy share award exercises.
A summary of Alpha’s options outstanding and exercisable at July 25, 2016 follows:
Options Outstanding and Exercisable
Exercise Price
Shares
Weighted-Average
Remaining
Life (yrs)
Weighted-Average
Exercise Price
$ 11.15 - $20.44
110,413

2.03
$
16.59

$ 23.93 - $32.91
112,704

2.79
$
27.08

$ 40.98 - $48.26
77,560

4.27
$
41.07

300,677

2.89
$
26.84


( 24 ) Reorganization Items
In connection with Alpha’s restructuring during the Predecessor period, certain prepetition liabilities were reclassified as liabilities subject to compromise. Liabilities subject to compromise included estimated or liquidated amounts for certain obligations arising prior to the Petition Date, including, among others, (i) contractual obligations, (ii) debt-related obligations and (iii) litigation and other contingent claims, some of which were recorded in accounts payable.
Reorganization items consisted of the following:
Predecessor
Period from January 1, 2016 to July 25, 2016 (2)
Professional fees (1)
$
(28,652
)
Provision for rejected contracts and leases
(3,524
)
Trade accounts payable and other
1,103

Reorganization items, net
$
(31,073
)
(1) Net cash paid for reorganization items for the period from January 1, 2016 to July 25, 2016 totaled approximately $27,236 related to professional fees.
(2) Includes the Company’s PRB operations being reported as discontinued operations in the Consolidated Financial Statements.

( 25 ) Related Party Transactions
There were no material related party transactions for the year ended December 31, 2018 .

Predecessor
As discussed in Note 1, the Predecessor Financial Statements include direct costs of the Company incurred by Alpha on the Company’s behalf and an allocation of general corporate expenses of Alpha which were not historically allocated to the Company for certain support functions that were provided on a centralized basis within Alpha and not recorded at the business unit level, such as expenses related to engineering, finance, human resources, information technology, sales and logistics, and legal, among others, and that would have been incurred had the Company been a separate, stand-alone entity. All significant affiliate transactions between Contura and Alpha have been included in these Financial Statements and are considered to be effectively settled for cash at the time the transaction is recorded. The total net effect of the settlement of these affiliate transactions represents capital contributions from or distributions to Alpha and therefore is reflected in the accompanying Statements of Cash Flows as a financing activity.

159
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

During the period from January 1, 2016 to July 25, 2016, the Company was allocated $57,217 of indirect general corporate expenses incurred by Alpha, which are included within continuing and discontinued operations in the Combined Statements of Operations. These amounts exclude allocated reorganization items, which are discussed in Note 24 .

( 26 ) Commitments and Contingencies
(a) General
Estimated losses from loss contingencies are accrued by a charge to income when information available indicates that it is probable that an asset has been impaired or a liability has been incurred and the amount of the loss can be reasonably estimated.
If a loss contingency is not probable or reasonably estimable, disclosure of the loss contingency is made in the Financial Statements when it is at least reasonably possible that a loss may be incurred and that the loss could be material.
(b) Commitments and Contingencies
Commitments
The Company leases coal mining and other equipment under long-term capital and operating leases with varying terms. In addition, the Company leases mineral interests and surface rights from land owners under various terms and royalty rates.
As of December 31, 2018 , aggregate future minimum non-cancelable lease payments under operating leases and minimum royalties under coal leases were as follows:
Operating
Leases
Coal
Royalties
Year Ending December 31:
2019
$
3,537

$
13,579

2020
3,232

12,992

2021
1,945

12,687

2022
360

10,697

2023
158

9,618

Thereafter
458

28,056

Total
$
9,690

$
87,629

Net rent expense under operating leases was $2,124 , $1,838 , $582 , and $659 for the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016, respectively. Coal royalty expense was $34,485 , $21,707 , $7,869 , and $5,807 for the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016, respectively.

Other Commitments

The Company has obligations under certain coal purchase agreements that contain minimum quantities to be purchased in 2019 totaling an estimated $260,205 , which includes an estimated $70,924 related to contractually committed variable priced tons from vendors with historical performance resulting in less than 20% of the committed tonnage being delivered. The Company has obligations under certain coal transportation agreements that contain minimum quantities to be shipped in 2019 and 2020 totaling $3,072 and $3,102 , respectively. The Company also has obligations under certain equipment purchase agreements that contain minimum quantities to be purchased in 2019 totaling $24,339 .
Contingencies
Extensive regulation of the impacts of mining on the environment and of maintaining workplace safety has had and is expected to continue to have a significant effect on the Company’s costs of production and results of operations. Further

160
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

regulations, legislation or litigation in these areas may also cause the Company’s sales or profitability to decline by increasing costs or by hindering the Company’s ability to continue mining at existing operations or to permit new operations.
During the normal course of business, contract-related matters arise between the Company and its customers. When a loss related to such matters is considered probable and can reasonably be estimated, the Company records a liability.
Per terms of the Back-to-Back Coal Supply Agreements, the Company is required to purchase and sell coal in 2019 and 2020 totaling $16,113 and $9,175 , respectively. For the year ended December 31, 2018 , the Company purchased and sold 5,719 tons, totaling $62,093 under the Back-to-Back Coal Supply Agreements. For the year ended December 31, 2017, the Company purchased and sold 2,000 tons, totaling $21,707 under the Back-to-Back Coal Supply Agreements.
In October 2018, the State of Wyoming Department of Revenue invoiced Blackjewel for approximately $7,800 in severance taxes owed by Blackjewel in connection with the Wyoming properties it previously acquired from the Company. The transfer of mining permits associated with these properties is pending. In connection with this invoice, the Department purported to assert liens over Contura Coal West, LLC, one of the Company’s subsidiaries. The Company believes that, in light of the sale of the Wyoming properties to Blackjewel, neither the Company nor its subsidiary is obligated to pay these severance taxes. On October 28, 2018, Blackjewel entered into a payment plan agreement with the State of Wyoming Department of Revenue to address the severance taxes owed by Blackjewel.

Future Federal Income Tax Refunds

As of December 31, 2018, the Company has recorded $68,774 of federal income tax receivable and $68,774 of federal deferred tax asset related to AMT Credits. In addition, the Company has recorded a non-current federal income tax receivable of $43,770 related to an NOL carryback claim. Because the federal government was a creditor in the Alpha Natural Resources, Inc. (“Predecessor Alpha”) bankruptcy proceedings, it is possible that the federal government could withhold some or all of the tax refund attributable to the NOL carryback claim and the refundable AMT Credits and assert a right to setoff the tax refund and refundable credits against its prepetition bankruptcy claims.

(c) Guarantees and Financial Instruments with Off-Balance Sheet Risk
In the normal course of business, the Company is a party to certain guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit, performance or surety bonds, and other guarantees and indemnities related to the obligations of affiliated entities which are not reflected in the Company’s Balance Sheet. As of December 31, 2018 , the Company had outstanding surety bonds with a total face amount of $581,436 to secure various obligations and commitments, including $237,150 related to the PRB. To secure the Company’s reclamation-related obligations, the Company currently has $137,269 of collateral supporting these obligations. Once the permits associated with the PRB Transaction have been transferred, the Company estimates approximately $12,600 comprised of short-term restricted cash and short-term deposits will be returned to operating cash.
Amounts included in restricted cash represent cash deposits that are restricted as to withdrawal as required by certain agreements entered into by the Company and provide collateral in the amounts of $90,759 , $29,611 , $86,217 , $27,386 , and $2,833 as of December 31, 2018 for securing the Company’s obligations under certain worker’s compensation, black lung, reclamation-related obligations, general liabilities, and financial guarantees, respectively, which have been written on the Company’s behalf. Additionally, the Company has $6,841 of short-term restricted cash held in escrow related to the Company’s contingent revenue payment obligation. Refer to Note 16 for further information regarding the contingent payment revenue obligation. The Company’s restricted cash is primarily invested in interest bearing accounts. This restricted cash is classified as both short-term and long-term on the Company’s Consolidated Balance Sheets.

Amounts included in restricted investments consist of certificates of deposit, corporate bonds, and U.S. treasury bills that are restricted as to withdrawal as required by certain agreements entered into by the Company and provide collateral in the amounts of $1,888 , $27,049 , and $200 as of December 31, 2018 for securing the Company’s obligations under certain worker’s compensation, reclamation-related obligations, and general liabilities, respectively, which have been written on the Company’s behalf. These restricted investments are classified as long-term on the Company’s Consolidated Balance Sheets.

Deposits represent cash deposits held at third parties as required by certain agreements entered into by the Company to provide cash collateral. At December 31, 2018 , the Company had cash collateral in the form of deposits in the amounts of

161
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

$24,002 and $1,390 to secure the Company’s obligations under reclamation-related obligations and various other operating agreements, respectively. These deposits are classified as both short-term and long-term on the Company’s Consolidated Balance Sheets.

As of December 31, 2018 , the Company had real property collateralizing $26,749 of reclamation bonds.
WVDEP Settlement Agreement

On November 6, 2018, Contura, the Alpha Companies and the West Virginia Department of Environmental Protection (the “WVDEP”) entered into a binding term sheet agreement (the “Term Sheet”) to resolve certain issues related to the issuance of the Dividend under the Permitting and Reclamation Plan Settlement Agreement for the State of West Virginia dated as of July 12, 2016 (amended by the First Amendment dated July 25, 2016 and by the Second Amendment dated October 23, 2017, the “Amended Settlement Agreement”).
Pursuant to the Term Sheet, the WVDEP provided its consent to the Dividend. The Term Sheet also provides for the extension of the first lien mortgage and deed of trust in an office and associated real estate in Julian, West Virginia previously granted by ANR to the WVDEP to secure ANR’s obligations under the Amended Settlement Agreement until ANR and Contura complete the payments required under the Reclamation Funding Agreement dated as of July 12, 2016, by and among, ANR, Contura, WVDEP, and the regulatory agencies of Illinois, Tennessee, Kentucky and Virginia (the “Amended Reclamation Funding Agreement”). Contura is also obligated under the Term Sheet to continue to hold subject to the applicable Deposit Account Control Agreements referenced in the Amendment of Agreements dated as of October 23, 2017 by and between Contura and the WVDEP approximately $2,800 of certain cash collateral until ANR and Contura complete the payments required of them under the Amended Reclamation Funding Agreement.

Concurrent with ANR’s issuance of the Dividend on November 8, 2018, pursuant to the Term Sheet, Contura posted cash collateral with WVDEP in the amount of $9,000 , to secure Contura’s and ANR’s payment obligations under the Amended Reclamation Funding Agreement and the Amended Settlement Agreement (the “Payment Obligations”) until a performance bond was issued as described in the following sentence. During the fourth quarter of 2018, as required under the Term Sheet, Contura issued a performance bond to WVDEP in the amount of $35,000 to secure the Payment Obligations. The amount of such performance bond will decrease on a dollar to dollar basis after the Payment Obligations fall below $35,000 . Upon issuance of the performance bond, the $9,000 cash collateral was released to Contura within the first quarter of 2019.

Letters of Credit

As of December 31, 2018 , the Company had $28,700 letters of credit outstanding under the Amended and Restated Asset-Based Revolving Credit Agreement. Additionally, as a result of the Merger, the Company assumed $135,746 letters of credit outstanding under the Amended and Restated Letter of Credit Agreement dated November 9, 2018 between ANR, Inc. and Citibank, N.A. and $11,876 letters of credit outstanding under the Credit and Security Agreement dated June 30, 2017, and related amendments, between ANR, Inc. and First Tennessee Bank National Association.

(d) Legal Proceedings

The Company could become party to legal proceedings from time to time. These proceedings, as well as governmental examinations, could involve various business units and a variety of claims including, but not limited to, contract disputes, personal injury claims, property damage claims (including those resulting from blasting, trucking and flooding), environmental and safety issues, securities-related matters and employment matters. While some legal matters may specify the damages claimed by the plaintiffs, many seek an unquantified amount of damages. Even when the amount of damages claimed against the Company or its subsidiaries is stated, (i) the claimed amount may be exaggerated or unsupported; (ii) the claim may be based on a novel legal theory or involve a large number of parties; (iii) there may be uncertainty as to the likelihood of a class being certified or the ultimate size of the class; (iv) there may be uncertainty as to the outcome of pending appeals or motions; and/or (v) there may be significant factual issues to be resolved. As a result, if such legal matters arise in the future, the Company may be unable to estimate a range of possible loss for matters that have not yet progressed sufficiently through discovery and development of important factual information and legal issues. The Company records accruals based on an estimate of the ultimate outcome of these matters, but these estimates can be difficult to determine and involve significant judgment.


162
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

( 27 ) Concentration of Credit Risk and Major Customers

The Company markets its coal principally to electric utilities in the United States and international and domestic steel producers. Credit is extended based on an evaluation of the customer’s financial condition and collateral is generally not required. Credit losses are provided for in the Financial Statements and were minimal for the years ended December 31, 2018 and 2017 , the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016.

Top customers as a percentage of total revenue and met and thermal coal as % of coal sales volume were as follows:
Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Total revenue
$
2,031,205

$
1,649,969

$
506,296

$
411,111

Top customer as % of total revenue (1)
17
%
15
%
15
%
7
%
Top 10 customers as % of total revenue (2)
60
%
65
%
67
%
54
%
Met coal as % of coal sales volume
63
%
57
%
53
%
37
%
Thermal coal as % of coal sales volume
37
%
43
%
47
%
63
%
(1) Revenues from the top customer are included in the CAPP - Met, NAPP, and Trading and Logistics segments for the year ended December 31, 2018, the CAPP - Met and Trading and Logistics segments for the year ended December 31, 2017, the CAPP - Met, NAPP, and Trading and Logistics segments for the period from July 26, 2016 to December 31, 2016, and the NAPP segment for the period from January 1, 2016 to July 25, 2016.
(2) In addition to the top customer, the Company has another customer with total revenues of 13% of total revenues included in the CAPP - Met, NAPP, and Trading and Logistics segments for the year ended December 31, 2018.

Additionally, two of the Company’s customers had outstanding balances each in excess of 10% of the total accounts receivable balance as of December 31, 2018 , and two of the Company’s customers had outstanding balances each in excess of 10% of the total accounts receivable balance as of December 31, 2017 .

The Company sold 5,968 tons of coal purchased from third parties, excluding tons sold related to the Back-to-Back Coal Supply Agreements, for the year ended December 31, 2018 , representing approximately 34% of total coal sales volume during such period. The Company sold 4,998 tons of coal purchased from third parties for the year ended December 31, 2017 , representing approximately 32% of total coal sales volume during such period. The Company purchased a substantial portion of this coal from Alpha.

( 28 ) Segment Information
The Company extracts, processes and markets met and thermal coal from surface and deep mines for sale to electric utilities, steel and coke producers, and industrial customers. The Company conducts mining operations only in the United States with mines in Northern and Central Appalachia. The Company has four reportable segments: CAPP - Met, CAPP - Thermal, NAPP, and Trading and Logistics. CAPP - Met consists of eight active mines and two preparation plants in Virginia, seventeen active mines and six preparation plants in West Virginia, as well as expenses associated with certain closed mines. CAPP - Thermal consists of six active mines and three preparation plants in West Virginia. NAPP consists of one active mine in Pennsylvania and one preparation plant, as well as expenses associated with one closed mine. The Trading and Logistics segment primarily engages in coal trading activities and coal terminal services. Prior to the Merger, the Company had three reportable segments: CAAP, NAPP, and Trading and Logistics.
In addition to the four reportable segments, the All Other category includes general corporate overhead and corporate assets and liabilities and the elimination of certain intercompany activity.
The operating results of these reportable segments are regularly reviewed by the Chief Operating Decision Maker (“CODM”), who is the Chief Executive Officer of the Company.
Segment operating results and capital expenditures for the year ended December 31, 2018 were as follows:

163
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Successor
Year Ended December 31, 2018
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Total revenues
$
650,385

$
36,222

$
285,796

$
1,055,505

$
3,297

$
2,031,205

Depreciation, depletion, and amortization
$
40,330

$
10,596

$
23,273

$
—

$
3,350

$
77,549

Amortization of acquired intangibles, net
$
2,746

$
662

$
—

$
(8,800
)
$
—

$
(5,392
)
Adjusted EBITDA
$
236,400

$
(875
)
$
44,368

$
98,735

$
(43,552
)
$
335,076

Capital expenditures
$
39,634

$
1,280

$
40,635

$
—

$
332

$
81,881


Segment operating results and capital expenditures for the year ended December 31, 2017 were as follows:
Successor
Year Ended December 31, 2017
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Total revenues
$
460,023

$
—

$
306,563

$
882,548

$
835

$
1,649,969

Depreciation, depletion, and amortization
$
18,941

$
—

$
15,087

$
—

$
882

$
34,910

Amortization of acquired intangibles, net
$
—

$
—

$
—

$
59,007

$
—

$
59,007

Adjusted EBITDA
$
175,018

$
—

$
54,433

$
89,296

$
(40,281
)
$
278,466

Capital expenditures
$
20,494

$
—

$
51,007

$
—

$
1,200

$
72,701


Segment operating results and capital expenditures for the period from July 26, 2016 to December 31, 2016 were as follows:
Successor
Period from July 26, 2016 to December 31, 2016
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Total revenues
$
138,973

$
—

$
132,363

$
234,704

$
256

$
506,296

Depreciation, depletion, and amortization
$
6,442

$
—

$
(772
)
$
—

$
303

$
5,973

Amortization of acquired intangibles, net
$
—

$
—

$
—

$
61,281

$
—

$
61,281

Adjusted EBITDA
$
46,404

$
—

$
28,198

$
39,265

$
(18,042
)
$
95,825

Capital expenditures
$
4,626

$
—

$
18,136

$
—

$
612

$
23,374



164
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Segment operating results and capital expenditures for the period from January 1, 2016 to July 25, 2016 were as follows:
Predecessor
Period from January 1, 2016 to July 25, 2016
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Total revenues
$
169,411

$
—

$
229,323

$
12,377

$
—

$
411,111

Depreciation, depletion, and amortization
$
15,389

$
—

$
49,852

$
3

$
832

$
66,076

Amortization of acquired intangibles, net
$
—

$
—

$
11,567

$
—

$
—

$
11,567

Adjusted EBITDA
$
625

$
—

$
35,515

$
(1,180
)
$
(29,073
)
$
5,887

Capital expenditures
$
894

$
—

$
14,468

$
—

$
—

$
15,362


The following table presents a reconciliation of net income (loss) to Adjusted EBITDA for the year ended December 31, 2018 :
Successor
Year Ended December 31, 2018
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Net income (loss) from continuing operations
$
193,422

$
(18,974
)
$
18,651

$
107,196

$
2,559

$
302,854

Interest expense
260

1

(1,286
)
—

39,835

38,810

Interest income
(22
)
—

(34
)
(18
)
(1,875
)
(1,949
)
Income tax benefit
—

—

—

—

(165,363
)
(165,363
)
Depreciation, depletion and amortization
40,330

10,596

23,273

—

3,350

77,549

Merger related costs
—

1

—

22

51,777

51,800

Management restructuring costs (1)
—

—

—

—

2,659

2,659

Non-cash stock compensation expense
73

24

—

335

11,546

11,978

Mark-to-market adjustment - acquisition-related obligations
—

—

—

—

24

24

Gain on settlement of acquisition-related obligations
—

—

—

—

(580
)
(580
)
Gain on sale of disposal group (2)
(16,386
)
—

—

—

—

(16,386
)
Accretion on asset retirement obligations
4,430

1,298

3,764

—

474

9,966

Loss on modification and extinguishment of debt
—

—

—

—

12,042

12,042

Cost impact of coal inventory fair value adjustment (3)
11,547

5,517

—

—

—

17,064

Amortization of acquired intangibles, net
2,746

662

—

(8,800
)
—

(5,392
)
Adjusted EBITDA
$
236,400

$
(875
)
$
44,368

$
98,735

$
(43,552
)
$
335,076

(1) Management restructuring costs are related to severance expense associated with senior management changes in the year ended December 31, 2018 .
(2) During the fourth quarter of 2017, the Company entered into an asset purchase agreement to sell a disposal group (comprised of property, plant and equipment and associated asset retirement obligations) within the Company’s CAPP - Met segment. From the date the Company entered into the asset purchase agreement through the transaction close date, the property, plant and equipment and associated asset retirement obligations were classified as held for sale in amounts representing the fair value of the disposal group. Upon permit transfer, the transaction closed on April 2, 2018. The Company paid $10,000 in connection

165
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

with the transaction, which was paid into escrow on March 27, 2018 and transferred to the buyer at the transaction close date, and expects to pay a series of additional cash payments in the aggregate amount of $1,500 , per the terms stated in the agreement, and recorded a gain on sale of $16,386 within other (income) expense within the Consolidated Statements of Operations.
(3) The cost impact of the coal inventory fair value adjustment as a result of the Alpha Merger is expected to have short-term impact.

The following table presents a reconciliation of net income (loss) to Adjusted EBITDA for the year ended December 31, 2017 :
Successor
Year Ended December 31, 2017
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Net income (loss) from continuing operations
$
150,304

$
—

$
36,604

$
29,639

$
(42,812
)
$
173,735

Interest expense
(90
)
—

(1,505
)
—

37,572

35,977

Interest income
(22
)
—

(1
)
—

(187
)
(210
)
Income tax benefit
—

—

—

—

(67,979
)
(67,979
)
Depreciation, depletion and amortization
18,941

—

15,087

—

882

34,910

Non-cash stock compensation expense
—

—

—

650

19,559

20,209

Mark-to-market adjustment - acquisition-related obligations
—

—

—

—

3,221

3,221

Gain on settlement of acquisition-related obligations
—

—

—

—

(38,886
)
(38,886
)
Secondary offering costs
—

—

—

—

4,491

4,491

Loss on modification and extinguishment of debt
—

—

—

—

38,701

38,701

Bargain purchase gain
—

—

—

—

(1,011
)
(1,011
)
Accretion on asset retirement obligations
5,770

—

4,164

—

—

9,934

Amortization of acquired intangibles, net
—

—

—

59,007

—

59,007

Expenses related to the dividend
115

—

84

—

6,168

6,367

Adjusted EBITDA (1) (2)
$
175,018


$
—

$
54,433


$
89,296


$
(40,281
)

$
278,466

(1) The Company’s Adjusted EBITDA calculation has been modified to add back non-cash stock compensation expense and accretion on asset retirement obligations to align with industry peer group methodology.
(2) Pursuant to the PRB divestiture and classification as a discontinued operation, the Company is no longer presenting a PRB reporting segment. The former PRB reporting segment had Adjusted EBITDA of $41,863 for the year ended December 31, 2017 .


166
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

The following table presents a reconciliation of net income (loss) to Adjusted EBITDA for the period from July 26, 2016 to December 31, 2016:
Successor
Period from July 26, 2016 to December 31, 2016
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Consolidated
Net income (loss) from continuing operations
$
37,436

$
—

$
26,434

$
(22,053
)
$
(53,663
)
$
(11,846
)
Interest expense
97

—

171

—

20,228

20,496

Interest income
(6
)
—

—

—

(17
)
(23
)
Income tax benefit
—

—

—

—

(1,920
)
(1,920
)
Depreciation, depletion and amortization
6,442

—

(772
)
—

303

5,973

Non-cash stock compensation expense
—

—

—

37

1,387

1,424

Mark-to-market adjustment for warrant derivative liability
—

—

—

—

33,975

33,975

Bargain purchase gain
—

—

—

—

(7,719
)
(7,719
)
Mark-to-market adjustment - acquisition-related obligations
—

—

—

—

(10,616
)
(10,616
)
Accretion on asset retirement obligations
2,435

—

2,365

—

—

4,800

Amortization of acquired intangibles, net
—

—

—

61,281

—

61,281

Adjusted EBITDA (1) (2)
$
46,404

$
—

$
28,198

$
39,265

$
(18,042
)
$
95,825

(1) The Company’s Adjusted EBITDA calculation has been modified to add back non-cash stock compensation expense and accretion on asset retirement obligations, a non-cash expense, to align with industry peer group methodology.
(2) Pursuant to the PRB divestiture and classification as a discontinued operation, the Company is no longer presenting a PRB reporting segment. The former PRB reporting segment had Adjusted EBITDA of $45,786 for the period from July 26, 2016 to December 31, 2016.


167
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

The following table presents a reconciliation of net (loss) income to Adjusted EBITDA for the period from January 1, 2016 to July 25, 2016:
Predecessor
Period from January 1, 2016 to July 25, 2016
CAPP - Met
CAPP - Thermal
NAPP
Trading and Logistics
All Other
Combined
Net income (loss) from continuing operations
$
(26,407
)
$
—

$
(43,143
)
$
(1,452
)
$
9,461

$
(61,541
)
Interest expense
2

—

—

—

—

2

Interest income
(9
)
—

(10
)
—

—

(19
)
Income tax benefit
—

—

—

—

(39,881
)
(39,881
)
Depreciation, depletion and amortization
15,389

—

49,852

3

832

66,076

Non-cash stock compensation expense
34

—

61

—

498

593

Reorganization items, net
8,196

—

12,528

248

17

20,989

Asset impairment and restructuring
1,667

—

1,408

21

—

3,096

Accretion on asset retirement obligations
1,753

—

3,252

—

—

5,005

Amortization of acquired intangibles, net
—

—

11,567

—

—

11,567

Adjusted EBITDA (1) (2)
$
625

$
—

$
35,515

$
(1,180
)
$
(29,073
)
$
5,887

(1) The Company’s Adjusted EBITDA calculation has been modified to add back non-cash stock compensation expense and accretion on asset retirement obligations, a non-cash expense, to align with industry peer group methodology.
(2) Pursuant to the PRB divestiture and classification as a discontinued operation, the Company is no longer presenting a PRB reporting segment. The former PRB reporting segment had Adjusted EBITDA of $36,819 for the period from January 1, 2016 to July 25, 2016.

No asset information has been provided for these reportable segments as the CODM does not regularly review asset information by reportable segment.

The Company markets produced, processed and purchased coal to customers in the United States and in international markets, primarily India, Brazil, France, Turkey, and the Netherlands. Export coal revenues were the following:
Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Total coal revenues (1)
$
2,020,889

$
1,639,883

$
502,236

$
396,768

Export coal revenues (1) (2)
$
1,671,646

$
1,265,320

$
357,343

$
155,735

Export coal revenues as % of total coal revenues (1)
83
%
77
%
71
%
39
%
(1) Amounts include freight and handling revenues.
(2) The amounts for the year ended December 31, 2018 include $420,919 and $285,120 of export coal revenues, including freight and handling revenues, from external customers in India and Brazil, respectively, recorded within the CAPP - Met, CAPP - Thermal, NAPP, and Trading and Logistics segments. The amounts for the year ended December 31, 2017 include $356,673 of export coal revenues, including freight and handling revenues, from external customers in India, recorded within the CAPP - Met, NAPP, and Trading and Logistics segments. Revenue is tracked within the Company’s accounting records based on the product destination.

( 29 ) Investment in Unconsolidated Affiliate

168
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Dominion Terminal Associates (“DTA”)
On March 31, 2017, the Company acquired a portion of another partner’s interest in DTA for $13,293 thereby increasing its ownership in DTA to sixty-five percent . DTA is reliant upon continuous cash contributions from the partners to fund its operating costs. The Company’s cash contributions totaled $5,253 for the year ended December 31, 2018 . The capital contributions which increase the capital accounts of the respective partners are a form of future subordinated financial support required by DTA to finance its activities. As a result, the Company has concluded DTA does not have sufficient equity investment to finance its activities without the support from the equity partners and is a variable interest entity. Prior to the purchase of the additional interest in DTA, no single party held a majority ownership interest in DTA. After the transaction, there are two remaining owners and Contura holds a sixty-five percent voting ownership interest in DTA. However, two representatives must be present for business to be conducted and consent and unanimous approval of both the members is required for decisions to be taken. Further, there are no provisions that allow either party to override or otherwise unilaterally make a decision. As a result, the Company has concluded that it does not have the power to direct the activities that most significantly impact its economic performance and therefore is not the primary beneficiary. Accordingly, the Company continues to apply the equity method of accounting.
The Company recorded equity method losses, before taxes, from DTA of ($6,112) , ($3,339) , ($2,287) , and ($2,735) for the years ended December 31, 2018 and 2017, the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016, respectively. As of December 31, 2018 and December 31, 2017, the Company’s investment in DTA was $15,236 and $16,095 , respectively, and is recorded within other non-current assets within the Company’s Consolidated Balance Sheets.
Condensed balance sheet information as of December 31, 2018 and December 31, 2017 and condensed income statement information for the years ended December 31, 2018 and 2017 , the period from July 26, 2016 to December 31, 2016, and the period from January 1, 2016 to July 25, 2016 for DTA is presented in the following table:

Successor
December 31, 2018
December 31, 2017
Current assets
$
2,159

$
5,960

Non-current assets
$
59,253

$
59,868

Current liabilities
$
3,103

$
1,530

Non-current liabilities
$
5,694

$
6,476

Partners' equity
$
52,615

$
57,822


Successor
Predecessor
Year Ended December 31, 2018
Year Ended December 31, 2017
Period from July 26, 2016 to December 31, 2016
Period from January 1, 2016 to July 25, 2016
Operating expenses
$
33,518

$
26,893

$
9,792

$
12,271

Other income, net
$
(20,314
)
$
(16,875
)
$
(3,683
)
$
(5,032
)
Total expenses, net
$
13,204

$
10,018

$
6,109

$
7,239

Contributions from partners to fund continuing operations
$
7,997

$
9,302

$
6,243

$
4,883

Expenses (over)/under contributions
$
(5,207
)
$
(716
)
$
134

$
(2,356
)
Depreciation and amortization
$
6,009

$
5,147

$
1,223

$
2,413



169
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

( 30 ) Quarterly Financial Information (Unaudited)

Successor
Year Ended December 31, 2018
First Quarter
Second Quarter (2)
Third Quarter
Fourth Quarter (3)
Total revenues
$
482,332

$
528,918

$
447,871

$
572,084

Net income from continuing operations (1)
58,300

74,642

14,011

155,901

Net (loss) income from discontinued operations
(1,359
)
(854
)
(2,117
)
641

Net income
$
56,941

$
73,788

$
11,894

$
156,542

Weighted average shares - basic
9,548,613

9,625,874

9,633,164

15,014,994

Weighted average shares - diluted
10,292,607

10,306,043

10,384,513

15,822,037

Basic income (loss) per share:
Income from continuing operations
$
6.11

$
7.75

$
1.45

$
10.38

(Loss) income from discontinued operations
(0.15
)
(0.08
)
(0.22
)
0.04

Net income
$
5.96

$
7.67

$
1.23

$
10.42

Diluted (loss) income per share:
Income from continuing operations
$
5.66

$
7.24

$
1.35

$
9.85

(Loss) income from discontinued operations
(0.13
)
(0.08
)
(0.20
)
0.04

Net income
$
5.53

$
7.16

$
1.15

$
9.89

(1) Net income from continuing operations includes merger related costs of $460 , $3,423 , $1,181 , and $46,736 for each of the four quarters of 2018, respectively.
(2) Net income from continuing operations in the second quarter of 2018 includes a gain on sale of a disposal group of ($16,386) within other (income) expense within the Company’s Statements of Operations. See Note 2 for further information.
(3) Net income from continuing operations in the fourth quarter of 2018 includes an income tax benefit of $165,496 . See Note 21 for further information. Additionally, net income from continuing operations in the fourth quarter of 2018 included a loss on modification and extinguishment of debt of ($12,042) .

170
CONTURA ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR
Notes to Consolidated Financial Statements
(Amounts in thousands except share and per share data)

Successor
Year Ended December 31, 2017
First Quarter (2)
Second Quarter
Third Quarter
Fourth Quarter
Total revenues
$
475,119

$
439,668

$
382,537

$
352,645

Net income from continuing operations (1)
$
30,956

$
18,399

$
9,730

$
114,650

Net income (loss) from discontinued operations
$
4,154

$
(5,788
)
$
429

$
(18,008
)
Net income
$
35,110

$
12,611

$
10,159

$
96,642

Weighted average shares - basic
10,309,428

10,309,612

10,277,974

9,971,877

Weighted average shares - diluted
10,728,281

10,874,175

10,896,856

10,583,744

Basic (loss) income per share:
Income from continuing operations
$
3.00

$
1.78

$
0.95

$
11.50

Income (loss) from discontinued operations
$
0.41

$
(0.56
)
$
0.04

$
(1.81
)
Net income
$
3.41

$
1.22

$
0.99

$
9.69

Diluted income (loss) per share:
Income from continuing operations
$
2.89

$
1.69

$
0.89

$
10.83

Income (loss) from discontinued operations
$
0.38

$
(0.53
)
$
0.04

$
(1.70
)
Net income
$
3.27

$
1.16

$
0.93

$
9.13

(1) Net income from continuing operations included a mark-to-market adjustment for acquisition-related obligations of ($4,357) , $6,739 , and $839 in the first three quarters of 2017, respectively, and a gain on the settlement of acquisition-related obligations of ($9,200) and ($29,686) in the second and forth quarters of 2017, respectively. Additionally, net income from continuing operations included secondary offering costs of $942 , $2,496 and $1,061 in the first three quarters of 2017, respectively, related to the withdrawn offering.
(2) Net income from continuing operations included a loss on modification and extinguishment of debt of ($38,701) in the first quarter of 2017.


171

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures as that term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and our Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosures. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In accordance with Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision of our CEO and our CFO, the effectiveness of disclosure controls and procedures as of December 31, 2018. Based on this evaluation, our CEO and our CFO concluded that our disclosure controls and procedures were effective as of December 31, 2018 at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the period covered by this Annual Report on Form 10-K that have materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations on Effectiveness of Disclosure Controls and Procedures

Our Chief Executive Officer, our Chief Financial Officer and other members of management do not expect that our disclosure controls and procedures or our internal control over financial reporting will prevent all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

This Annual Report on Form 10-K does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our registered public accounting firm, pursuant to the transition period established by rules of the SEC for newly public companies.

Item 9B. Other Information

None.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

The sections of our Proxy Statement entitled “Proposal 1 - Election of Directors,” “About our Board of Directors - Board and Its Committees,” “About our Board of Directors - Board Committees - Audit Committee,” “About our Management Team,” “Other Information - Section 16(a) Beneficial Ownership Reporting Compliance”, “About our Board of Directors - Code of Business Ethics” and “Stockholder Proposals for the 2020 Annual Meeting” are incorporated herein by reference.

The Company has a written Code of Business Ethics that applies to the Company’s Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial and Accounting Officer) and others. The Code of Business Ethics is available on the Company’s website at www.conturaenergy.com. Any amendments to, or waivers from, a provision of our Code of Business Ethics that applies to our Principal Executive Officer, Principal Financial and Accounting Officer or persons performing similar functions and that relates to any element of the code of ethics enumerated in paragraph (b) of Item 406 of Regulation S-K shall be disclosed by posting on our website.


172

Item 11. Executive Compensation

The sections of our Proxy Statement entitled “About our Board of Directors - Director Compensation - 2018 Director Compensation,” “Executive Compensation - Compensation Discussion and Analysis,” “Board Committee Reports - Compensation Committee Report,” “Executive Compensation - Compensation Discussion and Analysis - Risk Assessment of Compensation Programs,” “Executive Compensation - 2018 Summary Compensation Table,” “Executive Compensation - 2018 Grants of Plan-Based Awards,” “Executive Compensation - Outstanding Equity Awards at 2018 Fiscal Year End,” “Executive Compensation - Option Exercises and Stock Vested in 2018,” “Executive Compensation - Nonqualified Deferred Compensation,” “Executive Compensation - Potential Payments Upon Termination or Change in Control,” are incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The section of our Proxy Statement entitled “Security Ownership of Certain Beneficial Owners and Management” is incorporated herein by reference.

Equity Compensation Plan Information

The following table sets forth certain information concerning the Company’s equity compensation plans as of December 31, 2018:
Number of securities to be issued upon exercise of outstanding options, warrants and rights
Weighted-average exercise price of outstanding options, warrants and rights
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Plan Category
(a)
(b)
(c)
Equity compensation plans approved by security holders
1,863,951 (1)(2)

$40.47 (4)

868,175 (2)(3)

Equity compensation plans not approved by security holders
—

—

—

Total
1,863,951

$40.47

868,175

(1) Includes shares of our common stock granted under the Management Incentive Plan (the “MIP”), under which awards of restricted stock, RSUs and stock options have been granted, the Long-Term Incentive Plan (the “LTIP”), under which RSUs have been granted, the ANR Inc. 2017 Equity Incentive Plan (the “ANR EIP”), under which RSUs have been granted, and shares granted under the Series A Warrants Agreement.
(2) Includes the employee time-based restricted stock units which may be settled in cash or equity.
(3) The number of shares available for issuance includes 39,895 shares of our common stock under the MIP and 828,280 shares of our common stock under the LTIP.
(4) The weighted average exercise price does not take into account the restricted stock and RSUs.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The sections of our Proxy Statement entitled “About our Board of Directors - Independent and Non-Management Directors” and “Other Information - Review and Approval of Transactions With Related Persons” are incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

The sections of our Proxy Statement entitled “Proposal 4 - Ratification of Appointment of Independent Registered Public Accounting Firm - Independent Registered Public Accounting Firm and Fees” and “Proposal 4 - Ratification of Appointment of Independent Registered Public Accounting Firm - Policy for Approval of Audit and Permitted Non-Audit Services” are incorporated herein by reference.

Additional Information

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You may access and read our SEC filings through our website, at www.conturaenergy.com, or the SEC’s website, at www.sec.gov. You may also request copies of our filings, at no cost, by telephone at (423) 573-0300 or by mail at:

173

Contura Energy, Inc., P.O. Box 848, Bristol, TN 37621, attention: Investor Relations. Our Audit Committee Charter, Compensation Committee Charter, Nominating and Corporate Governance Committee Charter, Corporate Governance Practices and Policies, and Code of Business Ethics are also available on our website and available in print to any stockholder who requests them.

Part IV

Item 15. Exhibits, Financial Statement Schedules

Pursuant to the rules and regulations of the Securities and Exchange Commission, the Company has filed certain agreements as exhibits to this Annual Report on Form 10-K. These agreements may contain representations and warranties by the parties. These warranties have been made solely for the benefit of the other party or parties to such agreements and (i) may been qualified by disclosure made to such other party or parties, (ii) were made only as of the date of such agreements or such other date(s) as may be specified in such agreements and are subject to more recent developments, which may not be fully reflected in such Company’s public disclosure, (iii) may reflect the allocation of risk among the parties to such agreements and (iv) may apply materiality standards different from what may be viewed as material to investors. Accordingly, these representations and warranties may not describe the Company’s actual state of affairs at the date hereof and should not be relied upon.

(a) Documents filed as part of this Annual Report on Form 10-K:

(1) The following financial statements are filed as part of this Annual Report on Form 10-K under Item 8-Financial Statements and Supplementary Data:

•
Report of Independent Registered Public Accounting Firm
•
Consolidated Statements of Operations and Predecessor Combined Statement of Operations, Years ended December 31, 2018 and 2017, Period from July 26, 2016 to December 31, 2016, and Period from January 1, 2016 to July 25, 2016
•
Consolidated Statements of Comprehensive Income (Loss) and Predecessor Combined Statement of Comprehensive Loss, Years ended December 31, 2018 and 2017, Period from July 26, 2016 to December 31, 2016, and Period from January 1, 2016 to July 25, 2016
•
Consolidated Balance Sheets, December 31, 2018 and 2017
•
Consolidated Statements of Cash Flows and Predecessor Combined Statement of Cash Flows, Years ended December 31, 2018 and 2017, Period from July 26, 2016 to December 31, 2016, and Period from January 1, 2016 to July 25, 2016
•
Consolidated Statements of Stockholders’ Equity and Combined Statement of Predecessor Business Equity, Years ended December 31, 2018 and 2017, Period from July 26, 2016 to December 31, 2016, and Period from January 1, 2016 to July 25, 2016
•
Notes to Consolidated Financial Statements

(2) Financial Statement Schedules . All schedules are omitted because they are not required or because the information is immaterial or provided elsewhere in the Consolidated Financial Statements and Notes thereto.

(3) Listing of Exhibits. See the Exhibit Index following the signature page to this Annual Report on Form 10-K.


174

SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CONTURA ENERGY, INC.
Date: April 1, 2019
By:
/s/ Charles Andrew Eidson
Name:
Charles Andrew Eidson
Title:
Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Principal Accounting Officer)
















































175

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Charles Andrew Eidson, and each of them, his or her true and lawful attorneys-in-fact, each with full power of substitution, for him or her in any and all capacities, to sign any amendments to this Annual Report on Form 10-K and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorneys-in-fact or their substitute or substitutes may do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature
Date
Title
/s/ Kevin S. Crutchfield
April 1, 2019
Chief Executive Officer (Principal Executive Officer)
Kevin S. Crutchfield
/s/ Charles Andrew Eidson
April 1, 2019
Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Principal Accounting Officer)
Charles Andrew Eidson
/s/ Neale X. Trangucci
April 1, 2019
Chairman of the Board of Directors
Neale X. Trangucci
/s/ Albert E. Ferrara, Jr.
April 1, 2019
Director
Albert E. Ferrara, Jr.
/s/ Daniel J. Geiger
April 1, 2019
Director
Daniel J. Geiger
/s/ John E. Lushefski
April 1, 2019
Director
John E. Lushefski
/s/ Anthony Orlando
April 1, 2019
Director
Anthony Orlando
/s/ David J. Stetson
April 1, 2019
Director
David J. Stetson
/s/ Harvey L. Tepner
April 1, 2019
Director
Harvey L. Tepner
/s/ Michael Ward
April 1, 2019
Director
Michael Ward


176


Exhibit Index
Exhibit No.
Description of Exhibit
3.1*
3.2*
4.1*
10.1*
10.2*
10.3*
10.4*
10.5*
10.6*
10.7*
10.8*
10.9*
10.10*
10.11*

177

10.12*
10.13*
10.14*
10.15*
10.16*
10.17*
10.18*
10.19*
10.20*
10.21*
10.22*
10.23*
10.24*

178

10.25*
10.26*
10.27*
10.28*
10.29*
10.30*
10.31*
10.32*
10.33*
10.34*
10.35*†
10.36*†
10.37*†
10.38*†
10.39*†
10.40*†
10.41*†
10.42*†

179

10.43*†
10.44*†
10.45*†
10.46*
10.47†
10.48*
Amended and Restated Asset-Based Revolving Credit Agreement, dated as of November 9, 2018, by and among Contura Energy, Inc., as borrower, the other borrowers party thereto, the guarantors party thereto, the lenders from time to time party thereto, Citibank, N.A., as Swingline Lender, Citibank, N.A., Barclays Bank PLC, BMO Harris Bank, N.A., and Credit Suisse AG, Cayman Islands Branch, as L/C Issuers, Citigroup Global Markets Inc., Barclays Bank PLC, BMO Capital Markets Corp. and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers and Joint Bookrunners, the other lenders party thereto and Citibank, N.A., as administrative agent and collateral agent. (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Contura Energy, Inc. (File No. 333-226953) filed on November 13, 2018)
10.49*†
10.50*
10.51*
10.52*
10.53*
10.54*
10.55*†
10.56*†
21.1
23.1
31
32
95
101.INS
XBRL instance document
101.SCH
XBRL taxonomy extension schema
101.CAL
XBRL taxonomy extension calculation linkbase
101.DEF
XBRL taxonomy extension definition linkbase

180

101.LAB
XBRL taxonomy extension label linkbase
101.PRE
XBRL taxonomy extension presentation linkbase

______________
* Previously filed.
† Management contract, compensatory plan or arrangement.






181
TABLE OF CONTENTS
Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsItem 4. Mine Safety DisclosuresPart IIItem 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accounting Fees and ServicesPart IVItem 15. Exhibits, Financial Statement Schedules

Exhibits

3.1* Second Amended and Restated Certificate of Incorporation of Contura Energy, Inc. (Incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-4 of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 3.2* Second Amended and Restated Bylaws of Contura Energy, Inc. (Incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-4 of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 4.1* Specimen Certificate for shares of Common Stock. (Incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-4 of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.1* Amended and Restated Agreement and Plan of Merger, dated as of September 26, 2018, by and among Contura Energy, Inc., Alpha Natural Resources Holdings, Inc., ANR, Inc., Prime Acquisition I, Inc. and Prime Acquisition II, Inc. (Incorporated by reference to Annex A to the proxy statement contained in the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on October 5, 2018) 10.2* Asset Purchase Agreement, dated as of December 7, 2017, by among Blackjewel L.L.C., as purchaser, and Contura Coal West, LLC, Contura Wyoming Land, LLC and Contura Coal Sales, LLC, as seller. (Incorporated by reference to Exhibit 2.2 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.3* Form of Permit Operating Agreement, dated as of December 7, 2017, by among Contura Coal West, LLC, as Transferor and Blackjewel L.L.C., as Transferee (included as Exhibit E to the Asset Purchase Agreement) (Incorporated by reference to Exhibit 2.3 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.4* Form of Royalty Agreement, dated as of December 7, 2017, by among Blackjewel L.L.C., as purchaser, and Contura Coal West, LLC and Contura Wyoming Land, LLC, as seller. (included as Exhibit G to the Asset Purchase Agreement) (Incorporated by reference to Exhibit 2.4 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.5* Asset Purchase Agreement, dated July 26, 2016, among Contura Energy, Inc., Alpha Natural Resources, Inc., certain subsidiaries of Alpha Natural Resources, Inc., ANR, Inc. and Alpha Natural Resources, Inc., as sellers representative. (Incorporated by reference to Exhibit 2.5 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.6* Credit Agreement dated as of March 17, 2017 among Contura Energy, Inc. as Borrower, Jefferies Finance LLC, as Administrative Agent and Collateral Agent, and the Other Lenders Party Thereto (Jefferies Finance LLC, BMO Capital Markets Corp., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC and UBS Securities LLC, as Joint Lead Arrangers and Joint Bookrunners). (Incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.7* First Amendment to Credit Agreement, dated as of June 13, 2017, to the Credit Agreement, dated as of March 17, 2017 among Contura Energy, Inc. as Borrower, Jefferies Finance LLC, as Administrative Agent and Collateral Agent, and the Other Lenders Party Thereto (Incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.8* Asset-Based Revolving Credit Agreement dated as of April 3, 2017 among Contura Energy, Inc., and certain of its Subsidiaries, as the Borrowers; the Guarantors Party Thereto; Citibank, N.A., as Administrative Agent; Citibank, N.A., as Swingline Lender; Citibank, N.A., BMO Harris Bank N.A. and Credit Suisse AG, Cayman Islands Branch, as L/C Issuers; the Other Lenders Party Thereto and Citigroup Global Markets Inc., BMO Capital Markets Corp. and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers and Joint Bookrunners. (Incorporated by reference to Exhibit 10.3 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.9* First Amendment to Asset-Based Revolving Credit Agreement, dated as of June 9, 2017, to the Asset-Based Revolving Credit Agreement dated as of April 3, 2017 among Contura Energy, Inc., and certain of its Subsidiaries, as the Borrowers; the Guarantors Party Thereto; Citibank, N.A., as Administrative Agent; Citibank, N.A., as Swingline Lender; Citibank, N.A., BMO Harris Bank N.A. and Credit Suisse AG, Cayman Islands Branch, as L/C Issuers; the Other Lenders Party Thereto and Citigroup Global Markets Inc., BMO Capital Markets Corp. and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers and Joint Bookrunners. (Incorporated by reference to Exhibit 10.4 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.10* Loan Agreement dated as of July 26, 2016 by and between ANR, Inc. as Borrower; the Guarantors Party Thereto and Contura Energy, Inc. as Lender. (Incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.11* Registration Rights Agreement, dated as of July 26, 2016, by and among Contura Energy, Inc. and the holders party thereto. (Incorporated by reference to Exhibit 10.6 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.12* Amendment No. 1 to the Registration Rights Agreement, dated as of February 24, 2017, by and among Contura Energy, Inc. and the holders party thereto. (Incorporated by reference to Exhibit 10.7 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.13* Amendment No. 2 to the Registration Rights Agreement, dated as of October 10, 2017, by and among Contura Energy, Inc. and the holders party thereto. (Incorporated by reference to Exhibit 10.8 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.14* Amendment No. 3 to the Registration Rights Agreement, dated as of June 1, 2018, by and among Contura Energy, Inc. and the holders party thereto. (Incorporated by reference to Exhibit 10.9 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.15* Settlement Agreement, dated November 3, 2016 but effective only as of the Settlement Effective Time, by and among Contura Energy, Inc., for itself and on behalf of certain of its subsidiaries; ANR, Inc., for itself and on behalf of certain of its affiliates and Old ANR, Inc. (f/k/a Alpha Natural Resources, Inc.) on behalf of itself and on behalf of all of the sellers in its capacity as sellers representative. (Incorporated by reference to Exhibit 10.10 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.16* Reclamation Funding Agreement, dated July 12, 2016, by and among Alpha Natural Resources, Inc., on behalf of itself and its debtor-affiliates; Contura Energy, Inc.; the Illinois Department of Natural Resources; the Kentucky Energy and Environment Cabinet, Department for Natural Resources; the United States Department of the Interior, Office of Surface Mining, Reclamation and Enforcement, in its capacity as the regulatory authority over surface mining operations in the State of Tennessee; the Virginia Department of Mines, Minerals and Energy and the West Virginia Department of Environmental Protection. (Incorporated by reference to Exhibit 10.11 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.17* Amended Reclamation Funding Agreement dated October 23, 2017, by and among ANR, Lexington Coal Company, LLC, Contura, the Illinois Department of Natural Resources, the Kentucky Energy and Environment Cabinet Department for Natural Resources, the United States Department of the Interior, Office of Surface Mining, Reclamation and Enforcement (in its capacity as the regulatory authority over surface mining operations in the State of Tennessee), the Virginia Department of Mines, Minerals and Energy and the WVDEP. (Incorporated by reference to Exhibit 10.12 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.18* Settlement Agreement, dated July 12, 2016, by and among Alpha Natural Resources, Inc., on behalf of itself and its debtor-affiliates; Contura Energy, Inc.; Citicorp North America, Inc. and the United States Department of the Interior, on behalf of the Office of Surface Mining, Reclamation and Enforcement, including in its capacity as the regulatory authority over surface mining operations in the State of Tennessee, the Office of Natural Resources Revenue and the Bureau of Land Management. (Incorporated by reference to Exhibit 10.13 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.19* Permitting and Reclamation Plan Settlement Agreement for the Commonwealth of Kentucky, dated July 12, 2016, by and among Alpha Natural Resources, Inc., on behalf of itself and its debtor-affiliates; Contura Energy, Inc. and the Kentucky Energy and Environment Cabinet, Department for Natural Resources. (Incorporated by reference to Exhibit 10.14 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.20* Termination Agreement dated October 23, 2017, by and among Alpha Natural Resources, on behalf of itself and its affiliates, Contura Energy, Inc. and the Kentucky Energy and Environmental Cabinet, Department for Natural Resources. (Incorporated by reference to Exhibit 10.15 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.21* Permitting and Reclamation Plan Settlement Agreement for the State of Illinois, dated July 12, 2016, by and among Alpha Natural Resources, Inc., on behalf of itself and its debtor-affiliates; Contura Energy, Inc. and the Illinois Department of Natural Resources. (Incorporated by reference to Exhibit 10.16 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.22* First Amendment to Permitting and Reclamation Plan Settlement Agreement for the State of Illinois by and among Alpha Natural Resources, Inc., on behalf of itself and its affiliates, Contura and Illinois Department of Natural Resources. (Incorporated by reference to Exhibit 10.17 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.23* Permitting and Reclamation Plan Settlement Agreement for the Commonwealth of Virginia, dated July 12, 2016, by and among Alpha Natural Resources, Inc., on behalf of itself and its debtor-affiliates; Contura Energy, Inc. and the Commonwealth of Virginia, Department of Mines, Minerals and Energy. (Incorporated by reference to Exhibit 10.18 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.24* First Amendment to Permitting and Reclamation Plan Settlement Agreement for the Commonwealth of Virginia dated October 23, 2017, by and among ANR, on behalf of itself and its affiliates, including Old ANR, LLC (f/k/a Alpha Natural Resources, Inc.), Contura and the Virginia Department of Mines, Minerals and Energy. (Incorporated by reference to Exhibit 10.19 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.25* Permitting and Reclamation Plan Settlement Agreement for the State of West Virginia, dated July 12, 2016, by and among Alpha Natural Resources, Inc., on behalf of itself and its debtor-affiliates; Contura Energy, Inc. and the West Virginia Department of Environmental Protection. (Incorporated by reference to Exhibit 10.20 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.26* First Amendment to Permitting and Reclamation Plan Settlement Agreement for the State of West Virginia, dated July 25, 2016, by and among Alpha Natural Resources, Inc., on behalf of itself and its debtor-affiliates; Contura Energy, Inc. and the West Virginia Department of Environmental Protection. (Incorporated by reference to Exhibit 10.21 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.27* Second Amendment to Permitting and Reclamation Plan Settlement Agreement for the State of West Virginia, dated October 23, 2017, by and among Alpha Natural Resources, Inc., on behalf of itself and its debtor-affiliates; Contura Energy, Inc. and the West Virginia Department of Environmental Protection. (Incorporated by reference to Exhibit 10.22 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.28* Stipulation Regarding Water Treatment Obligations, dated July 12, 2016, by and among Alpha Natural Resources, Inc., on behalf of itself and its debtor-affiliates; Contura Energy, Inc. and the United States. (Incorporated by reference to Exhibit 10.23 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.29* Amended Stipulation Regarding Water Treatment Obligations, dated October 23, 2017, by and among Alpha Natural Resources, Inc., on behalf of itself and its debtor-affiliates, Lexington Coal Company, LLC, Contura Energy, Inc. and the United States. (Incorporated by reference to Exhibit 10.24 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.30* Stipulation and Agreed Order dated July 15, 2016 among Alpha Natural Resources, Inc., et al., as Debtors; Citicorp North America, as administrative and collateral agent; Contura Energy, Inc. and the Retiree Settlement Committee. (Incorporated by reference to Exhibit 10.25 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.31* Stipulation and Agreed Order dated July 6, 2016 among Alpha Natural Resources, Inc., et al., as Debtors; Citicorp North America, as administrative and collateral agent; Contura Energy, Inc. and the UMWA Funds. (Incorporated by reference to Exhibit 10.26 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.32* Agreement to Fund VEBA, dated July 5, 2016, by and among Contura Energy, Inc., on behalf of itself and as authorized agent for certain of its subsidiaries, and the United Mine Workers of America. (Incorporated by reference to Exhibit 10.27 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.33* Form of Indemnification Agreement by and between Contura Energy, Inc. and each of its current and future directors and officers. (Incorporated by reference to Exhibit 10.28 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.34* Warrant Agreement, dated July 26, 2016, between Contura Energy, Inc., Computershare, Inc. and Computershare Trust Company, N.A. (including Form of Warrant Certificate). (Incorporated by reference to Exhibit 10.29 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.35* Employment Agreement, dated July 26, 2016 by and between Contura Energy, Inc. and Kevin S. Crutchfield. (Incorporated by reference to Exhibit 10.35 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.36* Contura Energy, Inc. Management Incentive Plan, effective as of July 26, 2016. (Incorporated by reference to Exhibit 10.36 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.37* Amendment 1 to Contura Energy, Inc. Management Incentive Plan, dated as of January 18, 2017. (Incorporated by reference to Exhibit 10.37 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.38* Form of Contura Energy, Inc. Option Agreement. (Incorporated by reference to Exhibit 10.38 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.39* Form of Contura Energy, Inc. Restricted Share Agreement. (Incorporated by reference to Exhibit 10.39 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.40* Form of Contura Energy, Inc. Emergence Award Agreement. (Incorporated by reference to Exhibit 10.40 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.41* Contura Energy, Inc. Deferred Compensation Plan. (Incorporated by reference to Exhibit 10.41 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.42* Contura Energy, Inc. Annual Incentive Bonus Program. (Incorporated by reference to Exhibit 10.42 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.43* Contura Energy, Inc. Key Employee Separation Plan, effective as of July 26, 2016. (Incorporated by reference to Exhibit 10.43 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.44* Contura Energy, Inc. Amended and Restated Non-Employee Director Compensation Policy, dated December 14, 2017. (Incorporated by reference to Exhibit 10.44 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.45* Form of 2018 Long-Term Incentive Plan. (Incorporated by reference to Exhibit 10.45 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on August 21, 2018) 10.46* Form of Voting and Support Agreement. (Incorporated by reference to Exhibit 10.46 to the Registration Statement on Form S-4/A of Contura Energy, Inc. (File No. 333-226953) filed on October 5, 2018) 10.47 Form of Performance Stock Unit Award Agreement. 10.48* Amended and Restated Asset-Based Revolving Credit Agreement, dated as of November 9, 2018, by and among Contura Energy, Inc., as borrower, the other borrowers party thereto, the guarantors party thereto, the lenders from time to time party thereto, Citibank, N.A., as Swingline Lender, Citibank, N.A., Barclays Bank PLC, BMO Harris Bank, N.A., and Credit Suisse AG, Cayman Islands Branch, as L/C Issuers, Citigroup Global Markets Inc., Barclays Bank PLC, BMO Capital Markets Corp. and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers and Joint Bookrunners, the other lenders party thereto and Citibank, N.A., as administrative agent and collateral agent. (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Contura Energy, Inc. (File No. 333-226953) filed on November 13, 2018) 10.49* Form of Indemnification Agreement. (Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Contura Energy, Inc. (File No. 333-226953) filed on November 13, 2018) 10.50* Amended and Restated Credit Agreement, dated as of November 9, 2018, by and among Contura Energy, Inc., as the Initial Borrower, the lenders from time to time party thereto, Jefferies Finance LLC, as administrative agent and collateral agent, and Jefferies Finance LLC, Barclays Capital, Inc., BMO Capital Markets Corp., Citigroup Global Markets Inc., Clarksons Platou Securities, Inc. and B. Riley FBR, Inc., as Joint Lead Arrangers and Joint Bookrunners (Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Contura Energy, Inc. (File No. 333-226953) filed on November 13, 2018) 10.51* Amended and Restated Pledge and Security Agreement, dated as of November 9, 2018, by and among Contura Energy, Inc. and the subsidiaries of Contura Energy, Inc. that are grantors thereunder, and Citibank, N.A., as collateral agent. (Incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Contura Energy, Inc. (File No. 333-226953) filed on November 13, 2018) 10.52* Amended and Restated Pledge and Security Agreement, dated as of November 9, 2018, by and among Contura Energy, Inc. and the subsidiaries of Contura Energy, Inc. that are grantors thereunder, and Jefferies Finance LLC, as collateral agent. (Incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Contura Energy, Inc. (File No. 333-226953) filed on November 13, 2018) 10.53* Amended and Restated Guaranty Agreement, dated as of November 9, 2018, by and among subsidiaries of Contura Energy, Inc. that are guarantors party thereto and Jefferies Finance LLC, as administrative agent. (Incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K of Contura Energy, Inc. (File No. 333-226953) filed on November 13, 2018) 10.54* Term Sheet dated as of November 6, 2018 by and amongst ANR, Inc., Alpha Natural Resources Holdings, Inc., Contura Energy, Inc. and the West Virginia Department of Environmental Protection (Incorporated by reference to Exhibit 10.7 to the Current Report on Form 8-K of Contura Energy, Inc. (File No. 333-226953) filed on November 13, 2018) 10.55* Contura Energy, Inc. Form of Non-Employee Director Restricted Stock Unit Award Agreement (Incorporated by reference to Exhibit 10.8 to the Current Report on Form 8-K of Contura Energy, Inc. (File No. 333-226953) filed on November 13, 2018) 10.56* Contura Energy, Inc. Form of Restricted Stock Unit Award Agreement (For Employees) (Incorporated by reference to Exhibit 10.9 to the Current Report on Form 8-K of Contura Energy, Inc. (File No. 333-226953) filed on November 13, 2018) 21.1 List of Subsidiaries of Contura Energy, Inc. 23.1 Consent of KPMG LLP 31 Certifications Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to 302 of the Sarbanes-Oxley Act of 2002 32 Certifications Pursuant to 18 U.S.C. 1350, As Adopted Pursuant to 906 of the Sarbanes-Oxley Act of 2002 95 Mine Safety Disclosure