S-1 1 conturas-1.htm S-1 Document


As filed with the Securities and Exchange Commission on May 8, 2017.
Registration No. 333-        
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549  
Form S-1
REGISTRATION STATEMENT
Under
THE SECURITIES ACT OF 1933 
CONTURA ENERGY, INC.
(Exact Name of Registrant as Specified in its Charter)
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
 
1221
(Primary Standard Industrial
Classification Code Number)
 
81-3015061
(I.R.S. Employer
Identification Number)
Contura Energy, Inc.
340 Martin Luther King Jr. Blvd.
Bristol, Tennessee 37620
(423) 573-0300
(Address, including zip code and telephone number, including
area code, of registrant’s principal executive offices)
Kevin S. Crutchfield
Chief Executive Officer
Contura Energy, Inc.
340 Martin Luther King Jr. Blvd.
Bristol, Tennessee 37620
(423) 573-0300
(Name, address, including zip code and telephone number, including
area code, of agent for service)
Copies to:
Byron B. Rooney
Shane Tintle
Davis Polk & Wardwell LLP
450 Lexington Avenue
New York, New York 10017
Telephone: (212) 450-4000
Facsimile: (212) 701-5800
 
Mark M. Manno
 Executive Vice President, General Counsel
Contura Energy, Inc.
340 Martin Luther King Jr. Blvd.
Bristol, Tennessee 37620
Telephone: (423) 573-0300
Facsimile: (423) 573-0446
 
Ryan J. Maierson
John M. Greer
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, Texas 77002
Telephone: (713) 546-5400
Facsimile: (713) 546-5401
Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ☐
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
Large accelerated filer
☐
 
Accelerated filer
☐
Non-accelerated filer
☒
 
Smaller reporting company
☐
(Do not check if a smaller reporting company)
 
 
Emerging growth company
☐
 
If an emerging growth company, indicate by check mark if the registrant has not elected to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☐
CALCULATION OF REGISTRATION FEE
 
Title of Each Class of Securities
to be Registered
Proposed Maximum
Aggregate Offering
Price(1)(2)
Amount of
Registration Fee
Common Stock, $0.01 par value
$100,000,000
$11,590
(1)
Estimated pursuant to Rule 457(o) under the Securities Act of 1933, as amended.
(2)
Includes the aggregate offering price of additional shares that the underwriters have the option to purchase.
The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to such Section 8(a), may determine.



The information in this preliminary prospectus is not complete and may be changed. The securities described herein may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities, in any state or jurisdiction where the offer or sale is not permitted.
SUBJECT TO COMPLETION, DATED MAY 8, 2017

PRELIMINARY PROSPECTUS
                       Shares
conturaa01.jpg
Contura Energy, Inc.
Common Stock

This is the initial public offering of                  shares of common stock of Contura Energy, Inc. All of the shares of common stock are being offered by the selling stockholders identified in this prospectus. We will not receive any of the proceeds from the shares of common stock being sold in this offering.
This is our initial public offering, and we anticipate that the initial public offering price will be between $          and $          per share. We intend to apply to list our common stock on the New York Stock Exchange under the symbol “CTRA.”
The underwriters have the option, exercisable within 30 days from the date of this prospectus, to purchase up to an additional                  shares from the selling stockholders at the public offering price less the underwriting discount and commissions, solely to cover over-allotments.
Investing in our common stock involves risks. See “Risk Factors” beginning on page 13.
Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.
 
Price to Public
 
Underwriting
Discounts and
Commissions (1)
 
Proceeds, before
expenses, to Selling Stockholders
Per Share
 
$
 
 
 
$
 
 
 
$
 
Total
 
$
 
 
 
$
 
 
 
$
 
______________
(1)
See “Underwriting” for additional information regarding underwriting compensation.
The underwriters expect to deliver the shares to purchasers on or about          , 2017 through the book-entry facilities of The Depository Trust Company.
Citigroup
          , 2017



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TABLE OF CONTENTS
 
Page

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______________
We, the selling stockholders and the underwriters have not authorized anyone to provide any information or to make any representations other than that contained in this prospectus or in any free writing prospectus prepared by or on behalf of us or to which we have referred you. We, the selling stockholders and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may provide you. Neither we, the selling stockholders nor the underwriters are making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of shares of our common stock. The information in any free writing prospectus that we may provide to you in connection with this offering is accurate only as of the date of such free writing prospectus. Our business, financial condition, results of operations and future growth prospects may have changed since those dates. This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Special Note Regarding Forward-Looking Statements.”
______________
Unless the context requires otherwise: (a) references to “Contura,” our “company,” “we,” “us” or “our” refer to Contura Energy, Inc., a Delaware corporation, and its consolidated subsidiaries, and, where appropriate in context, the business set forth on a carve-out basis using Alpha’s historical basis in our assets, liabilities and operating results while under Alpha’s ownership, as acquired in connection with the Alpha Restructuring on July 26, 2016; (b) references to “Alpha” refer to Alpha Natural Resources, Inc., a Delaware corporation, and its consolidated subsidiaries and (c) references to “selling stockholders” refer to those entities identified as selling stockholders in “Principal and Selling Stockholders.”
We have provided definitions for some of the other industry terms used in this prospectus in the “Glossary” included elsewhere in this prospectus. Tonnage amounts in this prospectus are stated in short tons, unless otherwise indicated.
References to 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. References to our “T&L” coal volumes solely include those volumes purchased from third-party producers and sold through our Trading and Logistics business.
______________
Market and Industry Data and Forecasts
The data included in this prospectus regarding the coal industry, including descriptions of trends in the market, as well as our position within the industry, is based on a variety of sources, including independent industry publications, third-party studies, government publications and other published independent sources, including the U.S. Energy Information Administration, Bloomberg L.P., BP Statistical Review, the American Coalition for Clean Coal Electricity and Wood Mackenzie, none of which are affiliated with us, as well as information obtained from customers, distributors, suppliers, trade and business organizations and publicly available information, as well as our good faith estimates, which have been derived from management’s knowledge and experience in our industry. Although we believe the industry and market data to be reliable as of the date of this prospectus, this information could prove to be inaccurate. Industry and market data could be wrong because of the method by which sources obtained their data and because information cannot always be verified with complete certainty due to the limits on the availability and reliability of raw data, the voluntary nature of the data gathering process and other limitations and uncertainties. We, the selling stockholders and the underwriters do not know all of the assumptions regarding general economic conditions or growth that were used in preparing the forecasts from the sources relied upon or cited herein. Assumptions and estimates of our and our industry’s future performance are necessarily subject to a high degree of uncertainty and risk due to a variety of factors, including those described in “Risk Factors” and “The Coal Industry.” These and other factors could cause future performance to differ materially from our assumptions and estimates.

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Coal Reserve Information
The estimates of our proven and probable reserves as of December 31, 2016 included in this prospectus were prepared by Marshall Miller & Associates, Inc., an independent mining and geological consulting firm (“MM&A”). The estimates of our proven and probable reserves 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 testing 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 U.S. Securities and Exchange Commission’s 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.
Please read “Business—Coal Reserves” for additional information regarding our reserves.
Non-GAAP Financial Measures
The prospectus contains “non-GAAP financial measures” that 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.”
Adjusted EBITDA represents net income (loss) before:
•
Interest expense (income);
•
Income tax benefit;
•
Depreciation, depletion and amortization;
•
Mark-to-market adjustment for warrant derivative liability;
•
Bargain purchase gain;
•
Mark-to-market adjustment for acquisition-related obligations;
•
Amortization of acquired intangibles, net;
•
Reorganization items, net;

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•
Asset impairment and restructuring charges;
•
Goodwill impairment; and
•
Mark-to-market adjustment for other derivatives.
We also make use of the non-GAAP financial measures “CIB Free Cash Flow,” “CIB Cost of Coal Sales per Ton Sold” and “CIB SG&A Expense,” which are used to measure compensation performance. See “Executive Compensation–Performance Metrics.”
Adjusted EBITDA, CIB Free Cash Flow, CIB Cost of Coal Sales per Ton Sold and CIB SG&A Expense are not recognized terms under GAAP. Adjusted EBITDA does not purport to be an alternative to net income (loss) as a measure of operating performance. CIB Free Cash Flow does not purport to be an alternative to net income (loss) as a measure of liquidity. CIB Cost of Coal Sales per Ton Sold does not purport to be an alternative to Cost of Coal Sales per Ton. CIB SG&A Expense does not purport to be an alternative to Selling, General and Administrative Expenses. The presentations of these measures have limitations as analytical tools and should not be considered in isolation, or as a substitute for analysis of our results as reported under GAAP. Management compensates for the limitations of using non-GAAP financial measures by using them 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.

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PROSPECTUS SUMMARY
This summary highlights selected information contained elsewhere in this prospectus and does not contain all of the information you should consider in making your investment decision. Before investing in our common stock, you should carefully read this entire document, including our combined historical and pro forma financial statements and accompanying notes included elsewhere in this prospectus. You should also carefully consider, among other things, the matters discussed under “Risk Factors,” “Special Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Our Business
We are a large-scale, diversified provider of metallurgical (“met”) and steam coal to a global customer base. We operate high-quality, cost-competitive coal mines across three major U.S. coal basins complemented by a robust Trading and Logistics business. Our portfolio of mining operations consists of six mining complexes, comprised of nine underground mines, four surface mines and four coal preparation plants. In 2016, we sold 4.0 million tons of met coal from mines in Central Appalachia (“CAPP”) and Northern Appalachia (“NAPP”) and 41.1 million tons of steam coal from mines in CAPP, NAPP and the Powder River Basin (“PRB”). To supplement our mining operations, we operate a Trading and Logistics business that focuses on the sale of third-party coal into the international market. From the acquisition of our assets on July 26, 2016, through December 31, 2016, our Trading and Logistics business sold 1.5 million tons of met coal. A strategic cornerstone of this business is our 65.0% interest in Dominion Terminal Associates (“DTA”), a coal export terminal. 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.
Our assets create a strong, diversified operational footprint and have the ability to generate cash flows across many different pricing environments. Our met coal business, together with our Trading and Logistics business, is expected to sell 7.7 million tons of coal in 2017. In addition to our operating met coal mines, we have three potential development projects that are primarily focused on met coal and provide opportunities for incremental production growth. Our steam portfolio is anchored by our Cumberland mine, which is expected to be in the first quartile of the 2018 NAPP coal basin “Operating Margin” curve for U.S. producers, according to Wood Mackenzie. A substantial portion of our steam coal, including from our PRB operations, is sold under long-term contracts (typically ranging from one year to five years), providing us with significant sales visibility.
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 CAPP coal basin, we predominantly produce low-ash and low-sulfur met coal, including high volatile A (“High-Vol. A”), high volatile B (“High-Vol. B”), middle volatile (“Mid-Vol.”), and specialty coals, which are shipped to domestic and international steel producers. In the NAPP coal basin, we produce high-BTU steam coal, as well as some High-Vol. B met coal. In the PRB coal basin, we produce low-sulfur steam coal from large surface mining operations. Our steam coal is primarily sold to the domestic power generation industry.
We have a substantial reserve base of over 1.0 billion tons of proven reserves and approximately 310 million tons of probable reserves, which results in an average remaining mine life of approximately 30 years based on our 2016 production levels. Our reserve base in CAPP consists of 71 million tons of proven and 22 million tons of probable reserves across the three mining complexes, of which substantially all is met coal. Our reserve base in NAPP consists of 326 million tons of proven and 279 million tons of probable reserves, of which approximately 7% is met coal, with substantially all of the remaining reserves principally characterized as high-BTU, Pittsburgh 8 seam steam coal. In the PRB, we have 614 million tons of proven and 10 million tons of probable low-sulfur steam coal reserves.

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Our Operations
Our CAPP operations consist of three cost-competitive, high-quality met coal mining complexes: Toms Creek, McClure and Nicholas. According to Wood Mackenzie, in 2018, our met coal platform is expected to be positioned in the second quartile among domestic met producers based on “Operating Margin” as defined by Wood Mackenzie. From the acquisition of our assets on July 26, 2016 until December 31, 2016, our CAPP met coal quality was composed of 43.6% Mid-Vol., 39.7% High-Vol. A and 16.7% High-Vol. B. During this time period, we shipped approximately two-thirds of our met coal production from our CAPP operations internationally to customers in Europe, Asia and the Americas, with the remaining met production sold into the domestic market.
Our NAPP operations consist of the large-scale, high-margin and high-quality Cumberland coal mining complex. Cumberland is located in Greene County, Pennsylvania and operates one highly efficient longwall mine 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. According to Wood Mackenzie, Cumberland is expected to be in the first quartile for “Operating Margin” in 2018 among domestic steam coal producers in the NAPP coal basin. We are also able to sell part of our Cumberland coal production (0.4 million tons in 2016) into the met coal market as High-Vol. B, achieving higher realized pricing than if sold as steam 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. As of April 21, 2017, 100% of our anticipated 2017 production in NAPP was committed and priced.
Our PRB operations consist of the Belle Ayr and Eagle Butte mines. Our production from these mines is sold primarily to a well-established 8,400 to 8,600 BTU-specific market. Historically, the 8,400 to 8,600 BTU market has consisted of base load power generation plants and demand has been stable. A total of 34 million tons of steam coal was shipped from these two mines in 2016, primarily to utilities located in the western, midwestern and southern United States. Belle Ayr produces extremely low-sulfur coal that receives a premium to 8,400 BTU coal prices due to its high heat and low-sulfur content. Eagle Butte is expected to be in the first quartile for “Total Cash Costs” in 2018 among producers in the PRB, according to Wood Mackenzie. Our PRB mines historically have entered into long-term contracts with customers, which provide us with significant sales visibility. As of April 21, 2017, 93% of our anticipated 2017 production in the PRB was committed and priced.
Our Trading and Logistics business purchases met coal from domestic producers and sells into international markets. A strategic cornerstone of our Trading and Logistics business is our interest in the DTA coal export terminal. We recently 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 terminal fees, overhead and profit when purchasing third-party coal. Additionally, we sell capacity to third-party operators via throughput contracts. The Trading and Logistics business provides access to international markets and further diversifies our revenue sources.
For the year ended December 31, 2016, on a pro forma basis, we:
•
Sold 46.7 million tons (12% met coal and 88% steam coal);
•
Generated coal revenue of $1,150 million (40% met coal, 60% steam coal) and total revenue of $1,297 million; and
•
Generated net loss of $64.9 million and Adjusted EBITDA of $176.9 million.

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For the definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Summary Historical Consolidated Financial Data—Other Financial and Operating Data.”
Competitive Strengths
We believe we are well-positioned to execute our business strategies because we possess the following competitive strengths:
Diversified provider with a broad footprint of large scale met and steam coal operations. Our operational footprint consists of thirteen coal mines and four preparation plants in three major coal basins in the U.S.: CAPP, NAPP and the PRB. We operate as a “three-pronged” business: (i) met coal platform primarily in CAPP, (ii) steam coal platform largely in NAPP and PRB and (iii) a Logistics and Trading platform that owns a 65.0% interest in the DTA coal export terminal. Our cost-competitive, high-quality met coal platform in CAPP has 94 million tons of proven and probable reserves as well as meaningful production growth opportunities. Our steam platform has 1,186 million tons of proven and probable coal reserves. In addition, we have also 44 million tons of proven and probable reserves of met coal in NAPP. The steam platform is anchored by our flagship Cumberland mine in NAPP and includes our cost-competitive PRB portfolio. Through our Trading and Logistics business, we sell various types of met coal, which allows us to meet the needs of our broad customer base of international steel producers. We benefit from strong customer relationships, and our operations have supplied many of our top customers continuously over the past decade.
A leading provider of met coal with high operating margins. We operate three high-quality, cost-competitive met coal complexes in Virginia and West Virginia – Toms Creek, McClure and Nicholas. Our high-quality met coal product is an important component within our customers’ overall coking coal requirements. Our complexes produce high-quality Mid-Vol., High-Vol. and specialty met coals known for low-ash and sulfur content. In 2017, we expect to sell 3.9 million tons of met coal from mines in CAPP, 0.3 million tons from mines in NAPP and supply 3.5 million tons through our Trading and Logistics business. We believe our 2017 expected sales volume positions us to be the third largest provider of met coal in the United States. As of December 31, 2016, our CAPP operations had a significant reserve base composed of 71 million tons of proven and 22 million tons of probable reserves of met coal. Our consolidated met portfolio is estimated to hold a second quartile position based on 2018 “Operating Margin,” as defined by Wood Mackenzie, among U.S. met producers. The quality of our met coal, coupled with the cost-competitive position of these assets, allows us to maximize operating margins throughout different met coal price environments.
Highly efficient steam coal operations with strong contract visibility. Our steam coal operations are anchored by our flagship Cumberland mine in NAPP and include our cost-competitive mines in the PRB. Our mines produce steam coal that is highly sought after by domestic utilities. In NAPP, we produce Pittsburgh 8 seam steam coal, a well-known product to utilities in several different markets. Our Cumberland mine is estimated to hold a first quartile “Operating Margin” position in 2018 among domestic NAPP steam producers, according to Wood Mackenzie. Our Belle Ayr and Eagle Butte mines in Wyoming are highly efficient surface mine operations that benefit from mining 75 foot and 100 foot seams, respectively. Belle Ayr-produced coal typically receives a premium to 8,400 BTU PRB coal prices due to its high-heat and low-sulfur content. Coal mined at our PRB mines can be sold 100% raw with no washing necessary. In 2017, we expect to sell 31.5 million tons of steam coal in the PRB, 7.9 million tons in NAPP and 0.1 million tons in CAPP. As of April 21, 2017, we had contracted favorable pricing of our PRB portfolio for nearly 30 million tons at $11.34 per ton. In addition, we have contracted 7.9 million tons from our NAPP portfolio at $42.40 per ton. We enter into long-term supply agreements, typically ranging from one to five years, to contract our steam coal production in advance, thereby reducing the risks associated with our steam coal portfolio in future years. As of April 21, 2017, 94% of our expected steam production is already committed and priced for 2017. The table below outlines our current committed and priced volumes from 2017 to 2020, showing the degree of visibility into our future sales of steam coal.


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2017-2020 Steam Coal Committed and Priced Volume by Basin as of April 21, 2017
Segment (tons in millions)
2017
2018
2019
2020
NAPP
7.9
4.1
2.5
2.0
PRB
29.3
15.9
7.2
4.5
Flexible Trading and Logistics business enhances strategic positioning and provides global customer access. Our Trading and Logistics business enhances the variety of coal products available for us to service export customers in the Americas, Europe and Asia, while also providing us with strategic East Coast port access. Through our 65.0% ownership of DTA, we have approximately 14 million tons of export capacity and guaranteed low-cost port access for our coal. DTA is a key pillar of our strategy to cater to the export met coal market. This facility complements our met operations by blending captive and third-party coal to achieve a broader portfolio of coal qualities. We typically build in margin for terminal fees, overhead, and profit when purchasing third-party coal. Additionally, we sell capacity via throughput contracts to third-party operators. Our Trading and Logistics Operations provide access to international markets and further diversify our revenue sources.
Scalable platform for organic growth and strategically positioned to take advantage of value-added acquisition opportunities. We believe our strong financial characteristics and geographic positioning provide us with the ability to execute on a variety of strategic opportunities, both organic and inorganic. We have identified several organic met coal growth opportunities that can be developed in supportive pricing environments, including:
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Jerry Fork extension in CAPP, which could provide an incremental 0.2-0.3 million tons per year of High-Vol. B met coal;
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Deep Mine #42 in CAPP, which could provide an incremental 1.0-1.5 million tons per year of High-Vol. A and Mid-Vol. met coal; and
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Freeport mine in NAPP, which could provide an incremental 2.5-3.5 million tons per year of primarily High-Vol. B met coal, with some steam coal as byproduct.
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.
Well-capitalized balance sheet with minimal legacy liabilities to support execution of our business plan. Our balance sheet reflects minimal legacy liabilities or post-retirement benefit obligations and no pension obligations. In the first quarter of 2017, we took steps to strengthen our balance sheet by extending the maturity of our debt and lowering our overall borrowing costs. We entered into a $125.0 million asset-based revolving credit facility, which was undrawn at closing, and a new $400.0 million term loan to retire high-cost indebtedness and improve our capital structure. Our conservative balance sheet and low leverage allow us to operate our business effectively throughout the market cycle.
Proven and experienced management team with a primary focus on safety and environmental stewardship. Our management team has extensive knowledge of the coal mining industry as well as intimate operational knowledge of our assets. Our core management team brings over 17 years on average in the coal industry and over 9 years on average of experience managing and operating our assets. This management team has prioritized a focus on safe mining practices at its operations. Our safety process involves all employees in accident prevention and situational awareness and observation, changing behaviors and continuous improvement of mine safety conditions. We also believe that environmental stewardship is integral to safe, productive and cost-efficient mining operations. As a result, our mining operations have consistently earned recognition for outstanding safety and environmental performance, including numerous local, state and national awards.

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Business Strategies
Our business objectives are to increase shareholder value and drive cash flow generation across various pricing environments by sustaining a cost-competitive, diversified operational asset portfolio. Our key strategies to achieve these objectives are described below:
Promote excellence in safety and environmental stewardship. We believe safety is the bedrock upon which our culture and success are built. By implementing a behavior-based safety process, every employee is empowered to engage in the elimination of at-risk behaviors in the workplace, and to be accountable not only for their own safety, but for the safety of those around them. We intend to operate safely and achieve environmental excellence. Minimizing workplace incidents and environmental violations improves our operating efficiency, which in turn improves our cost structure and financial performance.
Rigorously seek opportunities to expand domestic and international sales while maintaining relationships with long-standing customer base. Through our operations and reserves in three 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 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, Turkey and Brazil. Additionally, we remain focused on advancing our Trading and Logistics business to procure coal from additional sources to expand sales to potential international customers. Combined with our strong international customer relationships and logistics expertise, our recent acquisition of an incremental 24.4% capacity at DTA further enhances our ability to grow our Trading and Logistics business.
Opportunistically expand met coal production capacity depending on market dynamics. We carefully evaluate opportunities to expand productive capacity at our met mines depending on current and projected met coal market dynamics. Our ability to leverage existing infrastructure and the embedded growth potential at our mining complexes to expand adjacent facilities and production provides a platform for expansion as market conditions allow. We expect our conservatively levered balance sheet and strong cash flow generation to provide us the ability to execute on these opportunities.
Continuously evaluate strategic opportunities to acquire complementary high-quality coal assets or enter strategic alliances. Our experienced management team continues to analyze acquisitions, joint ventures and other opportunities that would be accretive and synergistic to our existing asset portfolio. For example, given the geographic placement of our mines across three U.S. coal basins, we are strategically positioned to realize significant potential synergies from domestic acquisitions. We expect our strong financial position will help support execution of potential strategic acquisitions and alliances.
Remain committed to cost containment policies to ensure operations are as efficient and profitable as possible. We continue to leverage our strong base of experienced, well-trained employees through a culture of workforce engagement to drive cost savings and operational productivity. While our operations have achieved significant overall cash cost reductions since 2014, we see further opportunities to reduce costs across our business. We also are continuing to efficiently manage our business and actively demonstrate financial discipline by maintaining a lean cost structure, prudently managing capital allocation and maintaining our flexible logistics and transportation platform.
Industry Overview
Coal is an abundant and inexpensive natural resource, making it a leading source for the world’s energy consumption and steel production needs. According to the BP Statistical Review, total global proven coal reserves were 983 billion tons at the end of 2015, and coal provided 29% of the world’s primary energy consumption. Coal is generally categorized into met and steam coal. Met coal is used to create coke for use in the steel-making process. Steam coal is primarily used by utilities and power producers to generate electricity. Per Wood Mackenzie, 74% of the world’s steel production in 2016 was estimated to be manufactured using methods that consume met coal. Coal has historically been a relatively inexpensive fuel for power generation and remains a major fuel for global energy.

5



Metallurgical Coal Industry Overview
Met coal is converted into coke, a critical input in the steel making process. The met coke is used as a fuel and reducing agent in steel blast furnaces to convert iron ore into iron and subsequently to create steel. High-quality met coal is a scarce commodity, with large scale reserves found primarily in the eastern U.S., western Canada, eastern Australia, Russia and China. Met coal is consumed domestically and sold into the seaborne market. According to Wood Mackenzie, in 2017, approximately 313 million tons are expected to be shipped in the seaborne market, while the total global met coal production is expected to be 1,191 million tons.
Coke and iron production are the primary demand drivers for met coal. In the integrated steel making process, iron ore must be converted or ‘reduced’ using the carbon in met coal. Basic oxygen / blast furnace is the most common method to produce steel. Global met import demand is forecast to be stable in the near-term and is expected to increase modestly annually from 2016 to 2018, according to Wood Mackenzie. Our key end markets are expected to have growth levels in steel production that exceed other steelmaking nations, providing additional upside for us. As an example, import met coal demand in Turkey, India and Germany is expected to grow 20%, 14% and 6% respectively, from 2016 to 2020 according to Wood Mackenzie.
Historically, the majority of met coal sold in the seaborne market has been priced based on a quarterly benchmark. The supply of met coal decreased 6% from 2014 through 2016, according to Wood Mackenzie, due to high cost volume taken offline in a price environment that declined from $143 per metric ton in Q1 2014 to $81 per metric ton in Q1 2016. By Q4 2016, however, the trend reversed and the Hard Coking Coal (“HCC”) benchmark rose substantially to $200 / metric ton. In 2016, restrictive coal output policies in China and difficult mining conditions in Australia, which combined represented 79% of 2016 global met coal production, led to further supply tightening across the world. There was an additional short-term supply tightening due to storm damage from Cyclone Debbie that caused major rail outages in Australia during early April 2017.
To supply China and other net importers of met coal, Australia, Canada and the U.S. are expected to contribute 86% of 2017 seaborne met coal exports, according to Wood Mackenzie. Due to reduced capital expenditures over the past several years and the permanent closure of many mines, growth from these countries is expected to stay relatively flat at the newly reduced production levels. The remaining met coal production is largely expected to come from countries such as Mozambique and Mongolia, which have had many greenfield projects delayed in recent years due to lack of funding and / or an uneconomic pricing environment.
Steam Coal Industry Overview
Steam coal is an abundant resource that is crucial to global electricity needs. Steam coal producers compete primarily with natural gas and increasingly with renewable forms of energy around the world. In 2015, steam coal accounted for approximately 29% of the world’s energy consumption, according to the BP Statistical Review. Despite increasing competition from other forms of energy, steam coal is expected to continue playing a significant role in satisfying growing global energy needs, primarily in base load power generation. At current production rates, proven coal reserves are expected to last for over 150 years, according to the BP Statistical Review, which is by far the largest reserve life of any fossil fuel.
Steam coal has long been a cost-effective option for energy needs throughout the world. Since 2005, the cost of using coal to generate electricity has been approximately 50% cheaper on a dollar per million BTU basis than natural gas, according to the Energy Information Administration (“EIA”). From 2016 to 2035, seaborne steam coal exports are expected to grow at a compound annual growth rate (“CAGR”) of 0.8%, according to Wood Mackenzie. This growth is being driven by Australia and the United States. In the U.S., steam coal is produced in all major coal basins. The PRB supplies the majority of domestic steam coal and is expected to account for approximately 44% of supply in 2017, according to Wood Mackenzie. Over 95% of U.S. steam coal production is consumed domestically with the remainder sold into the seaborne export market.
Because natural gas power generation is an alternative to coal, Henry Hub natural gas pricing is a key reference point for the steam coal outlook. Natural gas pricing volatility continues but steam coal remains the low-cost option.

6



Henry Hub natural gas prices decreased from a high of $7.92 per million BTU in 2014 to a low of $1.49 per million BTU in March 2016. The natural gas volatility continued as prices increased to $3.76 per million BTU in December 2016 before stabilizing at around $3.00 per million BTU in March 2017.
Rising natural gas prices in 2017 and 2018 are expected to support higher steam coal prices, according to Wood Mackenzie. In addition to rising natural gas prices, the coal industry is expected to benefit from a reduced regulatory burden via recent and ongoing legislative and administrative action. In March, President Donald Trump signed the Executive Order on Promoting Energy Independence and Economic Growth, which aims to reduce regulatory restrictions intended to curb the production and use of fossil fuels. An important part of this Executive Order directs the Environmental Protection Agency (“EPA”) to commence regulatory proceedings to rescind or revise the Clean Power Plan. The Clean Power Plan had already been temporarily stayed by the U.S. Supreme Court pending judicial review. Potential repeal or revision of the Clean Power Plan and other potential actions from the current Administration should ease the pressure on coal-fired utilities to retire units prematurely, arguably increasing the life of the current domestic coal fleet.
Risks Related to our Business and Strategy
An investment in shares of our common stock involves substantial risks and uncertainties that may adversely affect our business, financial condition and results of operations and cash flows. Some of the more significant challenges and risks relating to an investment in our common stock include, but are not limited to:
•
Our business may suffer as a result of a substantial or extended decline in coal pricing, demand and other factors beyond our control, which could negatively affect our operating results and cash flows.
•
Coal mining involves many hazards and operating risks and is dependent upon many factors and conditions beyond our control, which may cause our profitability and our financial position to decline.
•
Significant competition, as well as changes in foreign markets or economics, could harm our sales, profitability and cash flows.
•
Extensive environmental, health and safety laws and regulations impose significant costs on our operations and future regulations could increase those costs, limit our ability to produce or adversely affect the demand for our products.
For additional risks relating to our business and this offering, see “Risk Factors” beginning on page 13 of this prospectus.
Corporate Information
We were incorporated in the State of Delaware on June 10, 2016 to acquire and operate certain of Alpha’s core coal operations, as part of Alpha’s restructuring. We began operations on July 26, 2016 upon Alpha’s emergence from Chapter 11 bankruptcy protection. Our principal executive offices are located at 340 Martin Luther King Jr. Blvd., Bristol, Tennessee 37620, and our telephone number is (423) 573-0300. Our website is www.conturaenergy.com. Our website and the information contained therein or connected thereto is not incorporated into this prospectus or the registration statement of which it forms a part.

7



The Offering
Shares of common stock to be sold in this offering by the selling stockholders
                   shares
Shares of common stock to be outstanding after this offering
                   shares
Underwriters’ option to purchase additional shares
The underwriters have a 30-day option to purchase up to                   additional shares of common stock from the selling stockholders, solely to cover over-allotments. We will not receive any of the proceeds from the shares of common stock sold pursuant to the over-allotment option.

Use of proceeds
We will not receive any proceeds from the sale of our common stock in this offering. All of the proceeds from this offering will be received by the selling stockholders. See “Use of Proceeds.”

Dividend policy
We have never declared or paid a cash dividend. If we decide to pay cash dividends in the future, the declaration and payment of such dividends will be at the sole discretion of our board of directors and may be discontinued at any time. In determining the amount of any future dividends, our board of directors will take into account any legal or contractual limitations, our actual and anticipated future earnings, cash flow, debt service and capital requirements, tax considerations and other factors that our board of directors may deem relevant.

Listing
We intend to apply to list our common stock on the New York Stock Exchange under the symbol “CTRA.”

Risk factors
See “Risk Factors” in this prospectus beginning on page 13 for a discussion of factors you should carefully consider before investing in our common stock.

Tax considerations
See “Material U.S. Federal Income and Estate Tax Consequences to Non-U.S. Holders.”
Unless we specifically state otherwise or the context otherwise requires, the share information in this prospectus is as of December 31, 2016 and does not give effect to or reflect the issuance of:
•
           shares issuable upon the exercise of outstanding stock options under the Contura Energy, Inc. Management Incentive Plan (the “MIP”) at a weighted-average exercise price of $       per share;
•
           shares reserved for future grants or for sale under the MIP; or
•
a maximum of             shares issuable upon exercise of the warrants outstanding as of December 31, 2016 at an exercise price of             per share.
In addition, the share information in this prospectus does not give effect to or reflect the issuance of 429,357 shares of restricted stock and 129,520 non-qualified stock options (with an exercise price of $66.13 per share) to certain of our officers and key employees under the MIP.
Unless we specifically state otherwise or the context otherwise requires, the information in this prospectus assumes that underwriters’ option to purchase up to an additional          shares of common stock from the selling stockholders is not exercised.

8



Summary Historical and Pro Forma Financial Data
The following tables set forth our summary consolidated and combined historical and pro forma financial data as of and for each of the periods indicated. The summary consolidated historical financial data as of December 31, 2016 and for the period from July 26, 2016 through December 31, 2016 is derived from the audited consolidated financial statements of the Successor included elsewhere in this prospectus. The summary combined historical financial data for the period from January 1, 2016 through July 25, 2016 and the years ended December 31, 2015 and December 31, 2014 is derived from the audited combined financial statements of our Predecessor included elsewhere in this prospectus. The term “Successor” refers to Contura Energy, Inc. 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 Alpha’s historical basis and our assets, liabilities and operating results while under Alpha’s ownership.
The summary unaudited pro forma statement of operations data for the year ended December 31, 2016 is derived from the unaudited pro forma condensed combined statement of operations included elsewhere in this prospectus. The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2016 assumes that the Alpha Restructuring and the Acquisition occurred as of January 1, 2016. The summary unaudited pro forma financial data is based upon available information and certain assumptions that management believes are factually supportable, are reasonable under the circumstances and are directly related to the Alpha Restructuring. The summary unaudited pro forma financial data is provided for informational purposes only and does not purport to represent what our results of operations or financial position actually would have been if the Alpha Restructuring had occurred at any other date, and such data does not purport to project our results of operations for any future period.
You should read this summary consolidated and combined historical and pro forma financial data together with “Unaudited Pro Forma Condensed Combined Statement of Operations,” “Selected Historical Consolidated and Combined Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes thereto, included elsewhere in this prospectus. Our historical results are not necessarily indicative of our future results of operations, financial position and cash flows.


9



Summary Consolidated and Combined Financial and Other Data
Statements of Operations Data:
(In thousands, except for share and per share data)
Pro Forma
 
Successor
 
 
Predecessor
Year Ended December 31, 2016
 
Period from
July 26, 2016 to December 31, 2016
 
 
Period from
January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Revenues:
 
 
 

 
 
 

 
 
 
 
Coal revenues
$
1,149,567

 
$
612,247

 
 
$
537,320

 
$
1,243,690

 
$
1,464,316

Freight and handling revenues
122,620

 
70,544

 
 
52,076

 
97,237

 
98,109

Other revenues
25,170

 
6,628

 
 
18,542

 
20,704

 
24,600

Total revenues
1,297,357

 
689,419

 
 
607,938

 
1,361,631

 
1,587,025

Costs and expenses:
 
 
 

 
 
 

 
 
 
 
Cost of coal sales (exclusive of items shown separately below)
937,982

 
465,764

 
 
489,652

 
1,106,046

 
1,202,612

Freight and handling costs
122,620

 
70,544

 
 
52,076

 
97,237

 
98,109

Other expenses
7,452

 
2,559

 
 
4,893

 
(931
)
 
15,473

Depreciation, depletion and amortization
100,956

 
43,978

 
 
85,379

 
202,115

 
203,361

Amortization of acquired intangibles, net
105,000

 
61,281

 
 
11,567

 
2,223

 
(1,699
)
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization shown separately above)
48,272

 
19,135

 
 
29,567

 
44,158

 
52,256

Mark-to-market adjustment for acquisition-related obligations
(10,616
)
 
(10,616
)
 
 
—

 
—

 
—

Asset impairment and restructuring
3,755

 
—

 
 
3,755

 
558,699

 
6,849

Goodwill impairment
—

 
—

 
 
—

 
—

 
70,017

Total costs and expenses
1,315,421

 
652,645

 
 
676,889

 
2,009,547

 
1,646,978

Income (loss) from operations
(18,064
)
 
36,774

 
 
(68,951
)
 
(647,916
)
 
(59,953
)
Other (expense) income:
 
 
 

 
 
 

 
 
 
 
Interest expense
(45,111
)
 
(20,792
)
 
 
(63
)
 
(437
)
 
(712
)
Interest income
52

 
23

 
 
29

 
4

 
7

Mark-to-market adjustment for warrant derivative liability
(33,975
)
 
(33,975
)
 
 
—

 
—

 
—

Bargain purchase gain
—

 
7,719

 
 
—

 
—

 
—

Equity loss in affiliates
(5,006
)
 
(2,280
)
 
 
(2,726
)
 
(7,700
)
 
(9,810
)
Miscellaneous income, net
915

 
232

 
 
683

 
28

 
383

Total other expense, net
(83,125
)
 
(49,073
)
 
 
(2,077
)
 
(8,105
)
 
(10,132
)
Loss before reorganization items and income taxes
(101,189
)
 
(12,299
)
 
 
(71,028
)
 
(656,021
)
 
(70,085
)
Reorganization items, net
—

 
—

 
 
(31,073
)
 
(16,134
)
 
—

Loss before income taxes
(101,189
)
 
(12,299
)
 
 
(102,101
)
 
(672,155
)
 
(70,085
)
Income tax benefit
36,258

 
1,369

 
 
34,889

 
254,595

 
17,740

Net loss
$
(64,931
)
 
$
(10,930
)
 
 
$
(67,212
)
 
$
(417,560
)
 
$
(52,345
)
Basic loss per common share
$
(6.30
)
 
$
(1.06
)
 
 


 


 


Diluted loss per common share
$
(6.30
)
 
$
(1.06
)
 
 


 


 


Weighted average shares - basic
10,309,310

 
10,309,310

 
 
 
 
 
 
 
Weighted average shares - diluted
10,309,310

 
10,309,310

 
 
 
 
 
 
 

10



Other Financial and Operating Data:
(In thousands except for per ton data)
Pro Forma
 
Successor
 
 
Predecessor
Year Ended December 31, 2016
 
Period from
July 26, 2016 to December 31, 2016
 
 
Period from
January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Tons sold
46,706

 
22,481

 
 
24,225

 
51,710

 
52,329

Average coal sales realization per ton (1)
$
24.61

 
$
27.23

 
 
$
22.18

 
$
24.05

 
$
27.98

Cost of coal sales per ton (2)
$
20.08

 
$
20.72

 
 
$
20.21

 
$
21.39

 
$
22.98

Coal margin per ton (3)
$
4.53

 
$
6.51

 
 
$
1.97

 
$
2.66

 
$
5.00

Adjusted EBITDA(4)
$
176,940

 
$
129,369

 
 
$
29,707

 
$
98,105

 
$
218,040

______________
(1)
Average coal sales realization per ton is defined as coal revenues divided by tons sold.
(2)
Cost of coal sales per ton is defined as cost of coal sales divided by tons sold.
(3)
Coal margin per ton is defined as coal revenues less cost of coal sales, divided by tons sold.
(4)
Adjusted EBITDA is a non-GAAP financial measure and has been presented in this prospectus as a supplemental measure of financial performance that is not required by, or presented in accordance with, GAAP. We calculate adjusted EBITDA as net loss before interest expense (income), income tax benefit, depreciation, depletion and amortization, mark-to-market adjustment for warrant derivative liability, bargain purchase gain, mark-to-market adjustment for acquisition-related obligations, amortization of acquired intangibles (net), reorganization items (net), asset impairment and restructuring charges, goodwill impairment and mark-to-market adjustment for other derivatives.
We believe that this non-GAAP financial measure provides additional insight into our operating performance, and it reflects how management analyzes our operating performance and compares that performance against other companies for purposes of business decision making by excluding the impact of certain items that management does not believe are indicative of our core operating performance. We believe Adjusted EBITDA assists management in comparing performance across periods, planning and forecasting future business operations and helping determine levels of operating and capital investments. Period-to-period comparisons of Adjusted EBITDA are intended to help our management identify and assess additional trends potentially impacting our company that may not be shown solely by period-to-period comparisons of net loss. In addition, we believe that Adjusted EBITDA is a useful measure as some investors and analysts use Adjusted EBITDA to compare us against other companies. However, Adjusted EBITDA may not be comparable to similarly titled measures used by other entities.
The following table reconciles net loss to Adjusted EBITDA for the periods presented.
(In thousands)
Pro Forma
 
Successor
 
 
Predecessor
Year Ended December 31, 2016
 
Period from
July 26, 2016 to December 31, 2016
 
 
Period from
January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Net loss
$
(64,931
)
 
$
(10,930
)
 
 
$
(67,212
)
 
$
(417,560
)
 
$
(52,345
)
Interest expense
45,111

 
20,792

 
 
63

 
437

 
712

Interest income
(52
)
 
(23
)
 
 
(29
)
 
(4
)
 
(7
)
Income tax benefit
(36,258
)
 
(1,369
)
 
 
(34,889
)
 
(254,595
)
 
(17,740
)
Depreciation, depletion and amortization
100,956

 
43,978

 
 
85,379

 
202,115

 
203,361

Mark-to-market adjustment for warrant derivative liability (a)
33,975

 
33,975

 
 
—

 
—

 
—

Bargain purchase gain (b)
—

 
(7,719
)
 
 
—

 
—

 
—


11



Mark-to-market adjustment for acquisition-related obligations (c)
(10,616
)
 
(10,616
)
 
 
—

 
—

 
—

Amortization of acquired intangibles, net (d)
105,000

 
61,281

 
 
11,567

 
2,223

 
(1,699
)
Reorganization items, net (e)
—

 
—

 
 
31,073

 
16,134

 
 
Asset impairment and restructuring (f)
3,755

 
—

 
 
3,755

 
558,699

 
6,849

Goodwill impairment (g)
—

 
—

 
 
—

 
—

 
70,017

Mark-to-market adjustment for other derivatives (h)
—

 
—

 
 
—

 
(9,344
)
 
8,892

Adjusted EBITDA
$
176,940

 
$
129,369

 
 
$
29,707

 
$
98,105

 
$
218,040

______________
(a)
Adjusts for the mark-to-market impact of warrants issued during the Successor period. The warrants are classified as a derivative liability and are marked-to-market with changes in value reflected in earnings.
(b)
Adjusts for the bargain purchase gain recognized through the Acquisition. The bargain purchase gain resulted from the excess of the fair value of the acquired assets over liabilities assumed through the Acquisition.
(c)
Adjusts for the mark-to-market impact of Acquisition-related obligations assumed through various settlement agreements entered into as part of the Alpha Restructuring.
(d)
Adjusts for the amortization of above and below market-priced coal supply agreements related to the Acquisition from Alpha, as well as other acquisitions during the Predecessor period.
(e)
Adjusts for reorganization items such as realized gains and losses from the settlement of pre-petition liabilities and provisions for losses resulting from the Alpha Restructuring, as well as professional fees directly related to the Alpha Restructuring.
(f)
Adjusts for the impairment of certain long-lived assets or asset groups as a result of a longer than expected recovery in the metallurgical coal markets and lower production and shipment levels, as well as severance expenses, losses related to non-core property divestitures and other restructuring-related charges.
(g)
Adjusts for goodwill impairment charges.
(h)
Adjusts for the mark-to-market impact of commodity swap agreements used to mitigate the risk of price volatility for diesel fuel.

Balance Sheet Data:
(In thousands)
December 31, 2016
Cash and cash equivalents
$
127,948

Working capital(1)
$
206,604

Property, plant, and equipment, net
$
317,013

Total assets
$
946,752

Notes payable and long-term debt, including current portion, net
$
349,161

Total liabilities
$
909,528

Stockholders’ equity
$
37,224

______________
(1)
Working capital is defined as current assets less current liabilities.

12



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 common stock to decline and result in a loss. In addition, we may also face new risks as yet unidentified. You should carefully consider the information in this prospectus, including the following risks and the matters addressed under “Special Note Regarding Forward-Looking Statements” before making an investment decision. The trading price of our common stock could decline, and you may lose all or part of your investment.
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:
•
the demand for domestic and foreign coal and coke, which depends significantly on the demand for electricity and steel;
•
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;
•
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;
•
the legal, regulatory and tax environment for our industry and those of our customers; 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.
Lower demand for met coal by U.S. and foreign steel producers could reduce the price of our met coal, which would reduce our revenues.
We produce met coal that is used in both the U.S. and foreign steel industries. Met coal accounted for approximately 51% of our coal revenues for the period from July 26, 2016 to December 31, 2016. Any deterioration in conditions in the U.S. or the foreign steel industry, 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

13



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.
In addition, the steel industry’s demand for met coal is affected by a number of factors, including the cyclical 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 steam coal by North American electric power generators could reduce the price of our steam coal, which would reduce our revenues.
Steam coal accounted for approximately 49% of our coal revenues for the period from July 26, 2016 to December 31, 2016. The majority of our sales of steam coal were to U.S. and Canadian electric power generators. The North American demand for steam coal is affected primarily by:
•
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;
•
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. A reduction in the amount of coal consumed by North American electric power generators would reduce the amount of steam 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 steam 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 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.

14



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 has 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 exports revenues accounted for approximately 48% of our total coal revenues for the period from July 26, 2016 to December 31, 2016. 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. Additionally, China is the world’s largest importer of coal, and decreases in its demand could cause decreases in the prices we receive for our export shipments. Furthermore, if the amount of coal exported from the U.S. were to decline, 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.
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. According to Wood Mackenzie, China is the largest met coal producer and consumer in the world, consuming over 99% of its 2016 domestic production of 731 million tons of met coal. The recent rise from historic lows in prices was driven in part by government policies in China that curbed domestic supply. In early 2016, the Chinese government announced a 276-work day limitation on the annual operating days for coal mines, as well as a plan to close over 1,000 coal mines within the year. While in early 2017, the Chinese government set its capacity reduction target to 165 million tons for the year, it may not enforce this target or may reverse it in future periods. 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 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, 2016, on a pro forma basis, accounted for approximately 7% of our total coal revenues, and coal sales to our ten largest customers accounted for approximately 41% of our total coal revenues. These customers may not continue to purchase coal from us as they

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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 materially.
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.
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.
In addition, price adjustment, “price reopener” and other similar provisions in some of our long-term supply contracts reduce the protection from short-term coal price volatility that these contracts have traditionally provided. Price reopener provisions are particularly common in international met coal sales contracts. Some of our coal supply contracts allow for the price to be renegotiated at periodic intervals. Generally, price reopener provisions require the parties to agree on a new price based on the prevailing market price; however, some contracts provide that the new price must be set between a pre-set “floor” and “ceiling.” Failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract or litigation, the outcome of which would be uncertain. 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 renegotiation 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 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 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. In the period from July 26, 2016 to December 31, 2016, we derived 48% of our total coal 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, margins and profitability and ability to obtain financing, as well as our costs.

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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. Furthermore, because we seek to enter into long-term arrangements for the sale of a substantial portion of our coal, it is likely that the average sales price we receive for our coal will lag behind any general economic recovery.
Risks Relating to Regulatory and Legal Developments
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 greenhouse gases (“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, a GHG, 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. These include:
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the 2015 Paris climate summit agreement, which resulted in voluntary commitments by 197 countries, including the United States, to reduce their GHG emissions and could result in additional firm commitments by various nations with respect to future GHG emissions;
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federal regulations such as the Clean Power Plan (“CPP”), which is currently stayed by the U.S. Supreme Court and would have required reductions in emissions from existing power plants, and new source performance standards for GHG emissions for new, modified or reconstructed coal and oil-fired power plants (“Power Plant NSPS”), which requires the use of partial carbon capture and sequestration (both of which are subject to potential suspension, revision or rescission);
•
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
•
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 United States Environmental Protection Agency (“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. The EPA will also review the compliance dates set by the CPP, since some of these dates “have passed or will likely pass while the CPP continues to be stayed.” On April 28, 2017, 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. 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 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 groups have sought to stop or delay coal mining activities, bringing numerous lawsuits, including against the Bureau of Land Management (“BLM”) and the Office of Surface Mining Reclamation and Enforcement (“OSM”) to challenge not only the issuance of individual coal leases and mine plan approvals and modifications, but also the federal coal leasing program more broadly. 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 future 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

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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 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 in October 2015 of a more stringent ambient air quality standard for ozone;
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implementation of the EPA’s Cross-State Air Pollution Rule (“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;  
•
continued implementation of the EPA’s Mercury and Air Toxics Standards (“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;
•
implementation of the EPA’s August 2014 final rule on cooling water intake structures for power plants;
•
more stringent EPA requirements governing management and disposal of coal ash pursuant to a rule finalized in December 2014; and
•
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.

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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;
•
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
•
employee health and safety, and benefits for current and retired coal miners (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;
•
Mine Safety and Health Administration (“MSHA”) and the state of 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
•
more stringent regulation of GHG emissions is being considered that, if expanded to cover coalbed methane emissions, could increase our costs, require additional controls, or compel us to limit our current operations, particularly at our underground coal mines.
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 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. Contura is also required to ensure that one or more of its subsidiaries assumes responsibility for complying with the Section IX Osmotic Pressure Injunctive Relief requirements under a November 2014 Consent Decree between Alpha and several government agencies with regard to the Cumberland and Emerald mines. See “Environmental and Other Regulatory Matters—Clean Water Act—Wastewater Discharge.”

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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.
Our long-term growth may be materially adversely impacted if economic, commercially available carbon mitigation technologies for power plants 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 carbon capture or other emissions control technologies. For example, pursuant to the Power Plant NSPS finalized by the EPA in August 2015, the EPA has 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. The Power Plant NSPS is undergoing judicial and administrative review and may be revised or rescinded in whole or in part pursuant to the March 2017 Executive Order. If such legislative or regulatory programs are adopted, 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.
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 and at contaminated sites owned or operated by third parties to which we sent wastes for 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 coal slurry impoundments at a number of our mining complexes. 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

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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.
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 to challenge permits or mining activities. In states where we operate, applicable laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if an officer or director of, a stockholder with a 10% or greater interest in, or certain other affiliates of, the applicant or permittee or an entity that is affiliated with or is in a position to control the applicant or permittee, has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits or modification or amendment of existing permits. 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 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 Army Corps of Engineers (the “COE”) under Section 404 of the Clean Water Act. 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 Clean Water Rule (“CWR”) under the Clean Water Act (“CWA”) that would further expand the circumstances when a Section 404 permit is needed. However, the CWR is currently stayed pending judicial review and, on February 28, 2017, 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. 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 February 2017. If we are unable to use the nationwide permits and require an individual permit for certain work, that could delay operations. Some of our operations involve mining federal coal. Operations involving federal coal may require additional approvals, including from the US Department of the Interior, such as mine plan modifications and approvals and lease modifications under the Mineral Leasing Act. These approvals require compliance with other federal environmental laws, which require public comment processes and may be the subject of litigation by project opponents. OSM mine plan modifications in particular have been subject to appeals and litigation, including related to climate change analysis. If we are unable to receive these approvals, certain coal production may be delayed or unavailable.

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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.
We are in the process of obtaining transfer of certain permits held by Alpha for the operations we acquired from Alpha. All necessary applications for the transfer of such permits have been filed, and we are authorized to continue operating on such permits as the mine or facility operator until such transfers have been completed. There can be no assurance that such transfers will be completed on a timely basis, or at all.
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.
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, (3) the repeal of capital gains treatment of coal and lignite royalties, and (4) the elimination of the domestic manufacturing deduction for coal and other hard mineral fossil fuels. 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 federal, state, or county tax laws, particularly in the areas of non-income taxes and royalties, could cause our financial position and profitability to deteriorate.
We pay federal and state royalties and federal, state and county non-income taxes on the coal we produce. A substantial portion of our royalties and non-income taxes are levied as a percentage of gross revenues, while others are levied on a per ton basis. For example, we pay royalties of 12.5% of gross proceeds to the federal government on coal extracted from leased federal lands. If the royalty and non-income tax rates were to significantly increase, our results of operations could be materially and adversely affected.

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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:
•
changes or variations in geologic, hydrologic or other conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;
•
mining, processing and loading equipment failures and unexpected maintenance problems;
•
limited availability or increased costs of mining, processing and loading equipment and parts and other materials from suppliers;
•
difficulties associated with mining under or around surface obstacles;
•
unfavorable conditions with respect to proximity to and availability, reliability and cost of transportation facilities;
•
adverse weather and natural disasters, such as heavy snows, heavy rains and flooding, lightning strikes, hurricanes or earthquakes;
•
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;
•
security breaches or terroristic acts;
•
strikes and other labor-related interruptions;
•
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;
•
competition and/or conflicts with other natural resource extraction activities and production within our operating areas;
•
the termination of material contracts by state or other governmental authorities; and
•
fatalities, personal injuries or property damage arising from train derailments, mined material or overburden leaving permit boundaries, underground mine blowouts, impoundment failures or other unexpected incidents.

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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 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 steam 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 steam coal. In deciding our approach to these reserves, we assess the conditions in the met and steam coal markets, including factors such as the current and anticipated future market prices of steam coal and met coal, the generally higher price of met coal as compared to steam coal, the lower volume of saleable tons that results when producing coal for sale in the met market rather than the steam market, the increased costs of producing met coal, the likelihood of being able to secure a longer term sales commitment for steam coal and our contractual commitments to deliver different types of coal to our customers. A decline in demand for met coal relative to steam coal could cause us to shift coal from the met market to the steam market, thereby reducing our revenues and profitability.
Coal competes with natural gas and renewable energy sources, and factors affecting these industries could have an adverse impact on our coal sales.
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.
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 the Powder River Basin, permitting, licensing and other environmental and

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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.
Our ability to operate our company effectively could be impaired if we fail to attract and retain key personnel.
Our ability to operate our business and implement our strategies depends in part on the efforts of our executive officers and other key employees. In addition, our business depends on, among other factors, our ability to attract and retain other qualified personnel. The loss of the services of any of our executive officers or other key employees or the inability to attract or retain other qualified personnel in the future could have a material adverse effect on our business or business prospects.
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.
During the period from July 26, 2016 to December 31, 2016, 88% of our captive coal volume was transported from our mines to the customer 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, 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.

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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, including certain obligations we assumed from Alpha as part of the bankruptcy reorganization. The unfunded status of these obligations as of December 31, 2016, as reflected in our financial statements, included $21.5 million of workers’ compensation obligations and $13.5 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. Several states in which we operate consider changes in workers’ compensation laws from time to time, which, if enacted, could adversely affect us.
We rely on Alpha to provide us with access to historical financial information pursuant to the terms of a transition services agreement for a limited transition period. If the transition period expires or if Alpha fails to perform its obligations under the agreement, we may be unable to implement substitute arrangements on a timely and cost-effective basis on terms favorable to us or at all.
Pursuant to the terms of a transition services agreement (the “Transition Services Agreement”) with Alpha, entered in connection with the Alpha Restructuring on July 26, 2016, Alpha provides us with access to historical financial information. We believe it is necessary for Alpha to provide this service to us to facilitate the efficient operation of our business as we transition to becoming a public company. See “Certain Relationships and Related Party Transactions—Transition Services Agreement.” Once the transition period specified in the Transition Services Agreement has expired or if Alpha fails to perform its obligations under the Transition Services Agreement, we may be unable to implement substitute arrangements on a timely and cost-effective basis on terms favorable to us or at all.
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. 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.
Federal healthcare legislation could adversely affect our financial condition and results of operations.
In March 2010, the Patient Protection and Affordable Care Act (“PPACA”) was enacted, impacting our costs of providing healthcare benefits to our eligible active and certain retired 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 2020. 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.
Beginning in 2020, 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.

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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.
The 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. Estimates of our total reclamation and mine-closing liabilities total $191.4 million as of December 31, 2016 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—Off-Balance Sheet Arrangements” 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.

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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 will support current production levels for more than 20 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 we do at our current operations. 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 through the lease by application (“LBA”) process or otherwise, 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 access with multiple parties. If we are unable to successfully negotiate surface access 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.
Our future success and growth could be materially and adversely affected if we are unable to acquire additional reserves through the federal and state competitive leasing processes, or to do so on a cost-effective basis.
Federal and state governments own coal in the vicinity of some of our mines. The federal LBA process is a significant means of acquiring additional reserves. There is no requirement that the federal government lease coal subject to an LBA, lease its coal at all or give preference to any LBA applicant, and our bids may compete with other coal producers’ bids in the PRB. In the current coal pricing environment, LBAs are becoming increasingly more competitive and expensive to obtain, and the review process to submit an LBA bid continues to lengthen. We

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expect that this trend may continue. The increasing size of potential LBA tracts may make it easier for new mining operators to enter the market on economical terms and may, therefore, increase competition for LBAs. Increased opposition from non-governmental organizations and other third parties may also lengthen, delay, or complicate the LBA process. In order to win a lease in the LBA process and acquire additional coal, our bid for a coal tract must meet or exceed the fair market value of the coal based on the internal estimates of the Bureau of Land Management (“BLM”), which they do not publish. We have maintained a history of timely payments related to our LBAs. If we are unable to maintain our “good payor” status, we would be required to seek bonding for any remaining payments. If we are required to purchase bonding for lease obligations this would significantly increase our costs and materially and adversely affect our profitability.
If Congress determines to amend the bonus bid payment method, it could require us to make a single up-front bonus bid payment equal to 100% of the bonus bid for the LBAs for which we intend to bid, which would materially and adversely affect our cash position, future profitability and results of operations.
The LBA process also requires us to acquire rights to mine from surface owners overlying the coal, and these rights are becoming increasingly more difficult and costly to acquire. Certain federal regulations provide a specific class of surface owners, also known as qualified surface owners (“QSOs”), with the ability to prohibit the BLM from leasing its coal. If a QSO owns the land overlying a coal tract, federal laws prohibit us from leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO, which would allow us to conduct our mining operations. This right of QSOs allows them to exercise significant influence over negotiations to acquire surface rights and can delay the LBA process or ultimately prevent the acquisition of an LBA. If we are unable to successfully negotiate access rights with QSOs at a price and on terms acceptable to us, we may be unable to acquire LBAs for coal on land owned by the QSO. If the prices to acquire land owned by QSOs increase, it could materially and adversely affect our profitability.
We acquire a small percentage of our reserves through the Wyoming state leasing processes. We typically lease approximately 9% of our Wyoming reserves from Wyoming state leases, which are equally distributed between our two Wyoming operations. If, as part of our growth strategy, we desire to expand our operations into areas requiring state leases, and we are unable to do so on a cost-effective basis, our business strategy could be adversely affected.
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 71% of our total workforce and approximately 60% of our hourly workforce is union-free as of December 31, 2016. 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 our subsidiaries have wage agreements with the United Mine Workers of America (“UMWA”) that are subject to termination by either the employer or the UMWA, without cause, on July 31, 2020. Either party may also reopen the wage agreements on July 26, 2018, for the sole purpose of renegotiating changes in the hourly wage rates, by giving written notice to the other party during the period from May 1, 2018 through June 1, 2018. 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.
We are a new company and are in the process of developing and maintaining proper and effective disclosure controls and procedures and internal control over financial reporting. We may not complete our development or implementation of our disclosure controls and procedures or internal control over financial reporting in a timely manner, or our disclosure controls and procedures or internal control may have one or more material weaknesses, which may adversely affect the value of our common stock.
We are a new company and are in the costly and challenging process of compiling the systems and processing the documentation necessary to implement and evaluate the effectiveness of our disclosure controls and procedures

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and 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 our disclosure 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.
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 federal and state 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 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. 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.
Some equipment and materials are needed to comply with regulations. For example, MSHA and other regulatory agencies sometimes make changes with regards to requirements for pieces of equipment. In 2015, MSHA promulgated a new regulation requiring the implementation of proximity detection devices on all continuous mining machines. Such changes could cause delays if manufacturers and suppliers are unable to make the required changes in compliance with mandated deadlines.
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

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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 do not currently operate all of our mines, and our results of operations could be adversely affected if third-party mine operators fail to effectively operate the mines.
Five 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.
Disruption in supplies of coal produced by third parties could impair our ability to fill customers’ orders, increase our costs or reduce revenues earned through our Trading and Logistics business.
We sold 2.1 million tons of coal purchased from third parties during the period from July 26, 2016 to December 31, 2016, representing approximately 10% of our total coal sales volume during such period. The availability of the coal we purchase may decrease and prices may increase as a result of, among other things, changes in overall coal supply and demand levels, consolidation in the coal industry and new laws or regulations. Furthermore, we purchase a substantial portion of this coal from one source. Disruption in our supply of purchased 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 prices we pay for purchased coal could increase our costs and therefore lower our earnings.
In addition, we earn margins on coal produced by others and sold through our Trading and Logistics business. Disruptions in the supply of coal sold through this business could reduce our revenues 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 program 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.
Our estimates and judgments related to the acquisition of the assets, liabilities, operating results and cash flows in the Alpha Restructuring may be inaccurate and thus impact our business, operating results and financial condition.
The purchase price allocation related to the Acquisition includes provisional amounts for certain assets and liabilities. The purchase price allocation will continue to be refined during the one-year measurement period, which will end no later than July 26, 2017, under acquisition accounting primarily in the area of income taxes and other contingencies. During the measurement period, we expect to receive additional detailed information to refine the provisional allocation. Our financial condition could be materially and adversely impacted in future periods if our accounting judgments and estimates related to these calculations prove to be inaccurate.

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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 Alpha as part of 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 Alpha. These carryforwards and tax basis were subject to reduction on December 31, 2016 due to the cancellation of indebtedness resulting from 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, the company does not have a 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, 2016, the company has recorded a full valuation allowance against its net deferred tax assets.
The enactment of legislation implementing changes in United States’ taxation policies could materially impact our tax net operating loss carryforwards and financial position.
The current presidential administration has made public statements indicating that it has made tax reform a priority, and key members of the U.S. Congress have conducted hearings and proposed a wide variety of potential changes. Certain changes to U.S. tax laws could affect the valuation of our net operating loss carryforwards and financial position. Our ability to use our net operating loss carryforwards may be subject to limitation and, thus, may result in increased future tax liability for us, both on the federal and state levels.
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 environmental laws and regulations. Before our emergence as a standalone entity, our operations and growth had been funded in large part through capital investments by our Predecessor. 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.
Derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Changes in fair value are recognized either in earnings or equity, depending on whether the transaction qualifies for cash flow hedge accounting, and if so, how effective the derivatives are at offsetting price movements in the underlying exposure.
We issued Series A Warrants on July 26, 2016 and classified the warrants as a derivative liability. The warrants we issued are recorded at fair value and marked to market in each reporting period, with changes in value reflected in earnings.
Any of these changes in fair value can have a significant non-cash impact on our earnings from period to period. For example, in the period from July 26, 2016 to December 31, 2016, the change in fair value of our derivative warrant liability was a charge of $34.0 million.

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Cybersecurity attacks, natural disasters, terrorist attacks and other similar crises or disruptions may negatively affect our business, financial condition and results of operations.
Our business 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 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, 2016, we had $363.5 million of indebtedness outstanding before discounts and issuance costs applied for financial reporting, of which $21.0 million will mature in the next three years. As of December 31, 2016, we did not have any letters of credit outstanding under the 2016 LC Facility.
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;
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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;
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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;
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cause us to be more vulnerable to general adverse economic and industry conditions;
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expose us to the risk of increased interest rates because certain of our borrowings are at variable rates of interest;
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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;
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limit our ability to borrow additional monies in the future to fund working capital, capital expenditures and other general corporate purposes; and
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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.

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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.
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 balances. 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 and indentures.
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.
As a result of recent coal producer bankruptcy filings, the coal industry has experienced increasing credit pressures that could result in demands for credit support by third parties or decisions by banks, surety bond providers, investors or other companies to reduce or eliminate their exposure to the coal industry, including our company. These credit pressures could materially and adversely impact our liquidity and ability to meet our regulatory requirements.
Recent coal producer bankruptcy filings have resulted in increased credit pressures on the coal industry. These credit pressures include, for example, (a) vendors, suppliers, customers and other commercial counterparties seeking prepayments, security deposits, letters of credit and other credit protections, and (b) banks, surety bond providers, investors and other companies reducing or eliminating their exposure to the coal industry. Although some of these credit pressures may be company-specific, many are directed to the coal industry in general due to the negative investor sentiment toward the industry. Any credit demands by third parties or refusals by banks, surety bond providers, investors or others to extend, renew or refinance credit on commercially reasonable terms may adversely impact our business, financial condition, results of operations, cash flows and liquidity. Surety bonds to secure our reclamation obligations are legally required as a condition of the permits for our mining operations. In some cases then, such as any collateral requirements imposed by surety bond providers to issue the surety bonds, our ability to meet these regulatory requirements may also be adversely impacted if we are not able to satisfy cash or other collateral requirements. As of December 31, 2016, there were approximately $315.1 million in third-party surety bonds outstanding to primarily secure the performance of our reclamation and lease obligations.
We have agreed to provide certain guarantees and other support in certain circumstances in connection with the Alpha Restructuring settlement, which could increase our financial obligations.

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In connection with Alpha’s bankruptcy reorganization, we agreed to provide certain support to the reorganized debtors (“ANR”) under certain circumstances. Pursuant to the Contingent Commitment, an unsecured obligation to ANR, we must provide ANR with revolving credit support in an aggregate total amount of $35 million from the Effective Date through September 30, 2018.
Pursuant to the UMWA VEBA Funding Settlement agreement, if federal legislation providing retirement health benefits to the UMWA Retirees has not been enacted or if moneys under the legislation have not become available for such benefits before August 1, 2017, on August 1, 2017, we are required to issue to the UMWA Contingent VEBA Funding Note 1 with a face value of $8.8 million, and if federal legislation providing retirement health benefits to the UMWA Retirees has not been enacted or if moneys under the legislation have not become available for such benefits before December 1, 2017, on December 1, 2017, we are also required to issue to the VEBA the UMWA Contingent VEBA Funding Note 2 with a face value of $8.8 million. The Miners Protection Act of 2017 (“MPA”) was introduced in the U.S. House on January 3, 2017 and in the Senate on January 17, 2017. On May 1, 2017, legislators announced that a tentative agreement had been reached on the Omnibus Appropriations Act, including funding of the MPA. On May 5, 2017, President Trump signed into law H.R. 244, the Consolidated Appropriations Act of 2017, which provides long-term funding for the health benefits of certain retired union miners. Specifically covered are any currently enrolled beneficiaries in the Plan whose health benefits would be denied or reduced as a result of a bankruptcy proceeding commenced in 2012 or 2015.
Pursuant to the Environmental Groups Settlement Agreement dated June 24, 2016 as part of the Alpha Restructuring, we agreed to the Environmental Groups Settlement Guarantee, which is a guarantee of ANR’s obligations to make payments of $1.6 million on each of March 31, 2017 and March 31, 2018. ANR made the first $1.6 million payment by March 31, 2017. Additionally, pursuant to the Reclamation Funding Agreement dated July 12, 2016, Restricted Cash Reclamation Accounts were established for certain federal and state environmental regulatory authorities to provide certain funding for the reclamation, mitigation and water treatment, and certain management work to be done at reclaim-only sites related to certain obligations under the various permits associated with ANR’s retained assets. Pursuant to the Reclamation Funding Agreement, under certain circumstances, we will be required to pay up to an aggregate amount of $50.0 million into various Restricted Cash Reclamation Accounts from 2021 through 2025.
Pursuant to a November 28, 2016 settlement, we agreed to provide a letter of credit of $4.0 million or similar instrument, in support of ANR’s payment obligations under the Permitting and Reclamation Plan Settlement Agreement for the State of West Virginia, dated as of July 12, 2016 and the Reclamation Funding Agreement dated July 12, 2016. Pending the letter of credit or similar instrument to be put in place, we placed $4.0 million in cash, pursuant to the Deposit Account Control Agreement with PNC Bank, National Association, dated as of December 22, 2016, to be kept in escrow. We also provided a secured guaranty, dated as of December 22, 2016, for ANR’s payment obligations under the two agreements described above, in an amount not to exceed $4.5 million and on March 31, 2017, we placed $4.5 million in cash, pursuant to the Deposit Account Control Agreement with PNC Bank, National Association, dated as of March 23, 2017, to be kept in escrow. See “Business - Legal Proceedings.”
ANR is newly emerged from the bankruptcy process, and it may not be able to operate at a profit or generate significant cash flows. If we are required to provide support under these various commitments, it would significantly increase our financial obligations and increase the related risks that we now face.
Under the terms of the asset purchase agreement between Alpha and Contura, liabilities, including those related to environmental matters, associated with Alpha or its predecessors’ pre-sale operations were explicitly retained by Alpha, subject to certain exceptions. Pursuant to Alpha’s Plan of Reorganization and the order of the Bankruptcy Court confirming it, the assets acquired by Contura were transferred “free and clear” of any liabilities or claims of any nature relating to Alpha or any of its predecessors except as otherwise provided in the Alpha Asset Purchase Agreement or in the terms of the order of the Bankruptcy Court (and subject to the settlements described above). In doing so, the Bankruptcy Court found that the sale was at arms-length and did not render us an alter ego or corporate successor of Alpha. In addition, in connection with certain of the settlements described above, certain federal and state governmental authorities released us from certain reclamation and environmental liabilities associated with the assets retained by Alpha or its pre-sale operations. Notwithstanding the foregoing, we could become the subject of

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claims relating to liabilities of Alpha or Alpha’s predecessors arising from pre-sale operations. For such claims to succeed, claimants would need to demonstrate, among other things, that they did not receive proper notice of Alpha’s Plan of Reorganization (or were otherwise not subject to discharge), that the claims arose after the confirmation of Alpha’s Plan of Reorganization, that the claims are not subject to the releases contained in the settlements and that we are successors to the liabilities of Alpha, notwithstanding the findings and order of the Bankruptcy Court to the contrary and the terms of the asset purchase agreement allocating such liabilities to Alpha. Although we believe the possibility of us becoming subject to the liabilities of Alpha to be remote, if we were to become subject to such liabilities, we could be required to pay substantial fines, penalties and/or damages, which we cannot estimate at this time and which could have a material adverse effect on our consolidated financial condition or results of operations.
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 the terms of a settlement we entered into in connection with the Alpha Restructuring, we were required to replace Alpha’s self-bonds with surety bonds or other traditional financial assurance mechanisms, 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. 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, 2016, we had outstanding surety bonds with third parties of $315.1 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.
We have partly secured our bonding obligations for our operations in Wyoming, which as of December 31, 2016, totals approximately $263.8 million, through an arrangement whereby we have granted the State of Wyoming a security interest in some of our real property and equipment. Certain citizen groups have filed objections to these arrangements as contrary to applicable regulations. We are in the process of replacing the security interests in our personal property with third-party surety bonds.
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 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 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 stock, make loans and investments,

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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.
As of December 31, 2016, the company did not have any letters of credit outstanding under the 2016 LC Facility. The 2016 LC Facility was a cash collateralized letter of credit facility which provided for the issuance of letters of credit secured by 105% cash collateral. On April 3, 2017, we entered into the 2017 ABL Facility. The 2017 LC Facility is a cash collateralized letter of credit facility which provides for the issuance of letters of credit secured by 103% cash collateral. Obligations secured by letters of credit may increase in the future. If we do not maintain sufficient borrowing capacity under our letter of credit facility, 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 this Offering and 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 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:
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institute a more comprehensive compliance function;
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comply with rules promulgated by the NYSE;
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continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
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establish new internal policies, such as those relating to insider trading; and
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involve and retain to a greater degree outside counsel and accountants in the above activities.

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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.
The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.
Prior to this offering, our common stock was traded on the OTC Pink® under the ticker symbol “CNTE.” An active, liquid and orderly trading market for our common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. 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 initial public offering price will be negotiated between us, the selling stockholders and the representative of the underwriters, based on numerous factors which we discuss in “Underwriting,” and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.
The following factors could affect our stock price:
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our operating and financial performance, including reserve estimates;
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quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;
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the public reaction to our press releases, our other public announcements and our filings with the SEC;
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strategic actions by our competitors;
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changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;
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speculation in the press or investment community;
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the failure of research analysts to cover our common stock;
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sales of our common stock by us, our directors or officers or the selling stockholders or the perception that such sales may occur;
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our payment of dividends;
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changes in accounting principles, policies, guidance, interpretations or standards;
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additions or departures of key management personnel;

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•
actions by our stockholders;
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general market conditions, including fluctuations in commodity prices;
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domestic and international economic, legal and regulatory factors unrelated to our performance; and
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the realization of any risks described under this “Risk Factors” section.
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. After the completion of this offering, we will have          outstanding shares of common stock, assuming no exercise of outstanding options, no vesting of outstanding restricted stock units and no exercise of outstanding warrants. This number includes the          shares of common stock that the selling stockholders are selling in this offering and the          shares of common stock that the selling stockholders may sell in this offering if the underwriters’ option to purchase additional shares is fully exercised. Of the outstanding shares,          shares sold in this offering will be freely tradable, except that any shares acquired by our affiliates, as that term is defined in Rule 144 under the Securities Act, in this offering may only be sold in compliance with certain limitations.
In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of          shares of our common stock issued or reserved for issuance under our equity incentive plans. Upon satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction, subject to Rule 144 limitations with respect to affiliates. In addition, as described below, 9,350,000 shares of common stock and 810,811 warrants issued in reliance on Section 1145(a)(1) of the Bankruptcy Code pursuant to Alpha’s Plan of Reorganization (and the shares of common stock issuable upon exercise of such warrants) may be resold without registration unless the seller is an “underwriter” with respect to those securities. See “Shares Eligible for Future Sale.”
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. See “Description of Capital Stock.”
The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.
We, our officers and directors, the selling stockholders and holders of     % our common stock have entered or will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the sale or other disposition of our common stock for a period of 180 days following the date of this prospectus. The representatives of the underwriters, at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. See “Underwriting” for more information on these

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agreements. In addition, holders of     % of our common stock are not subject to any contractual restrictions on their ability to sell such stock and may do so at any time. If the restrictions under the lock-up agreements are waived for such shares subject to restriction, then the common stock, along with such freely tradable shares, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.
We may issue preferred stock whose terms 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 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 will be influenced by the research and reports that industry or securities analysts publish about us or our business. If 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.
Our results as a public company could be significantly different from those portrayed in our historical financial results.
The historical financial information included in this prospectus has been derived from the consolidated financial statements of Alpha and may not reflect what our financial position, results of operations, cash flows, costs or expenses would have been had we been a separate public company during the periods presented. Alpha did not account for us, and we were not operated, as a separate public company for the historical periods presented. The historical costs and expenses reflected in our consolidated financial statements also include allocations of certain general and administrative costs and Alpha’s headquarters costs. These expenses are estimates and were based on what we and Alpha considered to be reasonable allocations of the historical costs incurred by Alpha to provide these services required in support of our business.
As a public company, our cost structure will be different and will include both additional recurring costs and nonrecurring costs that we will incur during our transition to being a public company. Accordingly, our historical consolidated financial information may not be reflective of our financial position, results of operations or cash flows or costs had we been a public company during the periods presented, and the historical financial information may not be a reliable indicator of what our financial position, results of operations or cash flows will be in the future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
The pro forma condensed consolidated financial information in this prospectus is based on estimates and assumptions that may prove to be materially different from our actual experience.
In preparing the pro forma condensed consolidated financial information included elsewhere in this prospectus, we have made certain adjustments to the historical consolidated financial information based upon currently available information and upon estimates and assumptions that our management believes are reasonable in order to reflect, on

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a pro forma basis, the impact of the structuring transactions, the debt financing transactions, the issuance of restricted stock to our directors and employees in connection with this offering and the issuance of common stock in this offering. However, these estimates are predicated on assumptions, judgments and other information which are inherently uncertain.
These estimates and assumptions used in the preparation of the pro forma condensed consolidated financial information in this prospectus may be materially different from our actual experience as a public company. The pro forma condensed consolidated financial information included elsewhere in this prospectus does not purport to represent what our results of operations would actually have been had we operated as a public company during the periods presented, nor do the pro forma data give effect to any events other than those discussed in the unaudited pro forma condensed consolidated financial information and related notes. See “Unaudited Pro Forma Condensed Combined Statement of Operations.”
We may not pay cash dividends on our common stock in the foreseeable future.
We have never declared or paid a cash dividend. If we decide to pay cash dividends in the future, the declaration and payment of such dividends will be at the sole discretion of our board of directors and may be discontinued at any time. In determining the amount of any future dividends, our board of directors will take into account any legal or contractual limitations, our actual and anticipated future earnings, cash flow, debt service and capital requirements, tax considerations and other factors that our board of directors may deem relevant.
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 certificate of incorporation and 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 certificate of incorporation and bylaws impose various procedural and other requirements, which could make it more difficult for stockholders to effect certain corporate actions. For example, our 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. See “Description of Capital Stock—Anti-Takeover Effects of Certain Provisions of Our Amended and Restated Certificate of Incorporation and our Amended and Restated Bylaws.”
A Change of Control (as defined in the 2017 Term Facility and the 2017 ABL Facility) is an event of default under the 2017 Term Loan Facility and the 2017 ABL Facility, 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.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This prospectus contains forward-looking statements that are not statements of historical fact and may involve a number of risks and uncertainties. These statements relate to analyses and other information that are based on forecasts of future results and estimates of amounts not yet determinable. These statements 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 prospectus 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.
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 prospectus. 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 prospectus.
The following factors are among those that may cause actual results to differ materially from our forward-looking statements:
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successful implementation of our business strategies;
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our liquidity, results of operations and financial condition;
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depressed levels or declines in coal prices;
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worldwide market demand for coal, electricity and steel, including demand for U.S. coal exports, and competition in coal markets;
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foreign currency fluctuations;
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utilities switching to alternative energy sources such as natural gas, renewables and coal from basins where we do not operate;
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reductions or increases in customer coal inventories and the timing of those changes;
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our production capabilities and costs;
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our ability to develop or acquire coal reserves in an economically feasible manner;
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inherent risks in the coal mining industry beyond our control;
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geologic, equipment, site access and operational risks and new technologies related to mining;
•
changes in domestic or environmental, health and safety laws and regulations, agency actions and court decisions, including those directly affecting our coal mining and production, and those affecting our customers’ coal usage, including potential climate change initiatives;
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our relationships with, and other conditions affecting, our customers, including the inability to collect payments from our customers if their creditworthiness declines;

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•
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;
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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;
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attracting and retaining key personnel and other employee workforce factors, such as labor relations;
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funding for and changes in employee benefit obligations and workers’ compensation benefits;
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litigation, including claims not yet asserted;
•
cybersecurity attacks or failures, threats to physical security, extreme weather conditions or other natural disasters;
•
climate change concerns and our operations’ impact on the environment;
•
reclamation and mine closure obligations;
•
our assumptions concerning economically recoverable coal reserve estimates;
•
our ability to negotiate new union 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, components and materials that are necessary for our operations, such as diesel fuel, steel products, explosives and tires;
•
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;
•
our ability to obtain or renew surety bonds on acceptable terms or maintain our current bonding status; and
•
other factors, including those discussed in “Risk Factors.”

45



USE OF PROCEEDS
We will not receive any proceeds from the sale of our common stock in this offering, including from any exercise of the underwriters’ option to purchase additional shares of our common stock. All of the net proceeds from this offering will be received by the selling stockholders. See “Principal and Selling Stockholders.”

46



DIVIDEND POLICY
We have never declared or paid a cash dividend. If we decide to pay cash dividends in the future, the declaration and payment of such dividends will be at the sole discretion of our board of directors and may be discontinued at any time. In determining the amount of any future dividends, our board of directors will take into account any legal or contractual limitations, our actual and anticipated future earnings, cash flow, debt service and capital requirements, tax considerations and other factors that our board of directors may deem relevant.
Our ability to pay dividends on our common stock is limited by covenants in our debt facilities and may be further restricted by the terms of any future debt or preferred securities. See “Risk Factors—Risks Related to this Offering and Our Common Stock—We May Not Pay Cash Dividends on Our Common Stock in the Foreseeable Future.”

47



CAPITALIZATION
The following table sets forth the company’s cash and cash equivalents and capitalization as of December 31, 2016. The selling shareholders will receive all proceeds from the sale of the shares of common stock offered from time to time under this prospectus. The company will not receive any proceeds from the sale of common stock pursuant to this prospectus.
This table should be read in conjunction with “Selected Historical Consolidated and Combined Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Unaudited Pro Forma Condensed Combined Statement of Operations,” and the consolidated financial statements and related notes and other financial information included elsewhere in this prospectus.
(Amounts in thousands, except share and per share data)
As of
December 31, 2016
Cash and cash equivalents (1)
$
127,948

Debt:
 
Term Facility (2)
42,500

2016 LC Facility (2)(3)
—

Closing Tranche Term Loan (2)
8,500

GUC Distribution Note (2)
5,500

10% Senior Secured First Lien Notes (2)
300,000

Other debt
7,024

Debt discount and issuance costs
(14,363
)
Total debt
349,161

Equity:
 
Preferred stock - par value $0.01, 2.0 million shares authorized, none issued
—

Common stock - par value $0.01, 20.0 million shares authorized, 10.3 million issued and outstanding at December 31, 2016
103

Additional paid-in capital
45,964

Accumulated other comprehensive income
2,087

Accumulated deficit
(10,930
)
Total equity
37,224

Total capitalization
$
386,385

______________
(1)
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. Excludes long-term restricted cash of $43,341 as of December 31, 2016.
(2)
On March 17, 2017, we entered into a $400.0 million Term Loan Credit Facility with a maturity date on March 17, 2024. In connection with this transaction, we repaid all of our outstanding 10.00% Senior Secured First Lien Notes due 2021. The proceeds of the Term Loan Credit Facility were also used to repay the Term Facility due 2020, the Closing Tranche Term Loan due 2018 and the GUC Distribution Note due 2018. On April 3, 2017, we entered into the ABL Facility, under which we may borrow cash or draw letters of credit from, on a revolving basis, in an amount up to $125.0 million, subject to certain limitations set forth therein. Any borrowings under the asset-based revolving credit facility will have a maturity date of April 4, 2022 and will bear interest at rates ranging from 1.00% to 2.50% depending on loan type. As of May 1, 2017, no letters of credit were outstanding, no cash borrowing transactions had taken place and $125.0 million was available under the facility. The LC Facility was also terminated in connection with the entry into the ABL Facility.
(3)
The 2016 LC Facility provided for the issuance of letters of credit secured by 105% cash collateral. We did not have any letters of credit outstanding under the LC Facility as of December 31, 2016.

48



DILUTION
Our as adjusted net tangible book value as of December 31, 2016 was $      or $      per share of common stock. As adjusted net tangible book value per share represents tangible assets, less liabilities, divided by the aggregate number of shares of common stock outstanding.
Because all of the shares of common stock to be sold in this offering, including those subject to any exercise of the underwriters’ option to purchase additional shares, will be sold by the selling stockholders, there will be no increase in the number of shares of our common stock outstanding as a result of this offering. The common stock to be sold by the selling stockholders is common stock that is issued and outstanding. Accordingly, our pro forma net tangible book value as of December 31, 2016 would be unchanged at approximately $          million, or $          per share of common stock, prior to giving effect to the payment by us of estimated offering expenses of $          million in connection with this offering.
Dilution per share represents the difference between the price per share to be paid by new investors for the shares of common stock sold in this offering and the as adjusted net tangible book value per share immediately after this offering. The following table illustrates this per share dilution:
Assumed initial public offering price per share
$
(Decrease/Increase) in as adjusted net tangible book value per share attributable to new investors
 
As adjusted net tangible book value per share as of December 31, 2016 after this offering
 
Immediate dilution per share to new investors in this offering (1)
$
______________
(1)
Because the offering expenses payable by us and the total number of shares outstanding following this offering will not be impacted by any exercise of the underwriters’ option to purchase additional shares of common stock from the selling stockholders and we will not receive any net proceeds from such exercise, there will be no change to the dilution in net tangible book value per share of common stock to purchasers in this offering due to any such exercise of the option.
The following table sets forth the total number of shares issued and outstanding as of December 31, 2016 after giving pro forma effect to the sale by the selling stockholders of           shares of common stock in this offering, together with the total consideration paid an average price per share paid for such shares, before deducting underwriting discounts and commissions and estimated offering expenses.
 
Shares Purchased
 
Total Consideration
 
Average Price Per Share
 
Number
 
Percent
 
Amount
 
Percent
 
Existing stockholders
 
 
%

 
$
 
%

 
 
New investors
 
 
 
 
 
 
 
 
 
Total
 
 
100
%
 
$
 
100
%
 
 
If the underwriters’ option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to                  , or approximately        % of the total number of shares of common stock issued and outstanding immediately following this offering.

49



UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
Introduction
The unaudited pro forma condensed combined statement of operations (“pro forma statement of operations”) for the year ended December 31, 2016 is set forth below. The pro forma statement of operations has been derived from and should be read in conjunction with the audited statement of operations for the period from July 26, 2016 to December 31, 2016 (Successor) and the period from January 1, 2016 to July 25, 2016 (Predecessor) included elsewhere in this prospectus.
In this introduction and the notes to the accompanying pro forma statement of operations, (i) “Successor” or “company” refers to Contura Energy, Inc. and its subsidiaries (“Contura”) for the period beginning July 26, 2016 and thereafter following the acquisition of certain of Alpha Natural Resources, Inc.’s (“Alpha”) core coal operations as part of Alpha’s restructuring (“Acquisition”), and (ii) “Predecessor” refers to Contura on a carve-out basis using Alpha’s historical bases in the assets, liabilities and operating results of Contura while under Alpha’s ownership.
The accompanying pro forma statement of operations reflects pro forma adjustments to the company’s statement of operations to give effect to the Acquisition and the Alpha Restructuring (collectively, the “Transactions”) as if the Transactions had occurred on January 1, 2016. The pro forma statement of operations excludes the effects of this offering. The Acquisition has already been reflected in the company’s historical audited balance sheet as of December 31, 2016; therefore, no change to unaudited pro forma balance sheet as of December 31, 2016 is presented herein.
The historical financial information has been adjusted in the accompanying pro forma statement of operations to give pro forma effect to events that are (i) directly attributable to the Transactions, (ii) factually supportable and (iii) expected to have a continuing impact on the company’s consolidated results.
The pro forma statement of operations give pro forma effect to the matters described in the accompanying notes, including:
•
removal of reorganization items, net that were directly attributable to the Alpha Restructuring;
•
removal of pension, post-retirement and deferred compensation plan benefit expenses related to obligations which were not assumed by the Successor as part of the Acquisition;
•
adjustment to cost of coal sales for accretion expense resulting from the estimate of fair value of the asset retirement obligations (“ARO”) assumed in the Acquisition;
•
adjustment to depreciation and depletion expense resulting from the estimate of fair value of property, plant and equipment (“PP&E”) and ARO assets acquired in the Acquisition;
•
adjustment to increase amortization expense based on the estimated fair value of acquired intangibles recorded in connection with the Acquisition;
•
addition of interest expense and associated discounts related to the Successor’s new debt agreements and acquisition-related obligations that were entered into in connection with the Acquisition; and
•
removal of the bargain purchase gain that resulted from the excess of fair value of the acquired assets over liabilities assumed through the Acquisition.
The pro forma statement of operations has been prepared by management for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been realized had the Transactions occurred as of the date indicated. In addition, future results may vary significantly from those reflected

50



in the pro forma statement of operations and should not be relied on as an indication of any future results of operations of the company.
The pro forma adjustments included in the pro forma statement of operations are based on currently available data and estimates and assumptions; therefore, actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions used to prepare these pro forma adjustments provide a reasonable basis for presenting the significant effects of the Transactions.
In the pro forma statement of operations, the Acquisition has been accounted for as a business combination using the acquisition method of accounting under the provisions of Accounting Standard Codification Topic 805, Business Combinations, or ASC 805, and applying the pro forma assumptions and adjustments described in the accompanying notes. The purchase price allocation will continue to be refined during the one-year measurement period, which will end no later than July 26, 2017, under acquisition accounting primarily in the area of income taxes and other contingencies. During the measurement period, the company expects to receive additional detailed information to refine the provisional purchase price allocation.
Historical and pro forma basic and diluted loss per share is calculated based on the weighted average common shares outstanding of the company for the Successor period from July 26, 2016 to December 31, 2016. There was no dilutive effect to common shares outstanding for the Successor period from July 26, 2016 to December 31, 2016 or the pro forma year ended 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.
The pro forma statement of operations does not reflect any additional costs that may arise from being a public company or the realization of any expected cost savings, operating efficiencies or other synergies that may result from the Acquisition.
The pro forma statement of operations is qualified by reference to, and should be read in conjunction with, “Capitalization,” “Selected Consolidated and Combined Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the audited Successor and Predecessor financial statements and related notes and other financial information included elsewhere in this prospectus.

51



UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
For the Year Ended December 31, 2016
(Amounts in thousands, except share and per share data)
 
Successor
 
Predecessor
 
Pro Forma Adjustments
 
Pro Forma
 
Period from
July 26, 2016 to December 31, 2016
 
Period from January 1, 2016 to July 25, 2016
 
Alpha Reorganization
 
Acquisition
 
Year Ended December 31, 2016
Revenues:
 

 
 

 
 
 
 
 
 
Coal revenues
$
612,247

 
$
537,320

 
$
—

 
$
—

 
$
1,149,567

Freight and handling revenues
70,544

 
52,076

 
—

 
—

 
122,620

Other revenues
6,628

 
18,542

 
—

 
—

 
25,170

Total revenues
689,419

 
607,938

 
—

 
—

 
1,297,357

Costs and expenses:
 

 
 

 
 
 
 
 
 
Cost of coal sales (exclusive of items shown separately below)
465,764

 
489,652

 
—

 
(17,434
)
(b)(c)
937,982

Freight and handling costs
70,544

 
52,076

 
—

 
—

 
122,620

Other expenses
2,559

 
4,893

 
—

 
—

 
7,452

Depreciation, depletion and amortization
43,978

 
85,379

 
—

 
(28,401
)
(d)(e)
100,956

Amortization of acquired intangibles, net
61,281

 
11,567

 
—

 
32,152

(f)
105,000

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

 
29,567

 
—

 
(430
)
(b)
48,272

Asset impairment and restructuring
—

 
3,755

 
—

 
—

 
3,755

Mark-to-market adjustment for acquisition related obligations
(10,616
)
 
—

 
—

 
—

 
(10,616
)
Total costs and expenses
652,645

 
676,889

 
—

 
(14,113
)
 
1,315,421

Income (loss) from operations
36,774

 
(68,951
)
 
—

 
14,113

 
(18,064
)
Other (expense) income:
 
 
 
 
 
 
 
 
 
Interest expense
(20,792
)
 
(63
)
 
—

 
(24,256
)
(g)
(45,111
)
Interest income
23

 
29

 
—

 
—

 
52

Mark-to-market adjustment for warrant derivative liability
(33,975
)
 
—

 
—

 
—

 
(33,975
)
Bargain purchase gain
7,719

 
—

 
—

 
(7,719
)
(h)
—

Equity loss in affiliates
(2,280
)
 
(2,726
)
 
—

 
—

 
(5,006
)
Miscellaneous income, net
232

 
683

 
—

 
—

 
915

Total other expense, net
(49,073
)
 
(2,077
)
 
—

 
(31,975
)
 
(83,125
)
Loss before reorganization items and income taxes
(12,299
)
 
(71,028
)
 
—

 
(17,862
)
 
(101,189
)
Reorganization items, net
—

 
(31,073
)
 
31,073

(a)
—

 
—

Loss before income taxes
(12,299
)
 
(102,101
)
 
31,073

 
(17,862
)
 
(101,189
)
Income tax benefit
1,369

 
34,889

 
—

(i)
—

(i)
36,258


52



Net loss
$
(10,930
)
 
$
(67,212
)
 
$
31,073

 
$
(17,862
)
 
$
(64,931
)
Basic loss per common share
(1.06
)
 
 
 
 
 
 
 
(6.30
)
Diluted loss per common share
(1.06
)
 
 
 
 
 
 
 
(6.30
)
Weighted average shares - basic
10,309,310

 
 
 
 
 
 
 
10,309,310

Weighted average shares - diluted
10,309,310

 
 
 
 
 
 
 
10,309,310

______________
See accompanying Notes to Unaudited Pro Forma Condensed Combined Statement of Operations.

53



CONTURA ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
(Dollars in thousands)
Description of the Acquisition
The company was incorporated in the state of Delaware on June 10, 2016. The company was formed to acquire and operate certain of Alpha’s core coal operations, as part of the Alpha Reorganization. The company began operations on July 26, 2016, with mining complexes in Northern Appalachia (including the Cumberland mine complex), the Powder River Basin (Belle Ayr and Eagle Butte complexes), and three Central Appalachian mining complexes (the Nicholas mine complex in Nicholas County, West Virginia, and the McClure and Toms Creek mine complexes in Virginia). The company also acquired Alpha’s interest in the Dominion Terminal Associates coal export terminal in eastern Virginia. Through the acquisition, Contura acquired 1.3 billion tons of proven and probable coal reserves. See Note 3 in the Successor and Predecessor audited financial statements included elsewhere in this prospectus for additional information related to the Acquisition.
Description of Alpha Reorganization
On August 3, 2015, 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 Alpha Debtors pursued a reorganization plan under which certain expenses were incurred and settlements negotiated, which were included within reorganization items, net, during the applicable portion of the Predecessor periods. The Bankruptcy Court approved the Alpha Debtors Plan of Reorganization on July 7, 2016 and Alpha emerged from bankruptcy on July 26, 2016.
Basis of Presentation
The accompanying unaudited pro forma condensed combined statement of operations (“pro forma statement of operations”) was prepared in accordance with Article 11 of Regulation S-X. The pro forma statement of operations for the year ended December 31, 2016 gives effect to the Transactions as if they had occurred on January 1, 2016 and was prepared using the audited statement of operations for the period from July 26, 2016 to December 31, 2016 (Successor) and the period from January 1, 2016 to July 25, 2016 (Predecessor).
Adjustments to the Pro Forma Statement of Operations
Alpha’s Reorganization
The following reflects the adjustment to record the pro forma effects of the consummation of Alpha’s Reorganization:
a)
Adjustment to remove Predecessor reorganization items, net that were directly attributable to Alpha’s Reorganization and will have no recurring impact on the company’s operating results.
Acquisition
The following reflects the adjustment to record the pro forma effects of the consummation of the Acquisition:
b)
Adjustment to eliminate Predecessor expenses related to (i) Alpha’s defined benefit pension plans, (ii) UMWA pension and benefit trust plans, (iii) Alpha’s post-retirement medical benefit plans and (iv) Alpha’s deferred compensation plans, none of which were assumed as part of the Acquisition. The following summarizes the components of the pro forma adjustments related to these benefit plans:

54



Cost of coal sales
Year Ended
December 31, 2016
Alpha post-retirement medical
$
(11,853
)
UMWA pension and benefit trusts
(7,127
)
Alpha defined benefit pension plans
(66
)
Total decrease to cost of coal sales
$
(19,046
)
Selling, general and administrative expenses
Year Ended
December 31, 2016
Alpha deferred compensation plans
$
(416
)
Alpha post-retirement medical
17

Alpha defined benefit pension plans
(31
)
Total decrease to selling, general and administrative expenses
$
(430
)
c)
Adjustment to increase cost of coal sales for accretion expense as a result of the change in the basis of the ARO to their estimated fair value in connection with the Acquisition. The following summarizes the pro forma adjustment to increase accretion expense:
 
Year Ended
December 31, 2016
Incremental Successor accretion expense
$
14,017

Elimination of Predecessor accretion expense
(12,405
)
Total increase to accretion expense
$
1,612

d)
Adjustment to increase depreciation expense as a result of the change in the basis of PP&E and ARO assets to their estimated fair value in connection with the Acquisition. PP&E is being depreciated over useful lives ranging from one to 25 years. ARO assets are being depreciated over the useful life of the related assets. The following summarizes the pro forma adjustment to increase PP&E and capitalized ARO depreciation expense:
 
Year Ended
December 31, 2016
Incremental Successor depreciation expense
$
56,978

Elimination of Predecessor depreciation expense
(51,151
)
Total increase to depreciation expense
$
5,827

e)
Adjustment to eliminate Predecessor depletion expenses of $34,228 due to the fair value adjustment of mineral rights to zero in connection with the Acquisition.
f)
Adjustment to increase estimated amortization expense for acquired intangibles based on the estimated fair value of acquired intangibles recorded in connection with the Acquisition. See Note 2 in the Successor and Predecessor audited financial statements included elsewhere in this prospectus for additional information related to acquired intangibles.
g)
Adjustment to reflect the net effect of interest expense and associated discount amortization related to the company’s (i) new debt arrangements and (ii) acquisition-related obligations that were entered into in connection with the Acquisition. See Notes 10 and 11 in the Successor and Predecessor audited financial statements included elsewhere in this prospectus for additional information related to the long-term debt and acquisition-related obligations, respectively.

55



h)
Adjustment to remove the bargain purchase gain that resulted from the excess of the fair value of the acquired assets over liabilities assumed through the Acquisition, as the gain will have no recurring impact on the company’s operating results.
i)
The company records deferred tax assets to the extent these assets will more likely than not be realized. In making such determination, the company considered all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial performance. Due to the company’s formation through the Acquisition as part of Alpha’s Reorganization, the company does not have a history of operating results. Additionally, ownership change limitations will limit the ability of the company to utilize its net operating loss and other carryforwards in future years. The company concluded that a full valuation allowance against the net deferred tax assets was necessary. The pro forma adjustments to Loss before income taxes were not tax-effected due to the full valuation allowance.


56



SELECTED HISTORICAL CONSOLIDATED AND COMBINED FINANCIAL DATA
The following table presents selected historical consolidated and combined financial data for the most recent five fiscal periods. The selected historical consolidated financial data as of December 31, 2016 and for the Successor period from July 26, 2016 to December 31, 2016, the selected historical combined financial data as of December 31, 2015 and for the Predecessor period from January 1, 2016 to July 25, 2016 and the years ended December 31, 2015 and 2014 have been derived from our audited Successor and Predecessor financial statements included elsewhere in this prospectus.  The selected historical combined financial data as of July 25, 2016 and December 31, 2014, 2013 and 2012 and for the Predecessor years ended December 31, 2013 and 2012 have been derived from our unaudited condensed combined financial statements that are not included in this prospectus. In management’s opinion, the unaudited condensed combined financial statements have been prepared on the same basis as the audited consolidated and combined financial statements and include all adjustments, consisting only of ordinary recurring adjustments, necessary for a fair presentation of the information for the periods presented.
As a result of Contura’s acquisition of certain Alpha core coal operations in connection with 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 our audited financial statements included elsewhere herein for additional information.
Our Predecessor combined financial statements and condensed combined financial statements include allocations of expenses for certain corporate functions historically performed by 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 the future costs we will incur as an independent, publicly-traded 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, publicly-traded company during the periods presented.
The selected historical consolidated and combined financial data presented below should be read in conjunction with our audited Successor and Predecessor financial statements and related notes thereto, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the “Unaudited Pro Forma Condensed Combined Statement of Operations” included elsewhere in this prospectus.

57



Selected Historical Consolidated and Combined Financial Data
(Amounts in thousands, except per share data)
 
Successor
 
 
Predecessor
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 

Years Ended December 31,
 
 
 
 
2015
 
2014
 
2013
 
2012
Statements of Operations Data:
 
 
 
 
 
 
 
 
 
 
 
 
Revenues:
 

 
 
 

 
 
 
 
 
 
 
 
Coal revenues
$
612,247

 
 
$
537,320

 
$
1,243,690

 
$
1,464,316

 
$
1,464,485

 
$
2,099,242

Freight and handling revenues
70,544

 
 
52,076

 
97,237

 
98,109

 
123,641

 
231,280

Other revenues (1)
6,628

 
 
18,542

 
20,704

 
24,600

 
40,786

 
80,431

Total revenues
689,419

 
 
607,938

 
1,361,631

 
1,587,025

 
1,628,912

 
2,410,953

Costs and expenses:
 

 
 
 
 
 
 
 
 
 
 
 
Cost of coal sales (exclusive of items shown separately below)
465,764

 
 
489,652

 
1,106,046

 
1,202,612

 
1,232,608

 
1,601,725

Freight and handling costs
70,544

 
 
52,076

 
97,237

 
98,109

 
123,641

 
231,280

Other expenses
2,559

 
 
4,893

 
(931
)
 
15,473

 
13,862

 
12,778

Depreciation, depletion and amortization
43,978

 
 
85,379

 
202,115

 
203,361

 
188,543

 
223,735

Amortization of acquired intangibles, net
61,281

 
 
11,567

 
2,223

 
(1,699
)
 
(909
)
 
27,309

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

 
 
29,567

 
44,158

 
52,256

 
45,440

 
65,201

Mark-to-market adjustment for acquisition-related obligations
(10,616
)
 
 
—

 
—

 
—

 
—

 
—

Asset impairment and restructuring (2)
—

 
 
3,755

 
558,699

 
6,849

 
8,743

 
216,348

Goodwill impairment (3)
—

 
 
—

 
—

 
70,017

 
5,912

 
206,890

Total costs and expenses
652,645

 
 
676,889


2,009,547


1,646,978


1,617,840


2,585,266

Income (loss) from operations
36,774

 
 
(68,951
)

(647,916
)

(59,953
)

11,072


(174,313
)
Other (expense) income:
 
 
 
 
 
 
 
 
 
 
 
 
Interest expense
(20,792
)
 
 
(63
)
 
(437
)
 
(712
)
 
(678
)
 
(777
)
Interest income
23

 
 
29

 
4

 
7

 
766

 
952

Mark-to-market adjustment for warrant derivative liability
(33,975
)
 
 
—

 
—

 
—

 
—

 
—

Bargain purchase gain
7,719

 
 
—

 
—

 
—

 
—

 
—

Equity loss in affiliates
(2,280
)
 
 
(2,726
)
 
(7,700
)
 
(9,810
)
 
(7,539
)
 
(8,727
)
Miscellaneous income, net
232

 
 
683

 
28

 
383

 
197

 
129

Total other expense, net
(49,073
)
 
 
(2,077
)
 
(8,105
)
 
(10,132
)
 
(7,254
)
 
(8,423
)

58



(Loss) income before reorganization items and income taxes
(12,299
)
 
 
(71,028
)
 
(656,021
)
 
(70,085
)
 
3,818

 
(182,736
)
Reorganization items, net
—

 
 
(31,073
)
 
(16,134
)
 
—

 
—

 
—

(Loss) income before income taxes
(12,299
)
 
 
(102,101
)
 
(672,155
)
 
(70,085
)
 
3,818

 
(182,736
)
Income tax benefit
1,369

 
 
34,889

 
254,595

 
17,740

 
33,802

 
55,099

Net (loss) income
$
(10,930
)
 
 
$
(67,212
)
 
$
(417,560
)
 
$
(52,345
)
 
$
37,620

 
$
(127,637
)
Basic loss per common share (4)
$
(1.06
)
 
 


 


 


 
 
 
 
Diluted loss income per common share (4)
$
(1.06
)
 
 


 


 


 
 
 
 
 
Successor
 
 
Predecessor
As of December 31, 2016 and for the period from July 26, 2016 to December 31, 2016
 
 
As of July 25, 2016 and for the period from January 1, 2016 to July 25, 2016
 
As of and for the
Year Ended December 31,
 
 
 
 
2015
 
2014
 
2013
 
2012
Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
127,948

 
 
$
108

 
$
269

 
$
26

 
$
52

 
$
145

Working capital
$
206,604

 
 
$
(35,872
)
 
$
53,249

 
$
7,959

 
$
(28,254
)
 
$
67,173

Total assets
$
946,752

 
 
$
1,590,256

 
$
1,715,410

 
$
2,429,213

 
$
2,536,057

 
$
2,769,881

Notes payable and long-term debt, including current portion, net
$
349,161

 
 
$
95

 
$
136

 
$
6,114

 
$
9,632

 
$
14,159

Total liabilities (5)
$
909,528

 
 
$
470,003

 
$
501,513

 
$
764,871

 
$
799,550

 
$
876,285

Stockholders’ equity/Predecessor business equity
$
37,224

 
 
$
1,120,253

 
$
1,213,897

 
$
1,664,342

 
$
1,736,507

 
$
1,893,596

Statement of Cash Flows Data:
 
 
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
 
 
 
Operating activities
$
70,918

 
 
$
60,690

 
$
150,862

 
$
165,103

 
$
274,457

 
$
521,418

Investing activities
$
15,552

 
 
$
(25,029
)
 
$
(97,034
)
 
$
(114,561
)
 
$
(118,008
)
 
$
(224,665
)
Financing activities
$
41,478

 
 
$
(35,822
)
 
$
(53,585
)
 
$
(50,568
)
 
$
(156,542
)
 
$
(295,739
)
______________
(1)
Other revenues for 2012 includes $28,526 associated with coal sales contract buyouts and $17,176 associated with terminal revenues.
(2)
Asset impairment and restructuring expenses for 2012 include long-lived asset impairment charges of $201,318 related to asset groups within the NAPP segment. Asset impairment and restructuring expenses for 2015 include long-lived asset impairment charges of $260,011, $224,139, and $72,012 related to asset groups within the PRB, NAPP and CAPP segments, respectively.
(3)
The goodwill impairment for 2012 includes impairment charges of $153,581 and $53,309 within the NAPP and PRB segments, respectively. Goodwill impairment for 2014 includes impairment charges of $70,017 within the CAPP segment.
(4)
Historical basic and diluted loss (income) per share is calculated based on the weighted average common shares outstanding for the Successor period from July 26, 2016 to December 31, 2016. 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.

59



(5)
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.


60



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 period from July 26, 2016 to December 31, 2016 (Successor), on a carve-out basis for the period from January 1, 2016 to July 25, 2016 (Predecessor), and the years ended December 31, 2015 and 2014 (Predecessor). You should read the following discussion of our results of operations and financial condition in conjunction with the accompanying audited Successor consolidated financial statements and Predecessor combined financial statements and the related notes, our “Unaudited Pro Forma Condensed Combined Statement of Operations, and “Selected Consolidated and Combined Historical Financial Data” included elsewhere in this prospectus. See Note 1 to the audited financial statements included elsewhere in this prospectus for further disclosures on the basis of presentation, as the Predecessor periods presented herein 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.
Overview
We are a large-scale, diversified provider of met and steam coal to a global customer base, operating high-quality, cost-competitive coal mines across three major U.S. coal basins along with a robust Trading and Logistics business. Our mining operations are located in major coal basins in CAPP, NAPP and the PRB, and are complemented by an active Trading and Logistics business. As of December 31, 2016, our operations consisted of thirteen mines and four coal preparation and load-out facilities, with approximately 2,200 employees. We produce, process and sell steam coal and met coal from operations located in Virginia, West Virginia, Pennsylvania and Wyoming. 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.
We were formed to acquire and operate certain of Alpha’s former core coal operations, as part of the Alpha Restructuring. We began operations on July 26, 2016, with mining complexes in NAPP (including the Cumberland mine complex), the PRB (the Belle Ayr and Eagle Butte complexes), and three CAPP mining complexes (the Nicholas mine complex in Nicholas County, West Virginia, and the McClure and Toms Creek mine complexes in Virginia). We also acquired Alpha’s 40.6% interest in the DTA coal export terminal in eastern Virginia, and on March 31, 2017, increased such interest to 65.0%. Through the Acquisition (as defined below), Contura acquired a significant reserve base. As of December 31, 2016, we had over 1.0 billion tons of proven reserves and approximately 310 million tons of probable reserves. See Note 3 to the audited financial statements included elsewhere in this prospectus for disclosures related to the Acquisition.
For the period from July 26, 2016 to December 31, 2016, the period from January 1, 2016 to July 25, 2016 and years ended December 31, 2015 and 2014, sales of steam coal were 19.4 million tons, 21.6 million tons, 46.2 million tons, and 47.5 million tons, respectively, and accounted for approximately 86%, 89%, 89%, and 91%, respectively, of our coal sales volume and sales of met coal, which generally sells at a premium over steam coal, were 3.1 million tons, 2.6 million tons, 5.5 million tons, and 4.9 million tons, respectively, and accounted for approximately 14%, 11%, 11%, and 9%, respectively, of our coal sales volume. These numbers include sales from our Trading and Logistics business.
Our sales of steam coal during the Successor and Predecessor periods were made primarily to large utilities and industrial customers throughout the U.S., and our sales of met coal were made primarily to steel companies in the northeastern and midwestern regions of the U.S. and in several countries in Europe, Asia and the Americas. For the period from July 26, 2016 to December 31, 2016, the period from January 1, 2016 to July 25, 2016 and years ended December 31, 2015 and 2014, approximately 48%, 20%, 20% and 22%, respectively, of our total coal 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 revenue for freight and handling services provided in delivering coal to certain customers, which are a component of the contractual selling price.

61



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.
We have four reportable segments: CAPP Operations, NAPP Operations, PRB Operations and Trading and Logistics Operations. CAPP consists of nine active mines, including five mines operated by third-party contractors, and two preparation plants in Virginia. CAPP also has one active mine and one preparation plant in West Virginia, as well as expenses associated with certain closed mines. NAPP consists of one active mine in Pennsylvania and one preparation plant, as well as expenses associated with one closed mine. PRB consists of two active mines in Wyoming. 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.
Formation
On August 3, 2015, Alpha 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. Alpha pursued a reorganization plan under which certain expenses were incurred and settlements negotiated. The Bankruptcy Court approved Alpha’s Plan of Reorganization on July 7, 2016 and Alpha emerged from bankruptcy on July 26, 2016.
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. See Note 1 to the audited financial statements included elsewhere in this prospectus for disclosures related to the Acquisition. 
Basis of Presentation
In this management’s discussion and analysis, (i) the “Successor” refers to Contura Energy, Inc. and its subsidiaries for the period beginning July 26, 2016 and thereafter following the acquisition of certain of Alpha’s core coal operations as part of the Alpha Restructuring (“Acquisition”), and (ii) “Predecessor” refers to Contura on a carve-out basis using Alpha’s historical bases in the assets, liabilities and operating results of Contura while under Alpha’s ownership.
The historical costs and expenses reflected in the Predecessor combined results of operations include an allocation for certain corporate functions historically provided 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 in the financial statements included elsewhere in this prospectus.
The combined financial statements of our Predecessor included elsewhere in this prospectus and the other historical Predecessor combined financial information presented and discussed herein may not be indicative of what our financial condition, results of operations and cash flows would have been if we were a separate stand-alone entity, nor are they indicative of what our financial position, results of operations and cash flows may be in the future. In addition, the Successor consolidated financial statements on and after July 26, 2016 are not comparable with the Predecessor combined financial statements prior to that date. Refer to Note 1 to our audited financial statements included elsewhere in this prospectus for additional information.
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. In 2016, we sold 4.0 million tons of met coal in CAPP and NAPP, 1.7 million tons of

62



met coal in our Trading and Logistics business and 41.1 million tons of steam coal in CAPP, NAPP and the PRB. Our expected 2017 sales volumes for met coal are approximately 3.9 million tons in CAPP, 0.3 million tons in NAPP and 3.5 million tons supplied through our Trading and Logistics business. Our expected 2017 sales for steam coal are approximately 31.5 million tons in the PRB, 7.9 million tons in NAPP and 0.1 million tons in CAPP.
Sales Agreements
Steam Coal. We enter into long-term supply agreements to sell our steam coal production in advance, thereby reducing the risks associated with our steam portfolio in future years. As of April 21, 2017, we had contracted 2017 sales of approximately 29.3 million tons of steam coal at an average realized price per ton of $11.34 from our PRB segment and approximately 7.9 million tons of steam coal at an average realized price per ton of $42.40 from our NAPP segment. As of April 21, 2017, 94% of our steam coal supply is committed and priced for 2017. The table below outlines our current steam coal committed and priced volumes from 2017 to 2020.
Segment (tons in millions)
2017
2018
2019
2020
NAPP
7.9
4.1
2.5
2.0
PRB
29.3
15.9
7.2
4.5
Met Coal. Met coal sales are contracted differently based on the region where the customer is located. Domestic contracts are typically on an annual basis, while our export contracts are normally either on a quarterly or spot basis. As of April 21, 2017, we had contracted 2017 sales of approximately 2.6 million tons of met coal at an average realized price per ton of $128.30 from our CAPP segment and approximately 0.1 million tons of met coal at an average realized price per ton of $87.91 from our NAPP segment.
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 steam 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 mine complexes to the applicable outbound shipping port, and our realized price per ton reflects the conversion of such tonnage from metric tons into short tons, as well as transportation costs from mine to port. In addition, for domestic sales contracts, as customers typically bear the cost of transportation from our mine complexes, 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.

63



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.
Our management strives to aggressively control costs and improve operating performance to mitigate external cost pressures. We have experienced volatility in operating costs related to fuel, explosives, steel, tires, contract services, and healthcare, among others, and have taken 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.
In addition, our stock-based compensation awards outstanding prior to this offering vest upon the later of a service condition, a change in control, which includes this offering, or termination of employment. In connection with this offering, we expect to incur approximately $25.0 million in accelerated stock-based compensation expense, which will be recognized upon the completion of this offering. See “Executive Compensation” and Note 19 in the financial statements included elsewhere in this prospectus for additional information about our stock compensation plans.
Results of Operations
Our results of operations for the Successor period from July 26, 2016 to December 31, 2016 and the Predecessor period from January 1, 2016 to July 25, 2016 and years ended December 31, 2015 and 2014 are discussed in these “Results of Operations” presented below. References to the year ended December 31, 2016 in the discussion are to the combined Successor and Predecessor periods for 2016 unless otherwise indicated. Such combined results are not comparable to our pro forma results of operations for the year ended December 31, 2016 presented elsewhere in this prospectus.

64



Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Revenues
 
Successor
 
 
Predecessor
(In thousands, except for per ton data)
Period from
July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended
December 31, 2015
Revenues:
 
 
 
 
 
 
Coal revenues:
 
 
 
 
 
 
Steam
$
299,744

 
 
$
389,764

 
$
862,040

Met
312,503

 
 
147,556

 
381,650

Freight and handling revenues
70,544

 
 
52,076

 
97,237

Other revenues
6,628

 
 
18,542

 
20,704

Total revenues
$
689,419

 
 
$
607,938

 
$
1,361,631

 
 
 
 
 
 
 
Tons sold:
 
 
 
 
 
 
Steam
19,413

 
 
21,649

 
46,209

Met
3,068

 
 
2,576

 
5,501

Total
22,481

 
 
24,225

 
51,710

 
 
 
 
 
 
 
Coal sales realization per ton:
 
 
 
 
 
 
Steam
15.44

 
 
18.00

 
18.66

Met
101.86

 
 
57.28

 
69.38

Average
27.23

 
 
22.18

 
24.05

 
Successor
 
 
Predecessor
(In thousands, except for per ton data)
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended
December 31, 2015
Coal revenues (1):
 
 
 
 
 
 
CAPP Operations
$
137,981

 
 
$
131,640

 
$
298,810

NAPP Operations
129,961

 
 
204,473

 
468,178

PRB Operations
180,555

 
 
192,629

 
427,680

Trading and Logistics Operations
163,750

 
 
8,578

 
49,022

Total coal revenues
$
612,247

 
 
$
537,320

 
$
1,243,690

Tons sold:
 
 
 
 
 
 
CAPP Operations
1,388

 
 
2,189

 
4,099

NAPP Operations
2,888

 
 
4,654

 
8,953

PRB Operations
16,674

 
 
17,225

 
37,971

Trading and Logistics Operations
1,531

 
 
157

 
687

 
 
 
 
 
 
 
Coal sales realization per ton (1):
 
 
 
 
 
 
CAPP Operations
99.41

 
 
60.14

 
72.90

NAPP Operations
45.00

 
 
43.93

 
52.29

PRB Operations
10.83

 
 
11.18

 
11.26

Trading and Logistics Operations
106.96

 
 
54.64

 
71.36

Average
27.23

 
 
22.18

 
24.05

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

65



Total revenues decreased $64.3 million, or 5%, for the twelve months ended December 31, 2016 compared to the prior year period. The decrease in total revenues was primarily related to decreased coal revenues of $94.1 million, partially offset by increased freight and handling revenues of $25.4 million, and increased other revenues of $4.5 million.
Coal revenues. Coal revenues decreased $94.1 million, or approximately 8%, for the twelve months ended December 31, 2016 compared to the prior year period. The decrease in coal revenues consisted of decreases in CAPP, NAPP, and PRB steam and met coal revenues offset by an increase in Trading and Logistics Operations.
Our sales mix of met coal and steam coal based on volume was 12% and 88%, respectively, for the twelve months ended December 31, 2016 compared with 11% and 89% in the prior year period. Our sales mix of met coal and steam coal based on coal revenues was 40% and 60%, respectively, for the twelve months ended December 31, 2016 compared with 31% and 69%, respectively, in the prior year period.
The decrease in coal revenues was due primarily to lower coal sales volumes partially offset by a slightly higher average coal sales realization of $0.56 per ton. Met coal volumes increased 0.1 million and average coal realization increased $12.13 year over year. However, a decrease in steam volumes of 5.1 million tons and a reduction in average coal realization of $1.86 compared to the prior year resulted in lower total coal sales. The decrease in coal revenues consisted of decreased steam coal revenues of $172.5 million partially offset by increased met coal revenues of $78.4 million.
Freight and handling. Freight and handling revenues and costs were $122.6 million for the twelve months ended December 31, 2016, an increase of $25.4 million, or 26%, compared to the prior year period. The increase was primarily due to a 1.0 million ton increase in export sales and a $30.73 increase in export sales realization per ton.
Other revenues. Other revenues increased $4.5 million, or 22%, for the twelve months ended December 31, 2016 compared to the prior year period, primarily attributable to an $8.7 million increase in coal sales contract buyouts, offset by a $2.2 million decrease in coal royalty revenues and a $2.0 million decrease in terminal fee revenues.
Costs and Expenses
 
Successor
 
 
Predecessor
(In thousands, except for per ton data)
Period from
July 26, 2016 to December 31, 2016
 
 
Period from
January 1, 2016 to July 25, 2016
 
Year Ended
December 31, 2015
Cost of coal sales (exclusive of items shown separately below)
$
465,764

 
 
$
489,652

 
$
1,106,046

Freight and handling costs
70,544

 
 
52,076

 
97,237

Other expenses
2,559

 
 
4,893

 
(931
)
Depreciation, depletion and amortization
43,978

 
 
85,379

 
202,115

Amortization of acquired intangibles, net
61,281

 
 
11,567

 
2,223

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

 
 
29,567

 
44,158

Mark-to-market adjustment for acquisition-related obligations
(10,616
)
 
 
—

 
—

Asset impairment and restructuring
—

 
 
3,755

 
558,699

Total costs and expenses
$
652,645

 
 
$
676,889

 
$
2,009,547


66



Other (expense) income:
 
 
 
 
 
 
   Interest expense
(20,792
)
 
 
(63
)
 
(437
)
   Interest income
23

 
 
29

 
4

Mark-to-market adjustment for warrant derivative liability
(33,975
)
 
 
—

 
—

   Bargain purchase gain
7,719

 
 
—

 
—

   Equity loss in affiliates
(2,280
)
 
 
(2,726
)
 
(7,700
)
   Miscellaneous income, net
232

 
 
683

 
28

Total other expense, net
(49,073
)
 
 
(2,077
)
 
(8,105
)
Reorganization items, net
—

 
 
(31,073
)
 
(16,134
)
Income tax benefit
1,369

 
 
34,889

 
254,595

Net loss
(10,930
)
 
 
(67,212
)
 
(417,560
)
 
 
 
 
 
 
 
Cost of coal sales:
 
 
 
 
 
 
CAPP Operations
95,328

 
 
135,126

 
302,323

NAPP Operations
106,781

 
 
181,911

 
384,848

PRB Operations
140,803

 
 
164,920

 
375,234

Trading and Logistics Operations
122,667

 
 
7,695

 
43,641

 
 
 
 
 
 
 
Tons sold:
 
 
 
 
 
 
CAPP Operations
1,388

 
 
2,189

 
4,099

NAPP Operations
2,888

 
 
4,654

 
8,953

PRB Operations
16,674

 
 
17,225

 
37,971

Trading and Logistics Operations
1,531

 
 
157

 
687

 
 
 
 
 
 
 
Cost of coal sales per ton (1):
 
 
 
 
 
 
CAPP Operations
68.68

 
 
61.73

 
73.76

NAPP Operations
36.97

 
 
39.09

 
42.99

PRB Operations
8.44

 
 
9.57

 
9.88

Trading and Logistics Operations
80.12

 
 
49.01

 
63.52

 
 
 
 
 
 
 
Coal margin per ton (2):
 
 
 
 
 
 
CAPP Operations
30.73

 
 
(1.59
)
 
(0.86
)
NAPP Operations
8.03

 
 
4.85

 
9.31

PRB Operations
2.38

 
 
1.61

 
1.38

Trading and Logistics Operations
26.83

 
 
5.63

 
7.83

______________
(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.

Cost of coal sales. Cost of coal sales decreased $150.6 million, or approximately 14%, for the twelve months ended December 31, 2016 compared to the prior year period. The decrease in cost of coal sales was due primarily to decreased labor and benefit expenses of $60.3 million and decreased supplies and maintenance expenses of approximately $97.2 million related to our cost reduction measures.
Other expenses. Other expenses increased $8.4 million for the twelve months ended December 31, 2016 compared to the prior year period, due primarily to $9.3 million of gain related to mark-to-market fair value

67



adjustments for our diesel fuel swaps recognized in the prior year which we did not have in the twelve months ended December 31, 2016.
Depreciation, depletion and amortization. Depreciation, depletion, and amortization decreased $72.8 million, or 36%, for the twelve months ended December 31, 2016 compared to the prior year period. The decrease was primarily a result of the change in the basis of property, plant and equipment and asset retirement obligation assets to their estimated fair value in connection with the Acquisition.
Amortization of acquired intangibles, net. Amortization expense of acquired intangibles, net increased $70.6 million for the twelve months ended December 31, 2016 compared to the prior year period. This increase was primarily attributable to the acquisition accounting impact on the estimated fair value of the intangibles recorded in connection with the Acquisition.
Selling, general and administrative expenses. Selling, general and administrative expenses increased $4.5 million, or 10%, for the twelve months ended December 31, 2016 compared to the prior year period. The increase in selling, general and administrative expenses was driven by an $8.0 million increase in incentive pay plus other administrative items, offset by a $4.5 million decrease in legal fees. In connection with our formation, we incurred $4.2 million of company formation and initial start-up related costs during the period from July 26, 2016 to December 31, 2016.
Mark-to-market adjustment for acquisition-related obligations. 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 Funding of Restricted Cash Reclamation. See Note 12 and Note 15 in the audited financial statements included elsewhere in this prospectus for disclosures related to acquisition-related obligations.
Asset impairment and restructuring. Asset impairment and restructuring expenses were $3.8 million for the twelve months ended December 31, 2016. Asset impairment and restructuring expenses were $558.7 million for the twelve months ended December 31, 2015. For the year ended December 31, 2015, we recorded $556.2 million in impairment charges, of which $72.0 million was recorded for asset groups in CAPP Operations, $224.1 million was recorded for asset groups in NAPP Operations, and $260.0 million was recorded on asset groups in the PRB Operations. The remaining $2.5 million related to severance costs and expenses related to non-core property divestitures. See Critical Accounting Policies and Note 9 to the audited financial statements included elsewhere in this prospectus.
Interest expense. Interest expense of $20.8 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. Alpha used a centralized approach to cash management and financing of its operations. The majority of our 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 we would have been able to finance its operations had it been a stand-alone business separate from Alpha during the Predecessor period.
Mark-to-market adjustment for warrant derivative liability. The mark-to-market loss on the warrant derivative liability related to the warrants issued in connection with the Acquisition of $34.0 million for the period from July 26, 2016 to December 31, 2016 was calculated using the Black-Scholes pricing model. See Notes 14 and Note 15 in the audited financial statements included elsewhere in this prospectus for additional disclosures related to the warrant derivative liability.
Bargain purchase gain. 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. See Note 3 in the audited financial statements included elsewhere in this prospectus for disclosures related to the Acquisition and the bargain purchase gain.

68



Reorganization items, net. Reorganization items, net primarily consist of realized gains and losses from the settlement of pre-petition liabilities, professional fees, and provisions for losses resulting from Alpha’s Restructuring. Reorganization items, net increased $14.9 million, or 93%, during the twelve months ended December 31, 2016 compared to the prior year period primarily due to a $14.1 million increase in professional fees. Refer to Note 20 in the audited financial statements included elsewhere in this prospectus for disclosures related to reorganization items, net. 
Income tax benefit. Income tax benefit of $36.3 million was recorded for the twelve months ended December 31, 2016 on a loss before income taxes of $114.4 million. The benefit rate is lower than the federal statutory rate of 35% primarily due to the impact of the non-deductible mark-to-market adjustment for the warrant derivative liability and the non-deductible transaction costs, partially offset by the impact of the percentage depletion allowance and the decrease in the valuation allowance.
Income tax benefit of $254.6 million was recorded for the twelve months ended December 31, 2015 on a loss before income taxes of $672.2 million. The benefit rate is higher than 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.
Segment Adjusted EBITDA
Segment Adjusted EBITDA per ton 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 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
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Consolidated
Net income (loss)
$
37,436

 
$
26,434

 
$
1,467

 
$
(22,053
)
 
$
(54,214
)
 
$
(10,930
)
Interest expense
97

 
171

 
296

 
—

 
20,228

 
$
20,792

Interest income
(6
)
 
—

 
—

 
—

 
(17
)
 
$
(23
)
Income tax benefit
—

 
—

 
—

 
—

 
(1,369
)
 
$
(1,369
)
Depreciation, depletion and amortization
6,442

 
(772
)
 
38,005

 
—

 
303

 
$
43,978

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
)
Amortization of acquired intangibles, net
—

 
—

 
—

 
61,281

 
—

 
$
61,281

Adjusted EBITDA
$
43,969

 
$
25,833

 
$
39,768

 
$
39,228

 
$
(19,429
)
 
$
129,369


69



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
(In thousands)
CAPP
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Combined
Net (loss) income
$
(26,407
)
 
$
(43,143
)
 
$
(679
)
 
$
(1,452
)
 
$
4,469

 
$
(67,212
)
Interest expense
2

 
—

 
61

 
—

 
—

 
$
63

Interest income
(9
)
 
(10
)
 
(10
)
 
—

 
—

 
$
(29
)
Income tax benefit
—

 
—

 
—

 
—

 
(34,889
)
 
$
(34,889
)
Depreciation, depletion and amortization
15,389

 
49,852

 
19,303

 
3

 
832

 
$
85,379

Reorganization items, net
8,196

 
12,528

 
10,084

 
248

 
17

 
$
31,073

Restructuring
1,667

 
1,408

 
659

 
21

 
—

 
$
3,755

Amortization of acquired intangibles, net
—

 
11,567

 
—

 
—

 
—

 
$
11,567

Adjusted EBITDA
$
(1,162
)
 
$
32,202

 
$
29,418

 
$
(1,180
)
 
$
(29,571
)
 
$
29,707

The following table presents a reconciliation of net (loss) income to Adjusted EBITDA for the year ended December 31, 2015:
 
Predecessor
 
Year ended December 31, 2015
(In thousands)
CAPP
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Combined
Net (loss) income
$
(118,543
)
 
$
(249,090
)
 
$
(259,317
)
 
$
795

 
$
208,595

 
$
(417,560
)
Interest expense
28

 
—

 
409

 
—

 
—

 
$
437

Interest income
(3
)
 
(1
)
 
—

 
—

 
—

 
$
(4
)
Income tax benefit
—

 
—

 
—

 
—

 
(254,595
)
 
$
(254,595
)
Depreciation, depletion and amortization
42,869

 
104,479

 
52,918

 
13

 
1,836

 
$
202,115

Reorganization items, net
3,438

 
6,306

 
6,049

 
336

 
5

 
$
16,134

Asset impairment and restructuring
73,585

 
223,719

 
261,274

 
121

 
—

 
$
558,699

Mark-to-market adjustment for other derivatives
(2,635
)
 
(446
)
 
(6,263
)
 
—

 
—

 
$
(9,344
)
Amortization of acquired intangibles, net
350

 
1,873

 
—

 
—

 
—

 
$
2,223

Adjusted EBITDA
$
(911
)
 
$
86,840

 
$
55,070

 
$
1,265

 
$
(44,159
)
 
$
98,105


70



The following table summarizes Adjusted EBITDA for our four reportable segments and All Other category:
 
Successor
 
 
Predecessor
(In thousands)
Period from
July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended
December 31, 2015
Adjusted EBITDA:
 
 
 
 
 
 
CAPP Operations
$
43,969

 
 
$
(1,162
)
 
$
(911
)
NAPP Operations
25,833

 
 
32,202

 
86,840

PRB Operations
39,768

 
 
29,418

 
55,070

Trading and Logistics Operations
39,228

 
 
(1,180
)
 
1,265

All Other
(19,429
)
 
 
(29,571
)
 
(44,159
)
Total
$
129,369

 
 
$
29,707

 
$
98,105

CAPP Coal Operations. Adjusted EBITDA increased $43.7 million for the twelve months ended December 31, 2016 compared to the prior year period. The increase in Adjusted EBITDA was primarily due to increased coal margin per ton of $11.81. The increase in coal margin per ton consisted of increased average coal sales realization per ton of $2.48, or approximately 3%, due primarily to a challenging met pricing environment, and decreased cost of coal sales per ton of $9.33, or 13%, due primarily to decreased labor and benefit expenses and decreased supplies and maintenance expenses primarily related to our cost reduction measures, and decreased sales-related variable costs associated with decreased coal revenues.
NAPP Coal Operations. Adjusted EBITDA decreased $28.8 million, or 33%, for the twelve months ended December 31, 2016 compared to the prior year period. The decrease in Adjusted EBITDA was primarily due to decreased coal margin per ton of $3.24. The decrease in coal margin per ton consisted of decreased average coal sales realization per ton of $7.95, or 15%, due primarily to customer mix and roll off of higher priced contracts year over year, offset partially by decreased cost of coal sales per ton of $4.71, or 11%.
PRB Coal Operations. Adjusted EBITDA increased $14.1 million, or 26%, for the twelve months ended December 31, 2016 compared to the prior year period. The increase in Adjusted EBITDA was primarily due to increased coal margin per ton of $0.61, or 44%. The increase in coal margin per ton consisted of decreased average coal sales realization per ton of $0.25, or 2%, due primarily to customer mix and roll off of higher priced contracts year over year, more than offset by decreased cost of coal sales per ton of $0.86, or 9%.
Trading and Logistics Operations. Adjusted EBITDA increased $36.8 million for the twelve months ended December 31, 2016 compared to the prior year period. The increase in Adjusted EBITDA was primarily due to increased coal margin per ton of $17.03. The increase in coal margin per ton consisted of increased average coal sales realization per ton of $30.73, or 43%, due to improvements in the met pricing environment, offset partially by increased cost of coal sales per ton of $13.71, or 22% due to increased prices of coal purchased from third parties.
All Other category. Adjusted EBITDA decreased $4.8 million, or 11%, for the twelve months ended December 31, 2016 compared to the prior year period. The decrease in adjusted EBITDA was primarily driven by an $8.0 million increase in incentive pay plus other administrative items, offset by a $4.5 million decrease in legal fees.

71



Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Revenues
(In thousands, except for per ton data)
Predecessor
Year Ended December 31, 2015
 
Year Ended December 31, 2014
 
Increase (Decrease)
$ or ton change
 
% change
Revenues:
 
 
 
 
 
 
 
Coal revenues:
 
 
 
 
 
 
 
Steam
$
862,040

 
$
1,063,829

 
$
(201,789
)
 
(19.0
)%
Met
381,650

 
400,487

 
(18,837
)
 
(4.7
)%
Freight and handling revenues
97,237

 
98,109

 
(872
)
 
(0.9
)%
Other revenues
20,704

 
24,600

 
(3,896
)
 
(15.8
)%
Total revenues
$
1,361,631

 
$
1,587,025

 
$
(225,394
)
 
(14.2
)%
 
 
 
 
 
 
 
 
Tons sold:
 
 
 
 
 
 
 
Steam
46,209

 
47,479

 
(1,270
)
 
(2.7
)%
Met
5,501

 
4,850

 
651

 
13.4
 %
Total
51,710

 
52,329

 
(619
)
 
(1.2
)%
 
 
 
 
 
 
 
 
Coal sales realization per ton:
 
 
 
 
 
 
 
Steam
18.66

 
22.41

 
(3.75
)
 
(16.7
)%
Met
69.38

 
82.57

 
(13.19
)
 
(16.0
)%
Average
24.05

 
27.98

 
(3.93
)
 
(14.0
)%
(In thousands, except for per ton data)
Predecessor
Year Ended
December 31, 2015
 
Year Ended
December 31, 2014
 
Increase (Decrease)
$ or ton change
 
% change
Coal revenues (1):
 
 
 
 
 
 
 
CAPP Operations
$
298,810

 
$
348,817

 
$
(50,007
)
 
(14.3
)%
NAPP Operations
468,178

 
613,341

 
(145,163
)
 
(23.7
)%
PRB Operations
427,680

 
436,930

 
(9,250
)
 
(2.1
)%
Trading and Logistics Operations
49,022

 
65,228

 
(16,206
)
 
(24.8
)%
Total coal revenues
$
1,243,690

 
$
1,464,316

 
$
(220,626
)
 
(15.1
)%
Tons sold:
 
 
 
 

 


CAPP Operations
4,099

 
4,130

 
(31
)
 
(0.8
)%
NAPP Operations
8,953

 
10,969

 
(2,016
)
 
(18.4
)%
PRB Operations
37,971

 
36,465

 
1,506

 
4.1
 %
Trading and Logistics Operations
687

 
766

 
(79
)
 
(10.3
)%
 
 
 
 
 


 


Coal sales realization per ton (1):
 
 
 
 


 


CAPP Operations
72.90

 
84.46

 
(11.56
)
 
(13.7
)%
NAPP Operations
52.29

 
55.92

 
(3.63
)
 
(6.5
)%
PRB Operations
11.26

 
11.98

 
(0.72
)
 
(6.0
)%
Trading and Logistics Operations
71.36

 
85.15

 
(13.79
)
 
(16.2
)%
Average
24.05

 
27.98

 
(3.93
)
 
(14.0
)%
______________
(1)
Does not include any portion of the price paid by our export customers to transport coal to the relevant outbound shipping port.

72



Total revenues decreased $225.4 million, or 14%, for the twelve months ended December 31, 2015 compared to the prior year period. The decrease in total revenues was due to decreased coal revenues of $220.6 million, decreased freight and handling revenues of $0.9 million, and decreased other revenues of $3.9 million.
Coal revenues. Coal revenues decreased $220.6 million, or 15%, for the twelve months ended December 31, 2015 compared to the prior year period. The decrease in coal revenues consisted of decreases in CAPP, NAPP, PRB steam and met coal revenues and Trading and Logistics Operations.
Our sales mix of met coal and steam coal based on volume was 11% and 89%, respectively, for the twelve months ended December 31, 2015 compared with 9% and 91% in the prior year period. Our sales mix of met coal and steam coal based on coal revenues was 31% and 69%, respectively, for the twelve months ended December 31, 2015 compared with 27% and 73%, respectively, in the prior year period.
The decrease in coal revenues was due primarily to lower coal sales volumes and lower average coal sales realization per ton and lower activity within the NAPP and Trading and Logistics segments. The decrease in coal revenues consisted of decreased met coal revenues of $18.8 million and decreased steam coal revenues of $201.8 million.
Freight and handling. Freight and handling revenues and costs were $97.2 million for the twelve months ended December 31, 2015, a decrease of $0.9 million, or 1%, compared to the prior year period. The decrease was primarily due to decreased freight rates and export shipments compared to the prior year.
Other revenues. Other revenues decreased $3.9 million, or 16%, for the twelve months ended December 31, 2015 compared to the prior year period, primarily attributable to a $5.2 million decrease in coal royalty revenues, partially offset by a $2.2 million increase in coal processing revenues.
Costs and Expenses
(In thousands, except for per ton data)
Predecessor
Year Ended
December 31, 2015
 
Year Ended
December 31, 2014
 
Increase (Decrease)
$ or ton change
 
% change
Cost of coal sales (exclusive of items shown separately below)
$
1,106,046

 
$
1,202,612

 
(96,566
)
 
(8.0
)%
Freight and handling costs
97,237

 
98,109

 
(872
)
 
(0.9
)%
Other expenses
(931
)
 
15,473

 
(16,404
)
 
(106.0
)%
Depreciation, depletion and amortization
202,115

 
203,361

 
(1,246
)
 
(0.6
)%
Amortization of acquired intangibles, net
2,223

 
(1,699
)
 
3,922

 
(230.8
)%
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization shown separately above)
44,158

 
52,256

 
(8,098
)
 
(15.5
)%
Asset impairment and restructuring
558,699

 
6,849

 
551,850

 
8,057.4
 %
Goodwill impairment
—

 
70,017

 
(70,017
)
 
(100.0
)%
Total costs and expenses
2,009,547

 
1,646,978

 
362,569

 
22.0
 %
Other (expense) income:
 
 
 
 

 


   Interest expense
(437
)
 
(712
)
 
(275
)
 
(38.6
)%
   Interest income
4

 
7

 
(3
)
 
(42.9
)%
   Equity loss in affiliates
(7,700
)
 
(9,810
)
 
(2,110
)
 
(21.5
)%
   Miscellaneous income, net
28

 
383

 
(355
)
 
(92.7
)%
Total other expense, net
(8,105
)
 
(10,132
)
 
(2,027
)
 
(20.0
)%

73



Reorganization items, net
(16,134
)
 
—

 
16,134

 
100.0
 %
Income tax benefit
254,595

 
17,740

 
236,855

 
1,335.1
 %
Net loss
(417,560
)
 
(52,345
)
 
365,215

 
697.7
 %
 
 
 
 
 
 
 
 
Cost of coal sales:
 
 
 
 

 


CAPP Operations
302,323

 
324,966

 
(22,643
)
 
(7.0
)%
NAPP Operations
384,848

 
412,973

 
(28,125
)
 
(6.8
)%
PRB Operations
375,234

 
411,280

 
(36,046
)
 
(8.8
)%
Trading and Logistics Operations
43,641

 
53,393

 
(9,752
)
 
(18.3
)%
 
 
 
 
 

 


Tons sold:
 
 
 
 

 


CAPP Operations
4,099

 
4,130

 
(31
)
 
(0.8
)%
NAPP Operations
8,953

 
10,969

 
(2,016
)
 
(18.4
)%
PRB Operations
37,971

 
36,465

 
1,506

 
4.1
 %
Trading and Logistics Operations
687

 
766

 
(79
)
 
(10.3
)%
 
 
 
 
 

 


Cost of coal sales per ton (1):
 
 
 
 

 


CAPP Operations
73.76

 
78.68

 
(4.93
)
 
(6.3
)%
NAPP Operations
42.99

 
37.65

 
5.34

 
14.2
 %
PRB Operations
9.88

 
11.28

 
(1.40
)
 
(12.4
)%
Trading and Logistics Operations
63.52

 
69.70

 
(6.18
)
 
(8.9
)%
 
 
 
 
 
 
 
 
Coal margin per ton (2):
 
 
 
 
 
 
 
CAPP Operations
(0.86
)
 
5.77

 
(6.63
)
 
(114.9
)%
NAPP Operations
9.31

 
18.27

 
(8.96
)
 
(49.0
)%
PRB Operations
1.38

 
0.70

 
0.68

 
97.1
 %
Trading and Logistics Operations
7.83

 
15.45

 
(7.62
)
 
(49.3
)%
______________
(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.

Cost of coal sales. Cost of coal sales decreased $96.6 million, or 8%, for the twelve months ended December 31, 2015 compared to the prior year period. The decrease in cost of coal sales was due primarily to decreased labor and benefit expenses of $35.5 million, decreased supplies and maintenance expenses of approximately $48.8 million related to our cost reduction measures, and decreased coal purchases from third parties of $16.3 million.
Other expenses. Other expenses decreased $16.4 million, or 106%, for the twelve months ended December 31, 2015 compared to the prior year period, primarily due to an $18.2 million favorable change in mark-to-market fair value adjustments for our diesel fuel swaps.
Depreciation, depletion and amortization. Depreciation, depletion, and amortization decreased $1.2 million, or 1%, for the twelve months ended December 31, 2015 compared to the prior year period. The increase was primarily due to increased depletion offset by decreased depreciation expense related to lower capital expenditures over the last twelve months compared to the same time period in the prior year.

74



Amortization of acquired intangibles, net. Amortization expense of acquired intangibles, net increased $3.9 million for the twelve months ended December 31, 2015 compared to the prior year period. The increase in expense for amortization of acquired intangibles, net, was primarily due to decreased amortization of below-market contracts due to the completion of shipments in the prior year of many of the contracts.
Selling, general and administrative. Selling, general and administrative expenses decreased $8.1 million, or 16%, for the twelve months ended December 31, 2015 compared to the prior year period. The decrease in selling, general and administrative expenses was primarily attributable to decreased stock compensation expense of $7.2 million.
Asset impairment and restructuring. Asset impairment and restructuring expenses were $558.7 million for the twelve months ended December 31, 2015 and consisted of impairment charges of $556.2 million and severance related expenses of $2.5 million and consisted primarily of severance and related benefits, professional fees for consulting, and reserves for other assets that may not be recoverable. See Critical Accounting Policies and Note 9 to the audited financial statements included elsewhere in this prospectus.
Goodwill impairment. There were no goodwill impairment expenses recorded for the year ended December 31, 2015, as there was no goodwill remaining as of December 31, 2014.
Reorganization items, net. The increase in 2015 was due to Alpha’s bankruptcy filing in August 2015. Refer to Note 20 in the Consolidated Financial Statements included elsewhere in this report for disclosures related to reorganization items.
Income taxes. Income tax benefit of $254.6 million was recorded for the twelve months ended December 31, 2015 on a loss before income taxes of $672.2 million. The benefit rate is higher than 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.
Income tax benefit of $17.7 million was recorded for the twelve months ended December 31, 2014 on a loss before income taxes of $70.1 million. The benefit rate is lower than the federal statutory rate of 35% primarily due to the impact of the non-deductible goodwill impairment and non-deductible stock-based compensation, partially offset by the impact of the percentage depletion allowance.

75



Segment Adjusted EBITDA
Segment Adjusted EBITDA per ton 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 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 year ended December 31, 2015:
 
Predecessor
 
Year ended December 31, 2015
(In thousands)
CAPP
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Combined
Net (loss) income
$
(118,543
)
 
$
(249,090
)
 
$
(259,317
)
 
$
795

 
$
208,595

 
$
(417,560
)
Interest expense
28

 
—

 
409

 
—

 
—

 
$
437

Interest income
(3
)
 
(1
)
 
—

 
—

 
—

 
$
(4
)
Income tax benefit
—

 
—

 
—

 
—

 
(254,595
)
 
$
(254,595
)
Depreciation, depletion and amortization
42,869

 
104,479

 
52,918

 
13

 
1,836

 
$
202,115

Reorganization items, net
3,438

 
6,306

 
6,049

 
336

 
5

 
$
16,134

Asset impairment and restructuring
73,585

 
223,719

 
261,274

 
121

 
—

 
$
558,699

Mark-to-market adjustment for other derivatives
(2,635
)
 
(446
)
 
(6,263
)
 
—

 
—

 
$
(9,344
)
Amortization of acquired intangibles, net
350

 
1,873

 
—

 
—

 
—

 
$
2,223

Adjusted EBITDA
$
(911
)
 
$
86,840

 
$
55,070

 
$
1,265

 
$
(44,159
)
 
$
98,105

The following table presents a reconciliation of net (loss) income to Adjusted EBITDA for the year ended December 31, 2014:
 
Predecessor
 
Year ended December 31, 2014
(In thousands)
CAPP
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Combined
Net (loss) income
$
(102,830
)
 
$
114,952

 
$
(33,972
)
 
$
6,697

 
$
(37,192
)
 
$
(52,345
)
Interest expense
87

 
14

 
611

 
—

 
—

 
$
712

Interest income
(3
)
 
(1
)
 
(3
)
 
—

 
—

 
$
(7
)
Income tax benefit
—

 
—

 
—

 
—

 
(17,740
)
 
$
(17,740
)
Depreciation, depletion and amortization
55,487

 
89,970

 
55,224

 
4

 
2,676

 
$
203,361

Goodwill impairment
70,017

 
—

 
—

 
—

 
—

 
$
70,017

Restructuring
1,092

 
5,627

 
117

 
13

 
—

 
$
6,849

Mark-to-market adjustment for other derivatives
599

 
—

 
8,293

 
—

 
—

 
$
8,892

Amortization of acquired intangibles, net
454

 
(33
)
 
(2,120
)
 
—

 
—

 
$
(1,699
)
Adjusted EBITDA
$
24,903

 
$
210,529

 
$
28,150

 
$
6,714

 
$
(52,256
)
 
$
218,040


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The following table summarizes Adjusted EBITDA for our four reportable segments and All Other category:
(In thousands)
Predecessor
Year Ended December 31, 2015
 
Year Ended December 31, 2014
 
Increase (Decrease)
 
 
$ change
 
% change
Adjusted EBITDA:
 
 
 
 
 
 
 
CAPP Operations
$
(911
)
 
$
24,903

 
$
(25,814
)
 
(103.7
)%
NAPP Operations
86,840

 
210,529

 
(123,689
)
 
(58.8
)%
PRB Operations
55,070

 
28,150

 
26,920

 
95.6
 %
Trading and Logistics Operations
1,265

 
6,714

 
(5,449
)
 
(81.2
)%
All Other
(44,159
)
 
(52,256
)
 
8,097

 
(15.5
)%
Total
$
98,105

 
$
218,040

 
$
(119,935
)
 
(55.0
)%
CAPP Coal Operations. Adjusted EBITDA decreased $25.8 million, or 104%, for the twelve months ended December 31, 2015 compared to the prior year period. The decrease in Adjusted EBITDA was primarily due to decreased coal margin per ton of $6.63. The decrease in coal margin per ton consisted of decreased average coal sales realization per ton of $11.56, or approximately 14%, due primarily to a challenging met pricing environment, partially offset by decreased cost of coal sales per ton of $4.93 due primarily to decreased labor and benefit expenses and decreased supplies and maintenance expenses related to our cost reduction measures, and decreased sales-related variable costs associated with decreased coal revenues.
NAPP Coal Operations. Adjusted EBITDA decreased $123.7 million, or 59%, for the twelve months ended December 31, 2015 compared to the prior year period. The decrease in Adjusted EBITDA was primarily due to decreased coal margin per ton of $8.96. The decrease in coal margin per ton consisted of decreased average coal sales realization per ton of $3.63, or approximately 7%, due primarily to customer mix and roll off of higher priced contracts year over year, and increased cost of coal sales per ton of $5.34 due primarily to lower volumes as a result of decreasing production from the Emerald mining complex.
PRB Coal Operations. Adjusted EBITDA increased $26.9 million, or 96%, for the twelve months ended December 31, 2015 compared to the prior year period. The increase in Adjusted EBITDA was primarily due to increased coal margin per ton of $0.68. The increase in coal margin per ton consisted of decreased average coal sales realization per ton of $0.72, or approximately 6%, due primarily to customer mix and roll off of higher priced contracts year over year, more than offset by decreased cost of coal sales per ton of $1.40, or 12%, due primarily to higher volumes over the prior year.
Trading and Logistics Operations. Adjusted EBITDA decreased $5.4 million, or 81%, for the twelve months ended December 31, 2015 compared to the prior year period. The decrease in Adjusted EBITDA was primarily due to decreased coal margin per ton of $7.62, or 49%. The decrease in coal margin per ton consisted of decreased average coal sales realization per ton of $13.79, or 16%, due primarily to a challenging met pricing environment, partially offset by decreased cost of coal sales per ton of $6.18, or 9%, due primarily to lower costs for coal purchased from third parties.
All Other category. Adjusted EBITDA increased $8.1 million for the twelve months ended December 31, 2015 compared to the prior year period. The increase in adjusted EBITDA was driven by decreased stock compensation expense of $7.2 million.

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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.
At December 31, 2016, we had total liquidity of $127.9 million, comprised of cash and cash equivalents. On March 17, 2017, we entered into a $400.0 million Term Loan Credit Facility with a maturity date on March 17, 2024. On April 3, 2017, we entered into an $125.0 million Asset-Based Revolving Credit Agreement expiring on April 4, 2022, which had no borrowings outstanding as of May 1, 2017.
To secure our obligations under certain workers’ compensation and reclamation-related bonds, we are required to provide cash collateral. At December 31, 2016, we had cash collateral in the amounts of $43.3 million and $52.6 million classified as long-term restricted cash and long-term deposits, respectively, on our balance sheet.
Cash Flows
Cash and cash equivalents increased by $127.9 million, decreased by $0.2 million, increased by $0.2 million, and decreased by $26,000 (actual) over the period from July 26, 2016 to December 31, 2016, the period January 1, 2016 to July 25, 2016, and the years ended December 31, 2015 and 2014, respectively. The net change in cash and cash equivalents was attributable to the following:
 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Cash flows (in thousands):
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
70,918

 
 
$
60,690

 
$
150,862

 
$
165,103

Net cash provided by (used in) investing activities
15,552

 
 
(25,029
)
 
(97,034
)
 
(114,561
)
Net cash provided by (used in) financing activities
41,478

 
 
(35,822
)
 
(53,585
)
 
(50,568
)
Net increase (decrease) in cash and cash equivalents
$
127,948

 
 
$
(161
)
 
$
243

 
$
(26
)
Operating Activities
Net cash provided by operating activities for the period from July 26, 2016 to December 31, 2016 was $70.9 million. Non-cash amounts included in net loss for the period from July 26, 2016 to December 31, 2016 were primarily related to depreciation, depletion and amortization, amortization of acquired intangibles, net, the mark-to-market adjustment for the warrants derivative liability, mark-to-market adjustment for acquisition-related obligations and accretion of asset retirement obligations.
Net cash provided by operating activities for the period from January 1, 2016 to July 25, 2016 was $60.7 million. Non-cash amounts included in net loss for the period from January 1, 2016 to July 25, 2016 were primarily related to depreciation, depletion and amortization, amortization of acquired intangibles, net, accretion of asset retirement obligations, deferred income taxes, and non-cash reorganization items.

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Net cash provided by operating activities for the year ended December 31, 2015 was $150.9 million. Non-cash amounts included in the net loss for the year ended December 31, 2015 primarily included depreciation, depletion and amortization, deferred income taxes and asset impairment and restructuring.
Net cash provided by operating activities for the year ended December 31, 2014 was $165.1 million. Non-cash amounts included in the net loss for the year ended December 31, 2014 were primarily attributable to depreciation, depletion and amortization, goodwill impairment and deferred income taxes.
Investing Activities
Net cash provided by investing activities for the period from July 26, 2016 to December 31, 2016 was $15.6 million. The cash provided by investing activities for the period from July 26, 2016 to December 31, 2016 primarily included cash acquired in the Acquisition of $51.0 million 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 from the sale of property, plant and equipment.
Net cash used in investing activities for the year ended December 31, 2015 was $97.0 million, primarily driven by capital expenditures of $59.5 million and acquisition of mineral rights under federal lease of $42.1 million, partially offset by proceeds from the sale of property, plant and equipment of $10.5 million.
Net cash used in investing activities for the year ended December 31, 2014 was $114.6 million, primarily attributable to capital expenditures of $68.7 million and acquisition of mineral rights under federal lease of $42.1 million.
Financing Activities
Net cash provided by financing activities for the period from July 26, 2016 to December 31, 2016 was $41.5 million. The cash provided by financing activities for the period from July 26, 2016 to December 31, 2016 primarily included $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 and years ended December 31, 2015 and 2014 was $35.8 million, $53.6 million and $50.6 million, respectively, and were primarily attributable to transfers to Alpha.

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Long-Term Debt
As of December 31, 2016 and 2015, our long-term debt consisted of the following:
 
Successor
 
 
Predecessor
 
December 31,
2016
 
 
December 31,
2015
(in thousands)
 
 
 
 
Term Facility (1)
$
42,500

 
 
$
—

LC Facility
—

 
 
—

Closing Tranche Term Loan - due January 2018(1)
8,500

 
 
—

GUC Distribution Note - due January 2018 (1)
5,500

 
 
—

10% Senior Secured First Lien Notes - due August 2021 (1)
300,000

 
 
—

Other (2)
7,024

 
 
136

Debt discount and issuance costs
(14,363
)
 
 
—

Total long-term debt
349,161

 
 
136

Less current portion
(2,324
)
 
 
(68
)
Long-term debt, net of current portion
$
346,837

 
 
$
68

______________
(1)
On March 17, 2017, we entered into a $400.0 million Term Loan Credit Facility with a maturity date on March 17, 2024. In connection with the transaction, we repaid all of our outstanding 10.00% Senior Secured First Lien Notes due 2021. The proceeds of the Term Loan Credit Facility were also used to repay the Term Facility due 2020, the Closing Tranche Term Loan due 2018 and the GUC Distribution Note due 2018. See Note 26 to our audited financial statement included elsewhere in this prospectus for further disclosures on this subsequent event.
(2)
On April 3, 2017, we entered into an Asset-Based Revolving Credit Agreement, under which we may borrow cash or draw letters of credit from, on a revolving basis, in an amount up to $125.0 million subject to certain limitations set forth therein. Any borrowings under the asset-based revolving credit facility will have a maturity date of April 4, 2022 and will bear interest at rates ranging from 1.00% to 2.50% depending on loan type. See Note 26 to our audited financial statement included elsewhere in this prospectus for further disclosures on this subsequent event.

Term Loan Credit Facility
On March 17, 2017, we entered into a $400.0 million Term Loan Credit Facility with a maturity date on March 17, 2024. The Term Loan Credit Facility carries an interest rate of LIBOR plus five percent, with a one percent LIBOR floor. In connection with the transaction, we repaid all of our outstanding 10.00% Senior Secured First Lien Notes due 2021. The aggregate principal amount outstanding of the notes was $300.0 million. The redemption price for the notes was equal to 107.5% of the principal amount thereof, including accrued interest, for a total payment to holders of the notes of approximately $329.0 million in aggregate. The proceeds of the Term Loan Credit Facility were used to repay certain other long-term liabilities including the Term Facility, the Closing Tranche Term Loan and the GUC Distribution Note, pay related fees, costs and expenses, and for general corporate purposes.
Asset-Based Revolving Credit Agreement
On April 3, 2017, we entered into an Asset-Based Revolving Credit Agreement with Citibank N.A. as administrative agent, collateral agent and swingline lender (the “Lender”), and Citibank N.A., BMO Harris Bank N.A. and Credit Suisse AG as letter of credit issuers (“LC Lenders”). The Asset-Based Revolving Credit Agreement includes a senior secured asset-based revolving credit facility (the “Facility”). Under the Facility, we may borrow cash from the Lender or cause the LC Lenders to issue letters of credit, on a revolving basis, in an amount up to

80



$125.0 million, subject to certain limitations set forth therein. Any borrowings under the Facility will have a maturity date of April 4, 2022 and will bear interest at rates ranging from 2.00% to 2.50% for Eurocurrency Rate Loans and 1.00% to 1.50% for Base Rate Loans, depending on the amount of credit available. No letters of credit were outstanding, no cash borrowing transactions had taken place and $125.0 million was available under the Facility.
The Term Loan Credit Facility and the Asset-Based Revolving Credit Agreement and related documents contained affirmative and negative covenants with no financial covenants.
Capital Leases
Our liability for capital leases, included in the other caption in the long-term debt table above, as of December 31, 2016 and 2015 totaled $2.7 million and $0.1 million, with $1.0 million and $0.1 million reported as the current portion of long-term debt as of December 31, 2016 and 2015, respectively.
Acquisition-Related Obligations
As of December 31, 2016, our acquisition-related obligations consisted of the following:
(in thousands)
December 31,
2016
Retiree Committee VEBA Funding Settlement Liability
$
10,000

UMWA Funds Settlement Liability
7,500

UMWA VEBA Funding Settlement Liability
9,300

UMWA Contingent VEBA Funding Note 1
8,750

UMWA Contingent VEBA Funding Note 2
8,750

Reclamation Funding Liability
42,000

Contingent Reclamation Funding Liability
20,370

Contingent Credit Support Commitment
4,567

Other
2,261

Discount
(27,152
)
Total acquisition-related obligations - long-term
86,346

Less current portion
(27,258
)
Acquisition-related obligations, net of current portion
$
59,088

We entered into various settlement agreements with Alpha and/or the Alpha bankruptcy successor ANR, Inc. (“ANR”) and third parties as part of the Alpha Restructuring. We assumed acquisition-related obligations through those settlement agreements which became effective on July 26, 2016, the effective date of Alpha’s Plan of Reorganization.
Contingent Credit Support Commitment
The Contingent Credit Support Commitment (“Contingent Commitment”) is an unsecured obligation to ANR that requires us to provide ANR with revolving credit support in an aggregate total amount of $35.0 million from July 26, 2016 (“Effective Date”) through September 30, 2018. ANR is entitled to draw against the Contingent Commitment if, and only if, the amount of cash and cash equivalents on ANR’s balance sheet falls below $20.0 million at any time prior to September 30, 2018 (the amount of any such shortfall, the “Shortfall”), in which case, ANR is entitled to draw against the Contingent Commitment an amount equal to the lesser of the Shortfall and the then-remaining undrawn amount of the Contingent Commitment. ANR is able to draw upon and repay the Contingent Commitment as necessary through September 30, 2018. We must fund a draw on the Contingent Commitment within 10 business days of notice from ANR. ANR will be required to repay the funds drawn against

81



the Contingent Commitment (i) prior to September 30, 2018 to the extent the amount of cash and cash equivalents on ANR’s balance sheet is greater than $20.0 million as of the end of any calendar quarter ending on or before September 30, 2018 (exclusive of the amount outstanding from the Contingent Commitment) or (ii) if any amounts are outstanding under the Contingent Commitment after September 30, 2018, to the extent the amount of cash and cash equivalents on ANR’s balance sheet at the end of any calendar quarter is greater than $30.0 million (exclusive of the amount outstanding from the Contingent Commitment), within 10 business days following the closing of its books for the relevant calendar quarter. Notwithstanding the above, all outstanding balances under the Contingent Commitment must be repaid by September 30, 2019.
As of December 31, 2016, ANR had not drawn against the Contingent Commitment. We are electing to use the fair value option to measure this liability at each reporting period. During the period from July 26, 2016 to December 31, 2016, we recorded a mark to market non-cash gain of $17.4 million, which is classified as other operating income in the Consolidated Statement of Operations. As of December 31, 2016, the carrying value of the Contingent Commitment was $4.6 million, all of which is classified as a loan commitment within acquisition-related obligations - current in our balance sheet.
Retiree Committee VEBA Funding Settlement
The Retiree Committee Settlement Agreement requires us to provide funding to the voluntary employees’ beneficiary association fund (“VEBA”) established by the retiree committee, which represented the interests of certain non-union Alpha retirees during the Alpha Restructuring, in an aggregate nominal amount of $13.0 million (the “Retiree Committee VEBA Funding Settlement Liability”) for the benefit of the VEBA beneficiaries pursuant to the following schedule: (a) $3.0 million within 10 business days after the later of the Effective Date or Alpha Natural Resources, Inc. and such subsidiaries (“Debtors”) receipt of written notice; (b) $3.0 million on January 1, 2017; (c) $3.5 million on January 1, 2018; (d) $2.5 million on January 1, 2019; and (e) $1.0 million on January 1, 2020. The initial $3.0 million installment was paid as part of the Alpha Restructuring settlement process and is therefore not reflected in our cash flows for the period from July 26, 2016 to December 31, 2016.
As of December 31, 2016, the carrying value of the Retiree Committee VEBA Funding Settlement liability is $8.3 million, net of discount of $1.7 million, and was classified as an acquisition-related obligation, with $3.0 million classified as current in our balance sheet. 
UMWA Funds Settlement
The UMWA Funds Settlement (“UMWA Funds Settlement”) provides for the Coal Act Funds, the 1974 Pension Plan, the 1993 Benefit Plan, the CDSP and the Account Plan (collectively, the “UMWA Funds”) to receive an initial distribution of $2.5 million in cash (to be allocated among the UMWA Funds by the UMWA Funds in their discretion) on the Effective Date. We are required to make periodic cash payments (to be allocated among the UMWA Funds by the UMWA Funds in their discretion) on the dates and in the amounts listed: December 31, 2017: $0.5 million; December 31, 2018: $1.0 million; December 31, 2019: $2.0 million; December 31, 2020: $2.0 million; December 31, 2021: $2.0 million. The initial distribution of $2.5 million was paid as part of the Alpha Restructuring settlement process and is not reflected in our cash flows for the period from July 26, 2016 to December 31, 2016.
As of December 31, 2016, the carrying value of the UMWA Funding Settlement liability was $4.0 million, net of discount of $3.5 million, and was classified as an acquisition-related obligation, with $0.5 million classified as current in our balance sheet. 
UMWA VEBA Funding and Contingent Notes Settlements
UMWA VEBA Funding
Pursuant to the UMWA VEBA Funding Settlement agreement entered into on July 5, 2016, we were required to contribute $10.0 million to a voluntary employees’ beneficiary association fund (the “VEBA trust”) on or before the Effective Date. Beginning on November 1, 2016, and again on the first of each month through April 1, 2017, we are

82



required to deposit $3.0 million into the VEBA trust (total of $18.0 million in six monthly payments). On or before November 15, 2016, and February 15, 2017 we are required to deposit $0.3 million into the VEBA trust (total of $0.6 million in two payments). The initial $10.0 million contribution was paid as part of the Alpha Restructuring settlement process and is not reflected in our cash flows for the period from July 26, 2016 to December 31, 2016. During the period from July 26, 2016 to December 31, 2016, we made $9.3 million of the required deposits, all of which was classified as operating activities in the Consolidated Statement of Cash Flows.
As of December 31, 2016, the carrying value of the UMWA VEBA Funding Settlement liability is $9.0 million, net of discount of $0.3 million, all of which was classified as an acquisition-related obligation - current in our balance sheet. 
UMWA Contingent VEBA Funding Notes
Pursuant to the UMWA VEBA Funding Settlement agreement entered into on July 5, 2016, if federal legislation providing retirement health benefits to the UMWA Retirees has not been enacted or if monies under the legislation have not become available for such benefits before August 1, 2017, on August 1, 2017, we are required to issue to the VEBA a 7-year 5% unsecured note (“UMWA Contingent VEBA Funding Note 1”) with a face value of $8.8 million. The note will have a maturity of seven years and will be subordinate to our Senior Secured First Lien Notes.
As of December 31, 2016, the carrying value of the UMWA Contingent VEBA Funding Note 1 was $4.3 million, net of discount of $4.4 million, all of which was classified as an acquisition-related obligation - long-term in our balance sheet. The MPA was introduced in the U.S. House on January 3, 2017 and in the Senate on January 17, 2017. On May 1, 2017, legislators announced that a tentative agreement had been reached on the Omnibus Appropriations Act, including funding of the MPA.
If federal legislation providing retirement health benefits to the UMWA Retirees has not been enacted or if moneys under the legislation have not become available for such benefits before December 1, 2017, on December 1, 2017, we are also required to issue to the VEBA a 7-year 5% unsecured note (“UMWA Contingent VEBA Funding Note 2”) with a face value of $8.8 million. The note will have a maturity of seven years and will be subordinate to our Senior Secured First Lien Notes.
As of December 31, 2016, the carrying value of the UMWA Contingent VEBA Funding Note 2 was $4.3 million, net of discount of $4.5 million, all of which was classified as an acquisition-related obligation - long-term in our balance sheet. 
Reclamation Funding Agreement
Pursuant to the Reclamation Funding Agreement dated July 12, 2016, separate interest bearing segregated deposit accounts (“Restricted Cash Reclamation Accounts”) were established for certain applicable federal and state environmental regulatory authorities to provide certain funding for the reclamation, mitigation and water treatment, and certain management work to be done at reclaim-only sites related to certain obligations under the various permits associated with ANR’s retained assets.
Funding of Restricted Cash Reclamation
Pursuant to the Reclamation Funding Agreement, we must pay the aggregate amount of $50.0 million into the various Restricted Cash Reclamation Accounts as follows: $8.0 million immediately upon the Effective Date; $10.0 million on the anniversary of the Effective Date in each of 2017, 2018, and 2019; and $12.0 million on the anniversary of the Effective Date in 2020. The initial $8.0 million payment was paid as part of the Alpha Restructuring settlement process and is not reflected in our cash flows for the period from July 26, 2016 to December 31, 2016.

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As of December 31, 2016, the carrying value of the Funding of Restricted Cash Reclamation liability is $29.2 million, net of discount of $12.8 million, with $10.0 million classified as current, all of which was classified as an acquisition-related obligation in our balance sheet. 
Contingent Funding of Restricted Cash Reclamation
Pursuant to the Reclamation Funding Agreement, under certain circumstances, we will be required to pay up to an aggregate amount of $50.0 million into various Restricted Cash Reclamation Accounts from 2021 through 2025 as follows: (i) if ANR does not contribute $50.0 million of free cash flow, as defined in the agreement, into the Restricted Cash Reclamation Accounts through December 31, 2020; and (ii) if ANR makes any reorganized ANR contingent revenue payment, as defined in the agreement, that reduces the amount of free cash flow that ANR otherwise would have contributed to the Restricted Cash Reclamation Accounts, then we will be obligated to pay the amount of the difference between (a) the amount of free cash flow that ANR would have contributed to the Restricted Cash Reclamation Accounts had it not made such reorganized ANR contingent revenue payment and (b) the amount of free cash flow actually contributed.
We are electing to use the fair value option to measure this liability at each reporting period. During the period from July 26, 2016 to December 31, 2016, we recorded a mark to market non-cash loss of $6.8 million which is classified as other operating income (loss) in the Consolidated Statement of Operations. As of December 31, 2016, the carrying value of the Contingent Funding of Restricted Cash Reclamation liability was $20.4 million, all of which was classified as an acquisition-related obligation - long-term in our balance sheet.
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, 2016, we had outstanding surety bonds with a total face amount of $315.1 million, respectively, to secure various obligations and commitments. To secure our obligations under these bonds, we had cash collateral in the amounts of $43.3 million and $52.6 million classified as long-term restricted cash and long-term deposits, respectively, on our balance sheet as of December 31, 2016.
As of December 31, 2016, we had mining equipment and real property collateralizing $102.4 million, respectively, 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. In the event that additional 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.

84



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, 2016:
(in thousands)
2017
 
2018-2019
 
2020-2021
 
After 2021
 
Total
Long-term debt (1)(2)
$
—

 
$
14,000

 
$
342,500

 
$
—

 
$
356,500

Other debt (3)
1,317

 
2,962

 
—

 
—

 
4,279

Capital lease obligations (4)
1,007

 
1,738

 
—

 
—

 
2,745

Acquisition-related obligations (5)(6)
22,800

 
29,000

 
17,000

 
17,500

 
86,300

Equipment purchase commitments
16,829

 
—

 
—

 
—

 
16,829

Maintenance and repairs contracts
22,374

 
25,326

 
12,651

 
4,830

 
65,181

Transportation commitments
921

 
6,114

 
3,102

 
—

 
10,137

Operating leases
1,147

 
802

 
76

 
363

 
2,388

Minimum royalties
3,284

 
1,315

 
468

 
734

 
5,801

Coal purchase commitments
47,021

 
—

 
—

 
—

 
47,021

Other (7)
2,197

 
4,393

 
2,197

 
—

 
8,787

Total
$
118,897

 
$
85,650

 
$
377,994

 
$
23,427

 
$
605,968

______________
(1)
Long-term debt includes principal amounts due in the years shown. Cash interest payable on these obligations, with interest rates ranging between 6.00% and 10.00% on our loans, would be approximately $33,067 in 2017, $65,258 in 2018 to 2019, and $49,621 in 2020 to 2021.
(2)
On March 17, 2017, we entered into a $400.0 million Term Loan Credit Facility with a maturity date in 2024. In connection with the transaction, we paid all of our outstanding 10.00% Senior Secured First Lien Notes due 2021. The proceeds of the Term Loan Credit Facility were used to repay the Term Facility due 2020, the Closing Tranche Term Loan due 2018 and the GUC Distribution Note due 2018. Cash interest payable on the Term Loan Credit Facility, with an interest rate of LIBOR plus five percent, with a one percent LIBOR floor, would be approximately $19,221 in 2017, $47,875 in 2018 to 2019, $46,966 in 2020 to 2021 and $50,715 after 2021, assuming interests rates as of April 30, 2017. Principal repayments on the Term Loan Credit Facility would be approximately $3,000 in 2017, $8,000 in 2018 to 2019, $8,000 in 2020 to 2021 and $381,000 after 2021.
(3)
Other debt includes principal amounts due in the years shown. Cash interest payable on these obligations, with an interest rate of 4.49%, would be approximately $133 in 2017 and $71 in 2018.
(4)
Capital lease obligations include principal amounts due in the years shown. Cash interest payable on these obligations with interest rates ranging between 4.72% and 9.50%, would be approximately $146 in 2017 and $106 in 2018 to 2019.
(5)
Acquisition-related obligations includes principal amounts due in the years shown. Cash interest payable on these obligations, with interest rates of 5.00%, would be approximately $219 in 2017, $1,750 in 2018 to 2019, $1,750 in 2020 to 2021, and $2,406 after 2021.

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(6)
Certain contingent liabilities and guarantees are excluded from the table above, for which the timing of payments are not estimable. See Note 11 for further disclosures related to these contingent liabilities and guarantees.
(7)
Personal property taxes assumed pursuant to the bankruptcy settlement include principal amounts due in the years shown. Cash interest payable on these obligations, with interest rates ranging between 5% and 18%, would be approximately $662 in 2017, $545 in 2018 to 2019, and $109 in 2020. Real estate taxes assumed pursuant to the bankruptcy settlement include principal amounts due in the years shown. Cash interest payable on these obligations, with interest rates ranging between 5% and 18%, would be approximately $849 in 2017, $599 in 2018 to 2019, and $120 in 2020.

Additionally, we have long-term liabilities relating to asset retirement obligations, black lung benefits, life insurance benefits, and workers’ compensation benefits. The table below reflects the estimated undiscounted cash flows for these obligations:
(in thousands)
2017
 
2018-2019
 
2020-2021
 
After 2021
 
Total
Asset retirement obligation
$
4,405

 
$
10,744

 
$
113,436

 
$
386,970

 
$
515,555

Black lung benefit obligation
—

 
—

 
16

 
43,184

 
43,200

Life insurance benefit obligation
866

 
1,533

 
1,349

 
18,854

 
22,602

Workers’ compensation benefit obligation
3,990

 
4,445

 
2,632

 
7,485

 
18,552

Total
$
9,261

 
$
16,722

 
$
117,433

 
$
456,493

 
$
599,909

We expect to spend between $90 million and $110 million on capital expenditures during 2017.
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. Illiquid credit markets, 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

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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.
•
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 as a gain 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, 2016, we had recorded asset retirement obligation liabilities of $191.4 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2016, we estimate that the aggregate undiscounted cost of final mine closures is approximately $515.6 million. 
Coal Reserves. There are numerous uncertainties inherent in estimating quantities of economically recoverable coal reserves, many of which are beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled by our internal engineers and geologists. Some of the factors and assumptions that impact economically recoverable reserve estimates include:
•
geological conditions;
•
historical production from the area compared with production from other producing areas;
•
the assumed effects of regulations and taxes by governmental agencies;
•
assumptions governing future prices;
•
current mine plans; and
•
future operating costs.
Each of these factors may vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and these variances may be material. Variances could affect our projected future revenues and expenditures, as well as the valuation of coal reserves. At December 31, 2016, we had 1.3 billion tons of proven and probable coal reserves, of which 0.7 billion tons were assigned to our active operations and 0.6 billion tons were unassigned.

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Workers’ Compensation. Individuals who sustain personal injuries due to job-related accidents may be compensated for their disabilities, medical costs, and on some occasions, for the costs of their rehabilitation, and the survivors of workers who suffer fatal injuries may receive compensation for lost financial support. The workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee who is injured in the course of employment. Our obligations are partially covered through high-deductible third-party insurance policies. We accrue for any liability by recognizing costs when it is probable that a covered liability has been incurred and the cost can be reasonably estimated. Our estimates of these costs are adjusted based upon actuarial studies. Actual losses may differ from these estimates, which could increase or decrease our costs. At December 31, 2016, we had workers’ compensation obligations of $21.5 million primarily related to obligations assumed in the Acquisition.
Coal Workers’ Pneumoconiosis. We are required by federal and state statutes to provide benefits to employees for awards related to coal workers’ pneumoconiosis disease (black lung). Our subsidiaries are insured for black lung obligations by a third-party insurance provider using high-deductible plans. Provisions are made for estimated benefits based on annual evaluations prepared by independent actuaries. As of December 31, 2016, we had estimated black lung obligations of approximately $13.5 million. 
Life Insurance Benefits. As part of the Alpha Restructuring and the Retiree Committee Agreement, we 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. As of December 31, 2016, we had estimated life insurance benefit obligations of approximately $12.6 million. 
Warrant Derivative Liability. We 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. The warrants are fair-valued using a Black-Scholes pricing model and marked to market at each reporting period with changes in value reflected in earnings. As of December 31, 2016, we had warrant derivative liability of approximately $35.1 million. 
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. Due to our formation through the acquisition of the core coal assets of Alpha as part of the Alpha Restructuring, a lack of history of operating results, and ownership change limitations applicable to net operating loss and other carryforwards, a full valuation allowance is currently recorded against the net deferred tax assets of ours.
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.

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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.
Acquisition-Related Obligations. We entered into various settlement agreements with Alpha and/or the Alpha bankruptcy successor ANR and third parties as part of the Alpha Restructuring. We assumed acquisition-related obligations through those settlement agreements which became effective on July 26, 2016, the effective date of Alpha’s plan of reorganization. These acquisition-related obligations include financial instruments which are fair valued on a recurring basis. Observable transactions are not available to aid in determining the fair value. Therefore, the fair value is 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. See Note 11 and Note 14 in the audited financial statements included elsewhere in this prospectus for disclosures related to acquisition-related obligations.
New Accounting Pronouncements. See Note 2 in the audited financial statements included elsewhere in this prospectus for disclosures related to new accounting policies adopted.

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THE COAL INDUSTRY
Coal is an abundant and inexpensive natural resource, making it a leading source for the world’s energy consumption and steel production needs. According to the BP Statistical Review, total global proven coal reserves were 983 billion tons at the end of 2015, and coal provided 29% of the world’s primary energy consumption. Coal is generally categorized into met and steam coal. Met coal is used to create coke for use in the steel-making process. Steam coal is primarily used by utilities and power producers to generate electricity. Per Wood Mackenzie, 74% of the world’s steel production in 2016 was estimated to be manufactured using methods that consume met coal. Coal has historically been a relatively inexpensive fuel for power generation and remains a major fuel for global energy.
conturaindustrygraph1.jpg
Source: BP Statistical Review, June 2016.
U.S. coal assets are critical for global energy and steel production needs. The U.S. has the largest proven reserve base of coal in the world with approximately 262 billion tons of proven reserves or approximately 25% of global coal reserves, according to the BP Statistical Review. In 2017, the U.S. is expected to account for 14% of the world’s coal supply and 12% of global coal consumption, according to Wood Mackenzie.
The geological characteristics of coal reserves largely determine the mining method used to extract coal. There are two primary methods of mining coal: underground and surface mining. In 2015, underground mining accounted for approximately 35% of total U.S. coal production, while surface mining accounted for the remaining 65% of U.S. production according to the EIA Annual Coal Report.
Underground mining methods are used when coal is located deep beneath the surface. Underground mining employs one of the following two methods: longwall mining or continuous (or room and pillar) mining. Longwall mining is a highly automated method using a mechanical shearer to extract coal from long rectangular blocks of medium to thick seams. Continuous miners are utilized to develop access to blocks of coal. A rotating drum mechanically advances, cuts coal from the face, and a conveyor belt transports coal to the preparation plant.

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Longwall mining accounted for approximately 60% of underground coal production in 2015, according to the EIA Annual Coal Report.
The other type of underground mining is continuous mining. In this method, rooms are cut into the coal seam leaving a series of coal pillars that help support the mine roof and control airflow. Continuous mining equipment is used to cut coal from the face, and shuttle cars are generally used to transport coal to a conveyor belt for subsequent delivery to the surface. Continuous mining accounted for approximately 40% of underground mining production in 2015, according to the EIA Annual Coal Report.
Surface mining accounts for the majority of U.S. coal production. This mining method is used when coal is found relatively close to the surface or when multiple seams are in close vertical proximity. Some methods of surface mining include area, contour, auger and highwall mining. Surface mining involves removing overburden (rock and overlying soil) with heavy, earth moving equipment and explosives to expose the coal seam(s). Next, coal is excavated and transported out of the pit to a preparation plant or loadout. After the coal is extracted and shipped, reclamation of disturbed areas occurs as part of normal mining activities. After a mine is depleted, overburden removed at the beginning of the mining process is used to backfill the remaining pits, vegetation is reestablished and the site is returned to its pre-mining state.
Some coal products are extracted and transported to preparation plants where they are washed to remove impurities, such as rock and shale. Preparation plants process coal to ensure quality specifications for end users. Additionally, some coal products are crushed and shipped directly to end users. Shipments are made via major railroads, trucks, barges and seaborne vessels or a combination thereof. The U.S. has ample port capacity along the East and Gulf Coasts.
Metallurgical Coal Industry Overview
Met coal is a critical input in the integrated steel making process. The coal is converted into coke, which is used as a fuel and reducing agent in blast furnaces to convert iron ore into liquid iron and afterwards into steel. High quality met coal is a scarce commodity, with large scale reserves found primarily in the eastern U.S., western Canada, eastern Australia, Russia and China. Met coal is consumed domestically and sold into the seaborne market. According to Wood Mackenzie, in 2017, approximately 313 million tons are expected to be shipped in the seaborne market, while the total global met coal production is expected to be 1,191 million tons.
Met coal is characterized and sold in the Pacific Basin as HCC, semi-soft coking coal (“SSCC”) and pulverized coal injection (“PCI”), with HCC typically being the most valuable. In the Atlantic Basin, met coal is sold according to its volatile matter (“Vol.”) specification as Low-Vol., Mid-Vol., High-Vol. A and High-Vol. B, with Low-Vol. typically being the most valuable. Steel producers procure a mix of coals based on the quality requirements of each blast furnace.
Historically, the majority of met coal sold in the seaborne market has been priced based on a quarterly benchmark. Typically, the benchmark price is set between major Australian suppliers and major Japanese steel producers. In Q1 2016, the HCC benchmark price reached the unsustainably low level of $81 per metric ton, and producers globally were forced to rationalize production. By Q4 2016, however, the trend reversed and the HCC benchmark rose substantially to $200 / metric ton. Price increases continued into Q1 2017 when the HCC benchmark settled at $285 / metric ton, more than 250% higher than the benchmark set in Q1 2016.

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conturaindustrygraph2.jpg
Source: Bloomberg. Pricing data as of March 31, 2017.
Metallurgical Coal Demand Fundamentals
Coke and iron production are the primary demand drivers for met coal. In the integrated steel making process, iron ore must be converted, or ‘reduced’ using the carbon in met coal. Basic oxygen / blast furnace is the most common method to produce steel. According to Wood Mackenzie, global steel production is expected to be 1.8 billion tons in 2017 which will require approximately 1.4 billion tons of met coal to produce. Import met coal demand is forecast to be stable in the near-term and is expected to increase modestly annually from 2016 to 2018. Import met coal demand growth is led by India, Brazil, Germany and Turkey, which are expected to have a weighted average 2016 to 2020 CAGR of approximately 2.7%, according to Wood Mackenzie.
The following tables show historical and forecast production levels by region of (i) total crude steel production and (ii) crude steel production using the basic oxygen / blast furnace process.
Global Crude Steel Production Landscape
conturaindustrytable1crudest.jpg
Source: Wood Mackenzie Global Steel Markets tool, April 2017.
Crude steel is produced with three primary methodologies: basic oxygen and blast furnace, electric arc furnace and open hearth furnace. Met coal is used in basic oxygen and blast furnace production which is the primary method and is estimated to be utilized in 74% of 2017 total crude steel production, according to Wood Mackenzie.

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Global Basic Oxygen / Blast Furnace Steel Production Landscape
conturaindustrytable2boblast.jpg
Source: Wood Mackenzie Global Steel Markets tool, April 2017.
The Chinese and Japanese economies have matured greatly over the past few decades but are expected to remain robust net importers of met coal. Chinese steel production and coking coal demand are expected to gradually decline as the country shifts more toward a service based economy. Reduction in Japanese steel production and met coal demand is driven by automakers continuing to delocalize their manufacturing to overseas plants and Japanese steel exports being displaced by increasing exports from China, India and Russia. These declines are expected to be largely offset by the industrialization and urbanization of India, which is expected to drive long-term growth of met coal demand.
India is expected to be one of the primary drivers of demand for seaborne met coal into the foreseeable future. As a result of India’s large, expanding population, increasing urbanization and its burgeoning middle class, steel production in India is expected to grow substantially. Tata Steel recently received approval to increase the capacity of its Hooghly coke plant, which is designed to process 100% imported coal. This move is part of a larger trend of Indian steel producers expanding their global footprints. In addition, the Prime Minister of India announced a “Buy Indian” policy to support domestic manufacturing, which should accelerate demand for steel and met coal imports. According to Wood Mackenzie, India is expected to import 56 million tons of met coal in 2017 and imports are expected to grow at a CAGR of 3.4% from 2016 through 2020.
Brazil, Germany and Turkey are other markets expected to drive met coal import demand growth going forward. Auto production increases are expected to drive increased steel production in Germany, while general economic growth in Turkey and Brazil will drive steel production in those countries. In Germany, the majority of coking coal mines have been closed over the past decade in tandem with an increase in exports of steel-rich luxury cars which has resulted in a rise in met coal imports. In Turkey, the increase in domestic met coal supply is not expected to keep pace with the estimated increase in infrastructure steel demand resulting in higher met imports in the near term. Brazil’s economic recovery is expected to drive additional need for steel going forward. The expected weighted annual growth rate of import met coal demand for these countries is 1.8% from 2016 to 2020, per Wood Mackenzie.

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Global Seaborne Metallurgical Coal Import Landscape
 
 
 
Historical
 
 
 
Projected
 
% of
11-‘16
16-‘20
16-‘35
Mst
2011
2012
2013
2014
2015
2016
2017E
2020E
2025E
2035E
2017 Total
CAGR
CAGR
CAGR
Japan
67

67

69

65

63

62

62

59

53

50

19.8
%
(1.4
)%
(1.3
)%
(1.1
)%
India
36

40

40

45

50

54

56

61

70

119

18.1

8.3

3.4

4.3

China
34

53

85

68

50

50

48

41

40

42

15.2

7.9

(4.9
)
(1.0
)
South Korea
35

35

34

39

42

39

38

39

38

36

12.3

2.0

(0.7
)
(0.3
)
Brazil
19

17

16

17

19

19

19

19

20

23

6.0

(0.3
)
0.9

1.2

Germany
14

14

15

17

18

18

18

19

19

20

5.8

5.0

1.5

0.7

Turkey
5

6

7

7

8

8

8

9

10

10

2.6

8.2

4.6

1.2

ROW
60

53

56

59

60

59

63

76

78

90

20.1

(0.1
)
6.3

2.2

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
270

285

321

316

309

308

312

322

327

391

—

2.7
 %
1.1
 %
1.3
 %
Source: Wood Mackenzie Global Coal Markets tool, February 2017.
Metallurgical Coal Supply Fundamentals
The four countries that supply the majority of met coal for the seaborne market are Australia, the U.S., Canada and Russia. These countries exported 295 million tons, which represented 96% of total 2016 seaborne exports, according to Wood Mackenzie. Supply from major met coal producing countries has fluctuated significantly over the past several years. From 2008 to 2013, the met market became oversupplied as prices increased and numerous new mines came online. These pricing increases were largely due to 2008 and 2011 supply disruptions in Australia, which has historically been the largest exporter of met coal globally. From 2013 to 2016, total export supply decreased significantly as prices declined and high cost volume came offline. Given reduced investments by coal producers in recent years to develop new mines, we believe there are limited opportunities for near-term term supply growth globally.
Global Seaborne Metallurgical Coal Export Landscape
 
 
 
Historical
 
 
 
Projected
 
% of
11-‘16
16-‘20
16-‘35
Mst
2011
2012
2013
2014
2015
2016
2017E
2020E
2025E
2035E
2017 Total
CAGR
CAGR
CAGR
Australia
148

160

186

203

203

204

203

199

192

235

64.8
%
6.6
 %
(0.7
)%
0.8
 %
United States
65

65

66

48

40

36

39

30

30

33

12.4

(11.3
)
(4.3
)
(0.4
)
Russia
12

15

22

24

26

27

30

35

39

29

9.5

17.5

6.7

0.3

Canada
29

33

38

33

30

28

28

28

29

33

8.9

(1.0
)
0.4

0.9

Mozambique
1

5

5

5

5

6

6

13

13

15

1.9

51.4

24.4

5.4

ROW
23

20

16

11

9

8

8

16

22

39

2.5

(19.8
)
20.4

9.0

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
278

298

333

324

312

308

313

321

326

384

—

2.1
 %
1.1
 %
1.2
 %
Source: Wood Mackenzie Global Coal Markets tool, February 2017.
Australia is the world’s largest exporter of met coal. According to Wood Mackenzie, Australia is expected to represent 65% of total global exports in 2017. In March / April 2017, Australian coal mines were forced to halt operations due to heavy rains from Cyclone Debbie. This weather event resulted in significant supply disruptions, which were exacerbated by ongoing rail related issues. Australia’s met export growth has been supported by the decline in the Australian Dollar; the Australian Dollar to U.S. Dollar exchange rate decreased from 0.892 as of December 31, 2013 to 0.749 as of April 30, 2017 according to Bloomberg, making production more profitable. Going forward, Australian production is expected to decline over the next two decades as few new projects are in development and existing mines will be faced with reserve degradation and mine site infrastructure constraints.
The U.S. is currently the second largest exporter of met coal and is expected to account for 12% or 39 million tons of the seaborne export market in 2017 according to Wood Mackenzie. While the pricing environment has

94



improved, U.S. producers are faced with capital constraints and permanently closed mines limiting producers’ ability to bring incremental tons to the market.
Canadian producers have experienced significant seaborne export declines since 2013. According to Wood Mackenzie, Canadian exports have decreased 27% from 2013 to 2016. The continued strength of the U.S. dollar contributes to Canadian mine profitability. The Canadian Dollar to U.S. Dollar exchange rate decreased from 0.941 as of December 31, 2013 to 0.733 as of April 30, 2017 according to Bloomberg. From 2016 to 2020, the Canadian export forecast is projected to remain roughly flat, according to Wood Mackenzie.
Russia is one of the few regions that has shown noticeable met coal supply growth in recent years. Russia’s growth has primarily been due to its proximity to the growing Asia market and the sharp decline in the Ruble that has made production more profitable. The Russian Ruble to U.S. Dollar exchange rate decreased from 0.030 as of December 31, 2013 to 0.018 as of April 30, 2017 according to Bloomberg. Russia is expected to account for 9% of seaborne met exports in 2017 and is expected to see annual compound growth of approximately 6.7% between 2016 and 2020 according to Wood Mackenzie.
Steam Coal Industry Overview
Steam coal remains the global fuel of choice for power generation due to its abundance and cost effectiveness. In 2016, global supply of steam coal exceeded 6.0 billion tons according to Wood Mackenzie, and provided 27% of global energy consumption in 2016 according to the EIA. Through 2030, coal-fired power generation is expected to be the second-largest energy source worldwide, behind liquid petroleum, according to the EIA. Steam coal producers compete primarily with natural gas and increasingly with renewable forms of energy around the world. Since 2005, according to the EIA, the cost of using coal to generate electricity has been approximately 50% cheaper on a dollar per million BTU basis than natural gas.
Despite increasing competition from other forms of energy, steam coal is expected to continue playing a significant role in satisfying growing global energy needs, primarily in base-load power generation. The largest consumers of coal in the U.S. are utilities. According to Wood Mackenzie, estimated domestic steam coal consumption is approximately 796 million tons in 2017. While much of the coal produced in the U.S. is consumed domestically, multiple ports in the U.S. provide coal producers with access to the export markets.
The largest steam coal producers globally are China, India, Indonesia, Australia and the U.S., according to Wood Mackenzie. As in the U.S., the majority of Chinese steam coal production is consumed domestically. Conversely, Indonesia and Australia are net exporters and account for approximately 60% of the global seaborne steam coal supply. According to Wood Mackenzie, these producers are likely to retain their positions as leading exporters of steam coal driven by South and South East Asian demand growth beginning in the mid-2020s. U.S. steam coal consumption has decreased in recent years primarily due to low natural gas prices and environmental regulations. Natural gas price volatility is one of the leading drivers of domestic steam coal demand. Going forward, natural gas prices are expected to rise to more normalized levels due to the decrease in natural gas storage levels to at or below five-year averages and slow recovery from previous production curtailments. In addition to the strengthening pricing of natural gas, the regulatory environment is improving as regulations are in the process of being revised or already rescinded by the current administration. Certain regulation have been already targeted by the current administration, such as the Clean Power Plan (“CPP”) and Mercury and Air Toxics Standards (“MATS”), which are currently under review, and the moratorium on granting additional coal federal land leases and the Stream Protection Rule, which has been eliminated, although this elimination is subject to legal challenges.
U.S. Steam Coal Demand Fundamentals
Steam coal is a key source for U.S. electrical and industrial needs primarily due to its low cost and reliability relative to other of forms of energy. According to the EIA, over the last decade steam coal has been approximately 50% cheaper than natural gas alternatives. In its 2017 Annual Energy Outlook, the EIA estimated that coal made up approximately 34% of total U.S. electricity generation in 2016, and is expected to increase to 36% in 2025. This

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compares to natural gas’ share of 28% of total U.S. electricity generation in 2016, decreasing to 22% in 2025. The power generation infrastructure in the U.S. continues to be highly reliant on coal-fired generation.
Domestic steam coal consumption is expected to increase over the next decade primarily due to increasing demand from utilities. Despite the retirement of coal-fired generation capacity and increased competition from other fuels, the EIA forecasts that the U.S. coal industry will retain its position as the predominant supplier of fuel to the domestic utility market. According to the EIA’s Annual Energy Outlook, coal’s share of domestic electrical power generation is expected to average 35% excluding the CPP, and 34% with the CPP in effect, from 2016 to 2025. In an extended forecast from 2016 to 2050, the EIA projects coal’s share of U.S. electrical power will average 34% without the CPP and 28% if the CPP were in effect.
conturaindustrygraph3.jpg
Source: EIA International Energy Outlook 2017.
Natural gas pricing volatility continues but steam coal remains the low-cost option. Henry Hub natural gas prices decreased from a high of $7.92 per million BTU in 2014 to a low of $1.49 per million BTU in March 2016. The volatility in pricing continued as prices increased to $3.76 per million BTU in December 2016 before stabilizing at around $3.00 per million BTU in March 2017.

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conturaindustrygraph4.jpg
Source: Bloomberg, pricing as of April 30, 2017.
Note: NAPP coal is based on 13,000 BTU/lb 3.00% Sulfur Pittsburgh Seam coal (prompt quarter). PRB Coal is based on 8,400 BTU/lb 0.80% Sulfur Wyoming coal (prompt quarter).
In its Short-Term Energy Outlook for 2017, the EIA projected the average cost of coal delivered to electric generating plants to be $2.17 on a dollars per MMBTU basis versus $3.55 for natural gas making the estimated price of natural gas substantially more than the price of coal for 2017.
Average Cost of United States Electricity Generation by Fossil Fuel
($ / mm BTU)
2012A
2013A
2014A
2015A
2016A
2017E
2018E
Coal
$
2.38

$
2.34

$
2.36

$
2.23

$
2.11

$
2.17

$
2.21

Natural Gas
3.42

4.33

4.98

3.23

2.88

3.55

4.00

Residual Fuel Oil
21.05

19.32

19.19

10.36

8.41

10.42

10.76

Distillate Fuel Oil
23.51

23.05

22.32

14.47

10.86

13.41

14.62

Source: EIA Short-Term Energy Outlook, March 2017.
Note: Represents steam coal delivered to electric generating plants.
In recent years, U.S. steam coal demand has faced significant headwinds, largely driven by proposed and enacted government regulations, notably, MATS and CPP. According to the American Coalition for Clean Coal Electricity, these new regulations (MATS, in particular) have already contributed to the retirement of approximately 400 coal-fired electricity generating units and the loss of over 60,000 megawatts of electric generating capacity. Moreover, it is expected that these new rules and regulations will force the closure of approximately 451 additional existing coal-fired units with approximately 75,400 megawatts of electric generating capacity
MATS, as issued by the U.S. EPA, establishes emissions limits for toxic air pollutants associated with coal combustion such as mercury and heavy metals. The regulation requires all coal generators that sell power and have a capacity greater than 25 megawatts to comply with specific emissions limits by April 2015. The EIA reports that as of April 2016, 276 GW or 92% of 2014 coal-fired power capacity, is MATS compliant and should not be at risk for further retirements as tighter regulation standards are unlikely for the near term. In addition, EPA indicated in an April 2017 court filing that it may reconsider the finding on which the MATS rule is based.
CPP, which was finalized during the Obama Administration, would have resulted in a substantial decline in the utilization of coal over the next 20 years. The CPP established the first-ever national standards regarding carbon emissions from power plants. However in March 2017, President Trump signed the Executive Order for Promoting Energy Independence and Economic Growth, which aims to reduce regulatory restrictions intended to curb the

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production and use of fossil fuels. An important part of this Executive Order directs the EPA to commence regulatory proceedings to rescind or revise the CPP. The CPP had already been temporarily stayed by the U.S. Supreme Court pending judicial review. The potential repeal or revision of the CPP and MATS and other potential actions from the current Administration should ease the pressure on coal-fired utilities to retire units prematurely, arguably increasing the life of the current domestic coal fleet.
U.S. Steam Coal Supply Fundamentals
The U.S. supplied 778 million tons or 13% of the global steam market in 2016 according to Wood Mackenzie. Domestic US coal production is primarily attributed to four coal producing basins: PRB, NAPP, ILB and CAPP. The type, quality and characteristics of coal vary within each basin. Going forward, U.S. coal supply outlook is expected to be primarily influenced by natural gas prices and the domestic regulatory environment.
The PRB is located in Wyoming and Montana. The PRB produces sub-bituminous coal with sulfur content typically ranging from 0.2% to 0.6% and heat content typically ranges from 8,000 to 9,500 BTU/lb. According to Wood Mackenzie, estimated coal production in the PRB was 309 million tons in 2016. The PRB produces the largest volume of steam coal among the four major U.S. coal basins largely because it is the basin most competitive with natural gas prices and is optimally located near coal-powered plants. The basin is expected to have positive long-term supply growth and will supply 44% of domestic steam coal in 2017, according to Wood Mackenzie. PRB coal is primarily shipped to customers via two major railroads and has access to West Coast export terminals in the U.S. and Canada.
The NAPP basin is located in Ohio, Pennsylvania, Maryland and northern West Virginia. The area includes reserves of bituminous coal with heat content generally ranging from 11,500 to 14,000 BTU/lb and sulfur content typically ranging from 1.0% to 5.0%. Steam coal produced in Northern Appalachia is marketed primarily to electric utilities, industrial customers and the export market. NAPP production levels are expected to stay relatively flat through 2018 around 100 million tons. NAPP coal is the most transportation advantaged in the U.S. with the ability to ship to customers via truck, river barge, or railroads with access to East Coast U.S. export terminals.
The ILB is located in western Kentucky, Illinois and Indiana. The area includes reserves of bituminous coal with a heat content typically ranging from 8,500 to 12,800 BTU/lb and sulfur content ranging from 1.0% to 5.0%. Most of the coal produced in the Illinois Basin is used to produce electricity, with small amounts used in industrial applications. Compared to the Northern Appalachian basin, the Illinois Basin has a lower heat content, higher chlorine content and higher transportation costs. According to Wood Mackenzie, estimated coal production in the Illinois Basin is expected to be 99 million tons in 2017. ILB coal predominantly utilizes river barges to deliver coal to customers, while also utilizing railroads for selected deliveries. ILB coal has access to Gulf Coast U.S. export terminals.
The CAPP basin is located in eastern Kentucky, southern West Virginia, Virginia and northern Tennessee. The area includes reserves of bituminous coal with a heat content typically ranging from 11,500 to 14,200 BTU/lb and sulfur content typically ranging from 0.5% to 3.0%. Steam coal produced in Central Appalachia is marketed primarily to electric utilities, industrial customers and the export market. CAPP produces a limited share of U.S. domestic steam coal primarily as a by-product of met coal production. According to Wood Mackenzie, estimated coal production in CAPP is expected to be 47 million tons in 2017. CAPP coal is transported to customers via railroads, river barges, and trucks with access to both East Coast and Gulf Coast U.S. export terminals.
As a power generation alternative to coal, Henry Hub natural gas pricing is a key reference point for the steam coal outlook. In response to increases in natural gas prices, domestic steam coal supply is expected to experience near-term growth following years of rationalization. In its April Short-Term Energy Outlook for 2017, the EIA projected the average cost of coal delivered to electric generating plants to be $2.17 on a dollars per MMBTU basis versus $3.55 for natural gas making the estimated price of natural gas substantially more than the price of coal for 2017. This pricing differential is expected to drive supply growth from the remaining steam coal producers.

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The regulatory environment is an important factor influencing supply fundamentals in steam coal industry. Recent regulation changes expected to provide relief to U.S. coal producers include the repeal of the Stream Protection Rule, and the elimination of a moratorium on new coal leases on Federal lands. The current administration repealed the Stream Protection Rule, which was a set of regulations enacted by the previous administration that would have positioned approximately 60% of existing coal reserves as uneconomic to produce. Additionally, the repeal of the coal moratorium once again allows new leases for coal on federal lands, adding potential new capacity back to the domestic coal market.
Coal Characteristics
In general, coal of all geological compositions is characterized by end use as either steam coal or met coal. Heat value, sulfur and ash content, and in the case of met coal, volatility, are the most important variables in the profitable marketing and transportation of coal. These characteristics determine the best end use for a particular type of coal.
Heat Value. The heat value of coal is commonly measured in British thermal units, or “BTUs.” One BTU is the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. Bituminous coal is located primarily in the Midwest, Appalachia, Arizona, Colorado and Utah and is the type most commonly used for electric power generation in the United States. Sub-bituminous coal is used for industrial steam purposes, while bituminous coal, depending on its quality, can be used for both met and industrial steam purposes.
Sulfur Content. Sulfur content can vary from seam to seam and sometimes within each seam. When coal is burned, it produces sulfur dioxide, the amount of which varies depending on the chemical composition and the concentration of sulfur in the coal. Low sulfur steam coals have a sulfur content of 1.5% or less, and low sulfur met coals have a sulfur content of 1.0% or less.
High sulfur coal can be burned in plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by 50% to 99%. Plants without scrubbers can burn high sulfur coal by blending it with lower sulfur coal or by purchasing emission allowances on the open market, allowing the user to emit a predetermined amount of sulfur dioxide. Some older coal-fired plants have been retrofitted with scrubbers, although most have shifted to lower sulfur coals as their principal strategy for complying with Phase II of the Clean Air Act’s Acid Rain regulations. We expect that any new coal-fired generation plants built in the United States will use clean coal-burning technology and will include scrubbers.
Ash & Moisture Content. Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from seam to seam. Ash content is an important characteristic of coal because electric generating plants must handle and dispose of ash following combustion. The absence of ash is also important to the process by which met coal is transformed into coke for use in steel production. Moisture content of coal varies by the type of coal, the region where it is mined and the location of coal within a seam. In general, high moisture content decreases the heat value and increases the weight of the coal, thereby reducing its value and making it more expensive to transport. Moisture content in coal, as sold, can range from approximately 5% to 30% of the coal’s weight.
Coking Characteristics. The coking characteristics of met coal are typically measured by the coal’s fluidity, ARNU results and volatility. Fluidity and ARNU tests measure the expansion and contraction of coal when it is heated under laboratory conditions to determine the strength of the coke that could be produced from a given coal. Typically, higher numbers on these tests indicate higher coke strength. 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, all other met characteristics being equal. Coal with a lower volatility produces a higher coke yield and is more highly valued than coal with a higher volatility.

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BUSINESS
Our Company
We are a large-scale, diversified provider of met and steam coal to a global customer base. We operate high-quality, cost-competitive coal mines across three major U.S. coal basins complemented by a robust Trading and Logistics business. Our portfolio of mining operations consists of six mining complexes, comprised of nine underground mines, four surface mines and four coal preparation plants. In 2016, we sold 4.0 million tons of met coal from mines in CAPP and NAPP and 41.1 million tons of steam coal from mines in CAPP, NAPP and the PRB. To supplement our mining operations, we operate a Trading and Logistics business that focuses on the sale of third-party coal into the international market. From the acquisition of our assets on July 26, 2016, through December 31, 2016, our Trading and Logistics business sold 1.5 million tons of met coal. A strategic cornerstone of this business is our 65.0% interest in DTA, a coal export terminal. 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.
Our assets create a strong, diversified operational footprint and have the ability to generate cash flows across many different pricing environments. Our met coal business, together with our Trading and Logistics business, is expected to sell 7.7 million tons of coal in 2017. In addition to our operating met coal mines, we have three potential development projects that are primarily focused on met coal and provide opportunities for incremental production growth. Our steam portfolio is anchored by our Cumberland mine, which is expected to be in the first quartile of the 2018 NAPP coal basin “Operating Margin” curve for U.S. producers, according to Wood Mackenzie. A substantial portion of our steam coal, including from our PRB operations, is sold under long-term contracts (typically ranging from one year to five years), providing us with significant sales visibility.
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 CAPP coal basin, we predominantly produce low-ash and low-sulfur met coal, including High-Vol. A, High-Vol. B, Mid-Vol. and specialty coals, which are shipped to domestic and international steel producers. In the NAPP coal basin, we produce high-BTU steam coal, as well as some High-Vol. B met coal. In the PRB coal basin, we produce low-sulfur steam coal from large surface mining operations. Our steam coal is primarily sold to the domestic power generation industry.
We have a substantial reserve base of over 1.0 billion tons of proven reserves and approximately 310 million tons of probable reserves, which results in an average remaining mine life of approximately 30 years based on our 2016 production levels. Our reserve base in CAPP consists of 71 million tons of proven and 22 million tons of probable reserves across the three mining complexes, of which substantially all is met coal. Our reserve base in NAPP consists of 326 million tons of proven and 279 million tons of probable reserves, of which approximately 7% is met coal, with substantially all of the remaining reserves principally characterized as high-BTU, Pittsburgh 8 seam steam coal. In the PRB, we have 614 million tons of proven and 10 million tons of probable low-sulfur steam coal reserves.



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Our Operations
The following table presents a summary of our mining complexes:
Complex
 
Location
 
Type
 
Coal Qualities
 
Logistics
Nicholas
 
CAPP (WV)
 
Underground
 
Met High-Vol. B and specialty
 
Norfolk Southern
Toms Creek
 
CAPP (VA)
 
Underground / Surface
 
Met High-Vol. A and B
 
Norfolk Southern
McClure
 
CAPP (VA)
 
Underground
 
Met Mid-Vol. and High-Vol. A
 
CSX
Cumberland
 
NAPP (PA)
 
Underground
 
Steam / Met High-Vol. B
 
CSX, Norfolk Southern, Monogahela River
Belle Ayr
 
PRB (WY)
 
Surface
 
Steam
 
BNSF, UP
Eagle Butte
 
PRB (WY)
 
Surface
 
Steam
 
BNSF, UP
CAPP
Our CAPP operations consist of three cost-competitive, high-quality met coal mining complexes: Toms Creek, McClure and Nicholas. According to Wood Mackenzie, in 2018, our met coal platform is expected to be positioned in the second quartile among domestic met producers based on “Operating Margin” as defined by Wood Mackenzie. From the acquisition of our assets on July 26, 2016 until December 31, 2016, our CAPP met coal quality was composed of 43.6% Mid-Vol., 39.7% High-Vol. A and 16.7% High-Vol. B. During this time period, we shipped approximately two-thirds of our met coal production from our CAPP operations internationally to customers in Europe, Asia and the Americas, with the remaining met production sold into the domestic market.

cappmapa01.jpg
NAPP
Our NAPP operations consist of the large-scale, high-margin and high-quality Cumberland coal mining complex. Cumberland is located in Greene County, Pennsylvania and operates one highly efficient longwall mine 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. According to Wood Mackenzie, Cumberland is expected to be in the first quartile for “Operating Margin” in 2018 among domestic steam coal producers in the NAPP coal basin. We are also able to sell part of our Cumberland coal production (0.4

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million tons in 2016) into the met coal market as High-Vol. B, achieving higher realized pricing than if sold as steam 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. As of April 21, 2017, 100% of our anticipated 2017 production in NAPP was committed and priced.


nappregionmapwba01.jpg
PRB
Our PRB operations consist of the Belle Ayr and Eagle Butte mines. Our production from these mines is sold primarily to a well-established 8,400 to 8,600 BTU-specific market. Historically, the 8,400 to 8,600 BTU market has consisted of base load power generation plants and demand has been stable. A total of 34 million tons of steam coal was shipped from these two mines in 2016, primarily to utilities located in the western, midwestern and southern United States. Belle Ayr produces extremely low-sulfur coal that receives a premium to 8,400 BTU coal prices due to its high heat and low-sulfur content. Eagle Butte is expected to be in the first quartile for “Total Cash Costs” in 2018 among producers in the PRB, according to Wood Mackenzie. Our PRB mines historically have entered into long-term contracts with customers, which provide us with significant sales visibility. As of April 21, 2017, 93% of our anticipated 2017 production in the PRB was committed and priced.

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prbregionmapwba01.jpg
Trading and Logistics
Our Trading and Logistics business purchases met coal from domestic producers and sells into international markets. A strategic cornerstone of our Trading and Logistics business is our interest in the DTA coal export terminal. We recently 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 terminal fees, overhead and profit when purchasing third-party coal. Additionally, we sell capacity to third-party operators via throughput contracts. The Trading and Logistics business provides access to international markets and further diversifies our revenue sources.
Our Competitive Strengths
We believe we are well-positioned to execute our business strategies because we possess the following competitive strengths:
Diversified provider with a broad footprint of large scale met and steam coal operations. Our operational footprint consists of thirteen coal mines and four preparation plants in three major coal basins in the U.S.: CAPP, NAPP and the PRB. We operate as a “three-pronged” business: (i) met coal platform primarily in CAPP, (ii) steam coal platform largely in NAPP and PRB and (iii) a Logistics and Trading platform that owns a 65.0% interest in the DTA coal export terminal. Our cost-competitive, high-quality met coal platform in CAPP has 94 million tons of proven and probable reserves as well as meaningful production growth opportunities. Our steam platform has 1,186 million tons of proven and probable coal reserves. In addition, we have also 44 million tons of proven and probable reserves of met coal in NAPP. The steam platform is anchored by our flagship Cumberland mine in NAPP and includes our cost-competitive PRB portfolio. Through our Trading and Logistics business, we sell various types of met coal, which allows us to meet the needs of our broad customer base of international steel producers. We benefit from strong customer relationships, and our operations have supplied many of our top customers continuously over the past decade.
A leading provider of met coal with high operating margins. We operate three high-quality, cost-competitive met coal complexes in Virginia and West Virginia – Toms Creek, McClure and Nicholas. Our high-quality met coal product is an important component within our customers’ overall coking coal requirements. Our complexes produce high-quality Mid-Vol., High-Vol. and specialty met coals known for low-ash and sulfur content. In 2017, we expect to sell 3.9 million tons of met coal from mines in CAPP, 0.3 million tons from mines in NAPP and supply 3.5

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million tons through our Trading and Logistics business. We believe our 2017 expected sales volume positions us to be the third largest provider of met coal in the United States. As of December 31, 2016, our CAPP operations had a significant reserve base composed of 71 million tons of proven and 22 million tons of probable reserves of met coal. Our consolidated met portfolio is estimated to hold a second quartile position based on 2018 “Operating Margin,” as defined by Wood Mackenzie, among U.S. met producers. The quality of our met coal, coupled with the cost-competitive position of these assets, allows us to maximize operating margins throughout different met coal price environments.
Highly efficient steam coal operations with strong contract visibility. Our steam coal operations are anchored by our flagship Cumberland mine in NAPP and include our cost-competitive mines in the PRB. Our mines produce steam coal that is highly sought after by domestic utilities. In NAPP, we produce Pittsburgh 8 seam steam coal, a well-known product to utilities in several different markets. Our Cumberland mine is estimated to hold a first quartile “Operating Margin” position in 2018 among domestic NAPP steam producers, according to Wood Mackenzie. Our Belle Ayr and Eagle Butte mines in Wyoming are highly efficient surface mine operations that benefit from mining 75 foot and 100 foot seams, respectively. Belle Ayr-produced coal typically receives a premium to 8,400 BTU PRB coal prices due to its high-heat and low-sulfur content. Coal mined at our PRB mines can be sold 100% raw with no washing necessary. In 2017, we expect to sell 31.5 million tons of steam coal in the PRB, 7.9 million tons in NAPP and 0.1 million tons in CAPP. As of April 21, 2017, we had contracted favorable pricing of our PRB portfolio for nearly 30 million tons at $11.34 per ton. In addition, we have contracted 7.9 million tons from our NAPP portfolio at $42.40 per ton. We enter into long-term supply agreements, typically ranging from one to five years, to contract our steam coal production in advance, thereby reducing the risks associated with our steam coal portfolio in future years. As of April 21, 2017, 94% of our expected steam production is already committed and priced for 2017. The table below outlines our current committed and priced volumes from 2017 to 2020, showing the degree of visibility into our future sales of steam coal.
2017-2020 Steam Coal Committed and Priced Volume by Basin as of April 21, 2017
Segment (tons in millions)
2017
2018
2019
2020
NAPP
7.9
4.1
2.5
2.0
PRB
29.3
15.9
7.2
4.5
Flexible Trading and Logistics business enhances strategic positioning and provides global customer access. Our Trading and Logistics business enhances the variety of coal products available for us to service export customers in the Americas, Europe and Asia, while also providing us with strategic East Coast port access. Through our 65.0% ownership of DTA, we have approximately 14 million tons of export capacity and guaranteed low-cost port access for our coal. DTA is a key pillar of our strategy to cater to the export met coal market. This facility complements our met operations by blending captive and third-party coal to achieve a broader portfolio of coal qualities. We typically build in margin for terminal fees, overhead, and profit when purchasing third-party coal. Additionally, we sell capacity via throughput contracts to third-party operators. Our Trading and Logistics Operations provide access to international markets and further diversify our revenue sources.
Scalable platform for organic growth and strategically positioned to take advantage of value-added acquisition opportunities. We believe our strong financial characteristics and geographic positioning provide us with the ability to execute on a variety of strategic opportunities, both organic and inorganic. We have identified several organic met coal growth opportunities that can be developed in supportive pricing environments, including:
•
Jerry Fork extension in CAPP, which could provide an incremental 0.2-0.3 million tons per year of High-Vol. B met coal;
•
Deep Mine #42 in CAPP, which could provide an incremental 1.0-1.5 million tons per year of High-Vol. A and Mid-Vol. met coal; and

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•
Freeport mine in NAPP, which could provide an incremental 2.5-3.5 million tons per year of primarily High-Vol. B met coal, with some steam coal as byproduct.
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.
Well-capitalized balance sheet with minimal legacy liabilities to support execution of our business plan. Our balance sheet reflects minimal legacy liabilities or post-retirement benefit obligations and no pension obligations. In the first quarter of 2017, we took steps to strengthen our balance sheet by extending the maturity of our debt and lowering our overall borrowing costs. We entered into a $125.0 million asset-based revolving credit facility, which was undrawn at closing, and a new $400.0 million term loan to retire high-cost indebtedness and improve our capital structure. Our conservative balance sheet and low leverage allow us to operate our business effectively throughout the market cycle.
Proven and experienced management team with a primary focus on safety and environmental stewardship. Our management team has extensive knowledge of the coal mining industry as well as intimate operational knowledge of our assets. Our core management team brings over 17 years on average in the coal industry and over 9 years on average of experience managing and operating our assets. This management team has prioritized a focus on safe mining practices at its operations. Our safety process involves all employees in accident prevention and situational awareness and observation, changing behaviors and continuous improvement of mine safety conditions. We also believe that environmental stewardship is integral to safe, productive and cost-efficient mining operations. As a result, our mining operations have consistently earned recognition for outstanding safety and environmental performance, including numerous local, state and national awards.
Business Strategies
Our business objectives are to increase shareholder value and drive cash flow generation across various pricing environments by sustaining a cost-competitive, diversified operational asset portfolio. Our key strategies to achieve these objectives are described below:
Promote excellence in safety and environmental stewardship. We believe safety is the bedrock upon which our culture and success are built. By implementing a behavior-based safety process, every employee is empowered to engage in the elimination of at-risk behaviors in the workplace, and to be accountable not only for their own safety, but for the safety of those around them. We intend to operate safely and achieve environmental excellence. Minimizing workplace incidents and environmental violations improves our operating efficiency, which in turn improves our cost structure and financial performance.
Rigorously seek opportunities to expand domestic and international sales while maintaining relationships with long-standing customer base. Through our operations and reserves in three 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 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, Turkey and Brazil. Additionally, we remain focused on advancing our Trading and Logistics business to procure coal from additional sources to expand sales to potential international customers. Combined with our strong international customer relationships and logistics expertise, our recent acquisition of an incremental 24.4% capacity at DTA further enhances our ability to grow our Trading and Logistics business.
Opportunistically expand met coal production capacity depending on market dynamics. We carefully evaluate opportunities to expand productive capacity at our met mines depending on current and projected met coal market dynamics. Our ability to leverage existing infrastructure and the embedded growth potential at our mining complexes to expand adjacent facilities and production provides a platform for expansion as market conditions allow. We expect our conservatively levered balance sheet and strong cash flow generation to provide us the ability to execute on these opportunities.

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Continuously evaluate strategic opportunities to acquire complementary high-quality coal assets or enter strategic alliances. Our experienced management team continues to analyze acquisitions, joint ventures and other opportunities that would be accretive and synergistic to our existing asset portfolio. For example, given the geographic placement of our mines across three U.S. coal basins, we are strategically positioned to realize significant potential synergies from domestic acquisitions. We expect our strong financial position will help support execution of potential strategic acquisitions and alliances.
Remain committed to cost containment policies to ensure operations are as efficient and profitable as possible. We continue to leverage our strong base of experienced, well-trained employees through a culture of workforce engagement to drive cost savings and operational productivity. While our operations have achieved significant overall cash cost reductions since 2014, we see further opportunities to reduce costs across our business. We also are continuing to efficiently manage our business and actively demonstrate financial discipline by maintaining a lean cost structure, prudently managing capital allocation and maintaining our flexible logistics and transportation platform.
Our Coal Reserves
We prepared the estimates of reserves which were audited by MM&A, and MM&A reviewed our methodology, assumptions and reserve factors utilized in calculations. In the few instances where MM&A recommended revisions to reserve figures, MM&A worked with our team to modify reserve estimates.
We maintain an internal staff of engineers and geoscience professionals who work closely with our 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 our 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 our 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.
As of December 31, 2016, we had estimated reserves totaling 1.3 billion tons, of which 727.5 million tons, or 55%, 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

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when conditions warrant. The remaining 595.9 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.
Our reserve estimates are predicated on engineering, economic, and geological data assembled and analyzed by internal engineers, geologists and finance associates, as well as third-party consultants. We update our reserve estimates annually to reflect past coal production, new drilling information and other geological or mining data, and acquisitions or sales of coal properties.
The following table provides the location and coal reserves associated with each mine or potential mine as of December 31, 2016:
As of December 31, 2016
(in thousands of short tons)(1) 
 
 
 
 
 
 
 
 
Recoverable Reserves
 
Reserve Control
Location/Mine
 
Status of
Operation(2)
 
Coal Bed
 
Assigned/
Unassigned(3)
 
Reserves
 
Proven
 
Probable
 
Owned
 
Leased
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CAPP
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nicholas
 
Active
 
Various
 
12,053 / 1,199
 
13,252

 
8,256

 
4,996

 
2,409

 
10,843

Toms Creek
 
Active
 
Various
 
7,198 / 23,880
 
31,078

 
24,071

 
7,007

 
—

 
31,078

McClure
 
Active
 
Various
 
45,861 / 3,349
 
49,210

 
39,111

 
10,099

 
—

 
49,210

 
 
 
 
 
 
 
 
93,540

 
71,438

 
22,102

 
2,409

 
91,131

NAPP
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumberland
 
Active
 
Pittsburgh 8
 
37,804 / 0
 
37,804

 
34,326

 
3,478

 
27,673

 
10,131

Greene Manor
 
Reserve
 
Pittsburgh 8
 
0 / 191,885
 
191,885

 
115,131

 
76,754

 
—

 
191,885

CNG
 
Reserve
 
Pittsburgh 8
 
0 / 202,264
 
202,264

 
68,770

 
133,494

 
202,264

 
—

Consol Trade Area
 
Reserve
 
Pittsburgh 8
 
0 / 34,256
 
34,256

 
14,387

 
19,869

 
—

 
34,256

CNG Sewickley
 
Reserve
 
Sewickley
 
0 / 65,524
 
65,524

 
37,349

 
28,175

 
65,524

 
—

Contura Freeport
 
Reserve
 
Freeport
 
0 / 73,633
 
73,633

 
55,961

 
17,672

 
—

 
73,633

 
 
 
 
 
 
 
 
605,366

 
325,924

 
279,442

 
295,461

 
309,905

PRB
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Belle Ayr
 
Active
 
Wyodak
 
294,227 / 0
 
294,227

 
285,400

 
8,827

 
14,960

 
279,267

Eagle Butte
 
Active
 
Roland/Smith
 
330,389 / 0
 
330,389

 
328,737

 
1,652

 
—

 
330,389

 
 
 
 
 
 
 
 
624,616

 
614,137

 
10,479

 
14,960

 
609,656

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
1,323,522

 
1,011,499

 
312,023

 
312,830

 
1,010,692

______________
(1)
1 short ton is equivalent to 0.907185 metric tons.
(2)
The “Status of Operation” for each mine is classified as follows:
Active — the mine is actively operating.
Reserve — mines where exploration has been conducted sufficient to define recoverable reserves, but the mine is not yet in development or production stage.
(3)
“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.


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The following table provides a summary of the quality of our reserves as of December 31, 2016:
As of December 31, 2016
(in thousands of short tons)(1) 
 
 
 
 
 
 
 
 
 
 
 
 
Average Btu
 
 
Location/Mine or Seam
 
Reserves
 
Primary Coal Type (2)
 
<1% Sulfur
 
1 - 1.5% Sulfur
 
>1.5% Sulfur
 
>12,500
 
<12,500
 
Date Acquired
CAPP
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nicholas / Jerry Fork / Eagle
 
4,656

 
HVM
 
4,656

 
 
 
 
 
4,656

 
 
 
07/26/16
Nicholas / Peerless
 
8,596

 
HVM
 
 
 
8,596

 
 
 
8,596

 
 
 
07/26/16
Toms Creek / (Multiple)
 
31,078

 
HVM
 
28,216

 
2,862

 
 
 
31,078

 
 
 
07/26/16
McClure / (Multiple)
 
49,210

 
MVM
 
49,210

 
 
 
 
 
49,210

 
 
 
07/26/16
NAPP
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumberland / Pittsburgh 8
 
37,804

 
S
 
 
 
 
 
37,804

 
37,804

 
 
 
07/26/16
Greene Manor/ Pittsburgh 8
 
191,885

 
S
 
 
 
 
 
191,885

 
191,885

 
 
 
07/26/16
CNG / Pittsburgh 8
 
202,264

 
S
 
 
 
 
 
202,264

 
202,264

 
 
 
07/26/16
Consol Trade Area / Pittsburgh 8
 
34,256

 
S
 
 
 
 
 
34,256

 
34,256

 
 
 
07/26/16
CNG Sewickley
 
65,524

 
S
 
 
 
 
 
65,524

 
65,524

 
 
 
07/26/16
Contura Freeport / Upper Freeport
 
73,633

 
HVM/S
 
73,633

 
 
 
 
 
73,633

 
 
 
07/26/16
PRB
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Belle Ayr / Wyodak
 
294,227

 
S
 
294,227

 
 
 
 
 
 
 
294,227

 
07/26/16
Eagle Butte / Roland/Smith
 
330,389

 
S
 
330,389

 
 
 
 
 
 
 
330,389

 
07/26/16
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
1,323,522

 
 
 
780,331

 
11,458

 
531,733

 
698,906

 
624,616

 
 
______________
(1)
1 short ton is equivalent to 0.907185 metric tons.
(2)
Coal Type: M=Metallurgical Coal; S=Steam; MVM=Mid-Vol. Metallurgical Coal; HVM=High-Vol. Metallurgical Coal.


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The following table provides a summary of information regarding our mining operations as of December 31, 2016:
 
 
 
 
 
 
 
 
Transportation
 
Preparation Plant
Location/Mine
 
Reserves
(thousands of short tons) (1)
 
Type (2)
 
Mining
Equipment (3)
 
Rail
 
Other (4)
 
Capacity
(short tons per hr)
 
Utilization
%
 
Source of
Power
CAPP
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nicholas / Jerry Fork
 
4,656

 
U
 
CM
 
NS
 
 
 
1,200

 
21

 
Mon Power
Toms Creek (Multiple)
 
31,078

 
U/S
 
CM/S/T/H
 
NS
 
 
 
800

 
30

 
Old Dominion
McClure (Multiple)
 
49,210

 
U
 
CM
 
CSX
 
 
 
1,000

 
76

 
MP2 Energy
NAPP
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumberland
 
37,804

 
U
 
LW
 
NS/CSX
 
B
 
1,600

 
86

 
WestPenn Power
PRB
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Belle Ayr
 
294,227

 
S
 
S/T
 
BNSF/UP
 
 
 
N/A(5)

 
N/A(5)

 
 
Eagle Butte
 
330,389

 
S
 
S/T
 
BNSF
 
 
 
N/A(5)

 
N/A(5)

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
747,364

 
 
 
 
 
 
 
 
 
 
 
 
 
 
______________
(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; T = Trucks; LW = Longwall; CM = Continuous Miner; H = Highwall Miner.
(4)
Transportation: B = Barge Loadout availability.
(5)
Loadout Only.

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.
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 and highwall mining. We do not use mountaintop removal mining.
Longwall Mining. At our Cumberland mine complex, 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, 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. 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.

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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, continuous haulage 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 thin seams. Ultimate seam recovery of in-place reserves is typically less than that achieved with longwall mining. All of this production is also washed in preparation plants 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 our PRB 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 haul trucks for transportation to a preparation plant or loadout area. Ultimate seam recovery of in-place reserves on average exceeds 90%. This surface-mined coal typically does not need to be cleaned in a preparation plant before sale. Productivity depends on overburden and coal thickness (strip ratio), equipment utilized and geologic factors.
Contour Mining. We use contour mining in areas where it is uneconomical to remove all the overburden from 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 mountain is created.
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 portal. The cut is typically a rectangular, horizontal opening in the highwall (the unexcavated face of exposed overburden and coal in a surface mine) 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.
Marketing, Sales and Customer Contracts
Our marketing and sales team, which is principally based in Bristol, Tennessee, consists of sales persons, distribution/traffic managers, contract administrators and administrative personnel. In addition to marketing coal produced at our operations, we also purchase and resell coal mined by others. We have coal supply commitments with a wide range of electric utilities, steel 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 our customers, we are able to serve a global customer base. This diversity allows us to adjust to changing market conditions. Many of our larger customers are well-established public utilities and steel manufacturers.
We sold a total of 46.7 million tons of coal in 2016, consisting of 45.0 million tons of captive coal, and 1.7 million tons of T&L coal. 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.

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The breakdown of tons sold for 2016 is set forth in the table below. All of our steam coal sales were captive volumes.
 
Steam Coal Sales
 
Metallurgical Coal Sales
 
(In millions, except percentages)
 
Tons
 
% of Coal
Sales Volume
 
% of Coal
Revenues
 
Tons
 
% of Coal
Sales Volume
 
% of Coal
Revenues
Year
Captive
 
Captive
 
T&L Coal
 
Captive
 
T&L Coal
 
Captive
 
T&L Coal
2016
41.1
 
88%
 
60%
 
4.0
 
1.7
 
8%
 
4%
 
25%
 
15%
We sold coal to approximately 83 different customers in 2016. Our top ten customers since the acquisition of assets from Alpha accounted for approximately 41% of 2016 total coal revenues and our largest customer during 2016 accounted for approximately 7% of 2016 total coal revenues, on a pro forma basis. The following table provides information regarding domestic and export sales in 2016 by revenues and tons sold: 
 
Tons Sold
 
Tons Sold as a
Percentage of
Coal Sales Volume
 
Coal
Revenues
 

Percentage of Coal
Revenues
 
(In millions, except percentages)
Export
5.0
 
11%
 
399.3
 
35%
Domestic
41.7
 
89%
 
749.7
 
65%
Export shipments serviced other customers through shipping ports in 15 countries during 2016, as shown on the map below. Europe was the largest export market in 2016, with coal sales to Europe accounting for approximately 44% of total export coal revenues and 15% of total coal revenues. All of our sales are made in U.S. dollars.
exportsalesmapa01.jpg

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We enter into long-term contracts (typically ranging from one to five years) with our steam 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 agreements contain committed volumes and fixed prices. However, some of these long-term agreements are unpriced or contain price adjustment and price reopener features that permit renegotiation or modification of coal sale prices. Provisions of this sort make it more difficult for us to predict the prices we will receive for our coal during the course of the agreement. During 2016, approximately 91% of our steam coal sales volume was delivered pursuant to long-term contracts.
Met coal sales are contracted differently based on the region where the customer is located. Domestic contracts are typically completed on an annual basis, while our export contracts are normally either on a quarterly or spot basis.
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 2016, our produced coal was transported from the mines and to the customer primarily by rail, with the main rail carriers being CSX Transportation, Norfolk Southern Railway Company, BNSF Railway and Union Pacific Railroad Company. Rail shipments constituted approximately 86% of total shipments of captive coal volume from our mines to the customer in 2016. The balance was shipped from our preparation plants, loadout facilities or mines via truck or barge. Our export sales are primarily shipped to Chesapeake Bay Pier shipping port in Maryland, and DTA, Pier VI and Lamberts Point shipping ports in Virginia. We own a 65.0% interest in the coal export terminal at Newport News, Virginia, which is operated by DTA.
Procurement
We incur substantial expenses per year to procure goods and services in support of our business activities in addition to capital expenditures. Principal goods and services include maintenance and repair parts and services, electricity, fuel, roof control and support items, explosives, tires, conveyance structure, ventilation supplies and lubricants. 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 and to support computer systems.
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.

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Competition
The coal industry is highly competitive. We compete for U.S. sales with numerous coal producers in the Appalachian region, and the Illinois basin, and with western coal producers. The most important factors on which we compete 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 east from western coal mines has resulted in increased competition for coal sales in the Appalachian region.
Demand for steam 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 our low sulfur coal and the prices that we are able to obtain for it are also be affected by the price and availability of high sulfur coal.
Demand for our met coal and the prices that we are able to obtain for it depend to a large extent on the demand 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.
Employees
As of December 31, 2016, we had approximately 2,200 employees, with the UMWA representing approximately 29% of these employees. Certain of our subsidiaries have wage agreements with the United Mine Workers of America (“UMWA”) that are subject to termination by either the employer or the UMWA, without cause, on July 31, 2020. Either party may also reopen the wage agreements on July 26, 2018, for the sole purpose of renegotiating changes in the hourly wage rates, by giving written notice to the other party during the period from May 1, 2018 through June 1, 2018. Relations with organized labor are important to our success, and we believe we have good relations with our employees.
Legal Proceedings
On November 16, 2016, the West Virginia Department of Environmental Protection (“DEP”) filed a complaint with the Bankruptcy Court (Adversary Case 16-03334) against us, Alpha Natural Resources, Inc., Citicorp North America, Inc. and certain former members of Alpha management who are now affiliated with us. The complaint made, among other claims, allegations regarding the accuracy of financial projections prepared in connection with the confirmation of Alpha’s plan of reorganization in July 2016.
On November 28, 2016, the parties reached a settlement (the “Settlement Agreement”) pursuant to which we will provide financial guarantees, for the benefit of the DEP, in connection with ANR’s performance of certain of its environmental obligations through 2018. The Settlement Agreement became effective upon the dismissal of the DEP complaint with prejudice and the approval of the settlement by the Bankruptcy Court on December 7, 2016. Pursuant to the Settlement Agreement, we agreed to provide a letter of credit of $4.0 million or similar instrument, in support of ANR’s payment obligations under the Permitting and Reclamation Plan Settlement Agreement for the State of West Virginia, dated as of July 12, 2016 by and among us, ANR, DEP and the Reclamation Funding Agreement, dated as of July 12, 2016, by and among us, ANR, the relevant agencies of the states of Illinois, Kentucky, Virginia and West Virginia and the United States government. Pending the letter of credit or similar instrument to be put in place, we placed $4.0 million in cash, pursuant to the Deposit Account Control Agreement with PNC Bank, National Association, dated as of December 22, 2016, to be kept in escrow. We also provided a secured guaranty, dated as of December 22, 2016, for ANR’s payment obligations under the two agreements

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described above, in an amount not to exceed $4.5 million and on March 31, 2017, we placed $4.5 million in cash, pursuant to the Deposit Account Control Agreement with PNC Bank, National Association, dated as of March 23, 2017, to be kept in escrow.
From time to time, we could also become party to other legal proceedings. 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, 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.

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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 adverse 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 since our inception in 2016 have been material. We expect that future liability under or compliance with environmental and safety requirements could have a material effect on our operations or competitive position. Under some circumstances, substantial fines and penalties, including revocation 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, 2016, we had accrued $191.4 million for reclamation liabilities and mine closures, including $4.3 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 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 access that overlies 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 obtaining transfer of certain permits held by Alpha for the operations we acquired from Alpha. All necessary applications for the transfer of such permits have been filed, and we are authorized to continue operating on such permits as the mine or facility operator until such transfers have been completed.

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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 that 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, 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 be delayed, refused or revoked if an officer or director of, a stockholder with a 10% or greater interest in, or certain other affiliates of, the applicant or permittee or an entity that is affiliated with or is in a position to control the applicant or permittee, has outstanding permit violations. Thus, past unabated or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits or amendments or renewals of existing permits.
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.
From time to time, OSM will revise its mining regulations under SMCRA. For example, in December 2016, the OSM published a final rule (the “Stream Protection Rule” or “SPR”) purportedly to revise its regulations related to protecting streams and their associated buffer zones. The SPR became effective in January 2017. However, in February 2017 Congress approved a resolution disapproving the SPR pursuant to the Congressional Review Act. President Trump signed the resolution on February 16, 2017, effectively repealing it and also preventing a rule in “substantially the same form” from being promulgated again without future legislation. On April 13, 2017 the OSM announced the withdrawal of a December 2016 Biological Opinion that addressed the implementation of the SPR in SMCRA permitting actions raising issues under the Endangered Species Act and provided guidance to states on addressing such issues while a new Biological Opinion is developed.
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 period from July 26, 2016 to December 31, 2016, we recorded $5.1 million of expense related to these fees.

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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”).
Mineral Leasing Act. Some of our operations involve mining federal coal. Operations involving federal coal may require additional approvals, including from the US Department of the Interior, such as mine plan modifications and approvals, lease by application (“LBA”) and lease by modification (“LBM”) to increase our reserves, under the Mineral Leasing Act. These approvals require compliance with other federal environmental laws, which require public comment processes and may be the subject of litigation by project opponents. The OSM is currently working on the environmental review for the Belle Ayr North Tract Mining Plan Modification. If approved, the amount of mineable federal coal would extend the life of the mine by approximately nine years.
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, 2016, our posted third-party surety bond amount in all states where we operate was approximately $315.1 million, 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 a settlement we entered into in connection with the Alpha Restructuring, we were required to replace Alpha’s self-bonds with surety bonds, collateralized bonds, or other financial assurance mechanisms, 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. We have partly secured our bonding obligations for our operations in Wyoming, which currently totals $263.8 million, through an arrangement whereby we have granted the State of Wyoming a security interest in some of our real property and equipment. Certain citizen groups filed objections to these arrangements as contrary to applicable regulations. We are in the process of replacing the security interests in our personal property with third-party surety bonds, estimated at approximately an additional $71 million. We estimate that the annual costs to maintain our required surety bond program to be approximately $8 to 9 million. 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 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.
A suit challenging the EPA’s 2015 Ozone NAAQS Murray Energy Corp. v. EPA is currently pending in the D.C. Circuit. However, on April 11, 2017, the D.C. Circuit granted EPA’s motion to indefinitely delay any decision on the challenges. In its motion, the EPA cited President Trump’s March 2017 Executive Order that directed the EPA to review for possible reconsideration any rule that could potentially burden the development of coal and other domestic energy sources. In addition, on November 17, 2016, the EPA published the Proposed Non-attainment Area Classifications and SIP Requirements Rule containing implementation requirements for the 2015 ozone NAAQS. 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, the areas in which we operate are currently in attainment with respect to the pollutants associated with our operations. However, our operations could be impacted if the attainment status of the areas in which we operate changes in the future.
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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.
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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 calls 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 steam 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

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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 28, 2017, the D.C. Circuit stayed the litigation.
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.
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.
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 steam 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.
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)

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to reduce their global GHG emissions. In December 2015, the United States and almost 200 nations agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. The Paris Agreement entered into force on November 4, 2016 upon achieving its threshold for ratification by signatory countries. A long-term goal of this Paris Agreement is 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. These commitments could further reduce demand and prices for our coal. The Trump administration has announced that it is considering whether to remain a party to the Paris Agreement or to seek to renegotiate it.
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 NSPS for emissions of carbon dioxide for new, modified and reconstructed fossil fuel-fired EGUs (“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 CO2/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 CO2/MWh-gross, and subcritical conditions for smaller units to meet a standard of 2,000 lb CO2/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, 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 CPP, a final rule that establishes carbon pollution standards for existing power plants, called CO2 emission performance rates. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the CPP. The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour) or mass-based tonnage limits for CO2. The state plans were to be due in September 2016, subject to potential extensions of up to

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two years for final plan submission. The compliance period begins in 2022, and emission reductions will be phased in up to 2030. The EPA also proposed a federal compliance plan to implement the CPP in the event that an approvable state plan is not submitted to the EPA. Judicial challenges have been filed. 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 stay suspends the rule, including the requirement that states submit their initial plans by September 2016. The Supreme Court’s stay applies only to the CPP and does not affect the EPA’s standards for new power plants.
On April 28, 2017, 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 the brief the court on whether the case should be remanded to the agency or kept on hold. It is not clear how (or if) either the D.C. Circuit Court or the Supreme Court will rule on the legality of the CPP or 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. The EPA will also review the compliance dates set by the CPP, since some of these dates “have passed or will likely pass while the CPP continues to be stayed.” 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 State of 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.
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 groups have sought to stop or delay coal mining activities, bringing numerous lawsuits, including against the BLM and OSM to challenge not only the issuance of individual coal leases, mine plan modifications and approvals, but also the federal coal leasing program more broadly. 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 costs to mine federally owned coal.
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

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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.
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, West Virginia Department of Environmental Protection, the Pennsylvania Department of Environmental Protection, and the Kentucky Energy and Environment Cabinet filed a Complaint against Alpha alleging certain violations of the Clean Water Act, 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 (the “Alpha Consent Decree”). On July 12, 2016, a Stipulation Regarding Water Treatment Obligations (the “Stipulation”) was made in Alpha’s bankruptcy proceeding and entered into by and among: Alpha, Contura, Citicorp North America, Inc. and the EPA. The Stipulation requires, among other things, one or more subsidiaries of Contura to assume the Section IX Osmotic Pressure Injunctive Relief requirements under the Alpha Consent Decree, at the Cumberland and Emerald mines, and provides that such Contura subsidiaries may serve a request for termination of the Consent Decree only after completing such requirements and thereafter maintaining consistent satisfactory compliance with the Consent Decree for a period of two years. We anticipate that two of our subsidiaries will join in the Alpha Consent Decree to confirm our obligations as set forth in the Stipulation. Since July 26, 2016 the company has been and is currently in compliance with its obligations under the Stipulation.
Dredge and Fill Permits. Many mining activities, including the development of settling ponds and other impoundments, require a permit from the Army Corps of Engineers (“COE”) under Section 404 of the Clean Water Act. 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. NWP 21s 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 Corps 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,” now known as the Clean Water Rule (CWR) under the CWA. 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

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the COE resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” The U.S. Supreme Court is scheduled to decide whether the Sixth Circuit had jurisdiction to hear challenges to the CWR. The Supreme Court’s decision may have an impact on the continued validity of the nationwide stay. On February 28, 2017, 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, EPA and the Army Corps of Engineers published a Notice of Intent to review and rescind or revise the CWR. The process to undo and replace the CWR will likely be subject to extensive notice and 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 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, 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. The Agency later received petitions for administrative reconsideration of the final rule, in March and April 2017. The EPA informed the petitioners that it will reconsider the rule. The outcome of the reconsideration is uncertain, but the requirements could increase our customers’ costs and may adversely affect the demand for coal, which may materially impact our results or operations.
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.
Resource Conservation and Recovery Act. The 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 rule also requires fugitive dust controls and imposes various monitoring, cleanup, and closure requirements.
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

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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. The 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 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 coal mines and property that we currently control. 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 Department of Homeland Security 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 Department of Homeland Security 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. 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.
National Environmental Policy Act. The National Environmental Policy Act (“NEPA”) requires federal agencies, including the Department of the Interior and its agencies such as OSM and BLM, to evaluate major agency actions that have the potential to significantly impact the environment, such as issuing a permit or other approval. In the course of such evaluations, an agency will typically prepare an environmental assessment to assess the potential direct, indirect and cumulative impacts of a proposed project. Where the activities in question have significant impacts to the environment, the agency must prepare an Environmental Impact Statement (“EIS”). Compliance with NEPA can be time-consuming and may result in the imposition of mitigation measures that could affect the amount of coal that we are able to produce from mines on federal lands, and may require public comment. Whether agencies have complied with NEPA is subject to protest, appeal or litigation, which can delay or halt projects. The NEPA review process, including potential disputes regarding the level of evaluation required for climate change impacts, may extend the time and/or increase the costs and difficulty for obtaining necessary governmental approvals, and may lead to litigation regarding the adequacy of the NEPA analysis, which could delay or potentially preclude the issuance of approvals or grant of leases.
In August 2016, the Council on Environmental Quality (“CEQ”) released final guidance discussing how federal agencies should consider the effects of GHG emissions and climate change in their NEPA evaluations. The guidance directs agencies to consider: (1) the potential effects of a proposed action on climate change as indicated by assessing GHG emissions and, (2) the effects of climate change on a proposed action and its environmental impacts. However, President Trump’s March 2017 Executive Order rescinded this final guidance.
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

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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.
DOI Moratorium and Programmatic EIS. On January 15, 2016, the Secretary of the Department of the Interior (“DOI”) issued an order imposing a moratorium on the issuance of new leases for coal resources on federally-owned lands in order to allow for a “comprehensive review” of the federal coal programs. The terms of this moratorium precluded the BLM from accepting new applications for steam coal sales, or modifying existing leases subject to certain exceptions. The moratorium did not preclude a company holding a lease from developing coal resources and thus did not interfere with our ongoing operations.
President Trump’s March 2017 Executive Order directed the Secretary of the Interior to amend or withdraw this order and lift the moratorium. On March 29, 2017, the new Secretary of the Interior revoked the DOI moratorium and ended the programmatic EIS.
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 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 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. 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 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. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the United States. For the period from July 26, 2016 to December 31, 2016, we recorded $10.2 million of expense related to this excise tax.

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The Patient Protection and Affordable Care Act introduces 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 establishes 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 insurance coverage sufficient 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 insurance policies.
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.

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MANAGEMENT
Directors and Executive Officers
The following table sets forth the names, ages and titles of our directors and executive officers.
Name
Age
 
Position
Kevin S. Crutchfield
56
 
Chief Executive Officer and Director
Charles Andrew Eidson
41
 
Executive Vice President and Chief Financial Officer
Gary W. Banbury
64
 
Executive Vice President and Chief Administrative Officer
V. Keith Hainer
48
 
Executive Vice President and Chief Operating Officer
Mark M. Manno
46
 
Executive Vice President, General Counsel,
Secretary and Chief Procurement Officer
Kevin Stanley
42
 
Executive Vice President and Chief Commercial Officer
Neale X. Trangucci
60
 
Chairman of the Board
Albert E. Ferrara, Jr.
68
 
Director
Jonathan Segal
35
 
Director
Each officer serves at the discretion of our board of directors and holds office until his or her successor is elected and qualified or until his or her earlier resignation or removal. There are no family relationships among any of our directors or executive officers.
Set forth below is a description of the background of the persons named above.
Kevin S. Crutchfield has served as our chief executive officer and as one of our directors since July 26, 2016. He also serves as chairman of the safety, health and environmental committee of our board of directors. He previously served as chairman and chief executive officer of Alpha Natural Resources, Inc., having been appointed as a director in November 2007, elected as chief executive officer at the time of Alpha’s merger with Foundation Coal in July 2009 and named chairman in May 2012. He was also a member of the safety, health, environmental and sustainability committee from the time of the merger. Prior to that time, he served as Alpha’s president from January 2007 until the merger. Mr. Crutchfield also served as Alpha’s executive vice president from November 2004 until January 2007. Alpha filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on August 3, 2015.
Mr. Crutchfield joined Alpha’s management team as the executive vice president of Alpha Natural Resources, LLC and vice president of ANR Holdings, LLC in March 2003, and also served as the executive vice president of ANR Holdings, LLC from November 2003 until ANR Holdings was merged with another of Alpha’s subsidiaries in December 2005. From June 2001 through January 2003, he served as vice president of El Paso Corporation, a natural gas and energy provider, and president of Coastal Coal Company, a coal producer and affiliate of El Paso Corporation, acquired by Alpha in 2003.
Prior to joining El Paso, he served as president and CEO of AMVEST Corporation, a coal and gas producer and provider of related products and services, and held executive positions at AEI Resources, Inc., a coal producer, including president and chief executive officer. Before joining AEI Resources, he served as the chairman, president and chief executive officer of Cyprus Australia Coal Company (“Cyprus”) and held executive operating management positions with Cyprus in the U.S. before being relocated to Sydney, Australia in 1997. He worked for Pittston Coal Company in various operating and executive management positions from 1986 to 1995, including as vice president operations, prior to joining Cyprus.
Mr. Crutchfield is currently the chairman of the board for the National Mining Association and serves on the board of directors of Coeur Mining Inc. He also served on the board of directors of King Pharmaceuticals, Inc. from

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February 2010 until the first quarter of 2011, when he resigned in connection with the acquisition of King Pharmaceuticals by Pfizer, and on the board of directors of Rice Energy Inc. from January 2014 to November 2014. Mr. Crutchfield holds a bachelor of science degree in mining and minerals engineering from Virginia Polytechnic Institute and State University, and he also completed the executive program at the University of Virginia’s Colgate Darden School of Business. For these reasons, we believe Mr. Crutchfield is qualified to serve as a director.
Charles Andrew Eidson has served as our executive vice president and chief financial officer since July 26, 2016. He previously served as executive vice president and chief financial officer of Alpha Natural Resources, Inc., a position he held from March 2016. His previous roles with Alpha included senior vice president, strategy and business development, and vice president, mergers and acquisitions. Alpha filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on August 3, 2015.
Prior to joining Alpha in July 2010, Mr. Eidson held several financial positions across industry sectors, including at PricewaterhouseCoopers LLP, Eastman Chemical Company, and most recently Penn Virginia Resource Partners, where he led mergers and acquisitions projects for the coal segment and managed the budgeting and planning process. Mr. Eidson holds a bachelor of science degree, cum laude, in commerce and business administration from the University of Alabama and a master of business administration degree from Milligan College.
Gary W. Banbury has served as our executive vice president and chief administrative officer since July 26, 2016. He previously served as the executive vice president and chief administrative officer of Alpha Natural Resources, Inc. since July 2013. Alpha filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on August 3, 2015.
Prior to joining Alpha, Mr. Banbury served as executive vice president and chief administrative officer for Allied Nevada Gold Corp. Prior to that time, Mr. Banbury held a number of other senior roles, including president and chief operating officer of RJ Human Capital Services and senior vice president/chief administrative officer for Coeur d’Alene Mines Corporation. Mr. Banbury earned his bachelor of science degree in Personnel and Labor Relations from Michigan Technological University.
V. Keith Hainer has been our executive vice president and chief operating officer since July 26, 2016. He previously served as executive vice president, mining operations for Alpha Natural Resources, Inc., a position he held from January 2015. From the time he joined Alpha in 2011, Mr. Hainer served as vice president, asset engineering and senior vice president, operations excellence and idle mines. Alpha filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on August 3, 2015.
Prior to joining Alpha, he held a number of positions in engineering maintenance and production with Massey Energy, including vice president, maintenance starting in 2008. Mr. Hainer began his mining career with Shell Mining in 1989. Mr. Hainer earned a bachelor of science in physics from Marshall University, as well as a master of science in engineering and an MBA from Marshall. He also earned a bachelor of science in electrical engineering from the West Virginia University Institute of Technology. Mr. Hainer serves on the board of advisors for West Virginia University College of Mineral Engineering and the board of advisors for Marshall University - College of Information Technology and Engineering.
Mark M. Manno has served as our executive vice president, general counsel, secretary and chief procurement officer since July 26, 2016. He previously served as executive vice president, general counsel, secretary and chief procurement officer for Alpha Natural Resources, Inc., positions he held from December 2015. Prior to these positions, Mr. Manno served as senior vice president, chief information and sourcing officer from February 2015, and senior vice president, strategic sourcing and information technology for Alpha’s wholly owned subsidiary, Alpha Natural Resources Services, LLC, from March 2014. Mr. Manno previously served as vice president, strategic sourcing and materials management from April 2012, and also as vice president and assistant general counsel. Alpha filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on August 3, 2015.

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Before joining Alpha in February 2010, Mr. Manno was general counsel and real estate division president with SJ Strategic Investments in Bristol, Tennessee. Earlier in his career, he served in multiple roles with King Pharmaceuticals, Inc. and was an attorney with Baker, Donelson, Bearman, Caldwell & Berkowitz, PC, in Johnson City, Tennessee. Before joining the private sector, Mr. Manno was an officer in the U.S. Navy and a graduate of the U.S. Naval Academy. He completed his master of business administration degree at Mississippi State University and his law degree at the University of Memphis.
Kevin Stanley has served as our executive vice president and chief commercial officer since April 28, 2017. He previously served as our senior vice president, sales and marketing since July 26, 2016 and as senior vice president, business planning for Alpha, a position he held from December 2015. Prior to this position, Mr. Stanley served as vice president, business planning for Alpha from 2012 and in several additional roles, including as director of corporate development from 2011 for Alpha Australia, LLC, a wholly owned subsidiary of Alpha. Alpha filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on August 3, 2015.
Prior to joining Alpha in 2003, Mr. Stanley served in various accounting roles for subsidiaries of Massey Energy. Mr. Stanley holds a bachelor of science degree in accounting from the University of Virginia’s College at Wise.
Neale X. Trangucci has served as one of our directors since July 26, 2016. He is chairman of our board of directors and chairman of the nominating and corporate governance committee of our board of directors. In 2014, he formed NXT Partners LLC, where he is the principal / owner. He served as co-head of bankruptcy and distressed investments with Mason Capital Management from 2005 until 2014 and previously held senior positions focused on distressed assets and investments with Stonehill Investment Corp / WHX Corp. (including as a partner in Stonehill and as chief executive officer of WHX Corp.), Salomon Brothers Inc. in New York City and Continental Illinois Bank. Mr. Trangucci has also served on the board of directors of George Industries Inc., Automation Tooling Systems, WHX Corp., Wheeling-Pittsburgh Corp., Wheeling-Nisshin Inc., Photowatt International, Handy & Harman and Unimast. Mr. Trangucci earned a bachelor of science degree from Bucknell University and a master’s degree in international finance and banking from Columbia University. For these reasons, we believe Mr. Trangucci is qualified to serve as a director.
Albert E. Ferrara, Jr. has served as one of our directors since July 26, 2016 and is chairman of the audit committee of our board of directors. Mr. Ferrara has spent over forty years in the metals and related resource industry. Mr. Ferrara served in senior executive positions with AK Steel, including senior vice president finance and chief financial officer, from 2003 until his retirement in 2013. Before joining AK Steel, Mr. Ferrara spent thirty years with United States Steel Corporation/USX Corporation in a variety of roles domestically and internationally, including senior vice president finance and treasurer. Mr. Ferrara has served since 2014 as a principal of Amelia Metals LLC, a consulting firm specializing in the metals and mining industries. Mr. Ferrara holds a bachelor of science in commerce with distinction and a juris doctor degree, both from the University of Virginia. He has been licensed to practice law in the State of Pennsylvania. For these reasons, we believe Mr. Ferrara is qualified to serve as a director.
Jonathan Segal has served as one of our directors since July 26, 2016 and is chairman of the compensation committee of our board of directors. He is a managing director of, and portfolio manager for, Highbridge Capital Management, LLC (“Highbridge”). He joined Highbridge in 2007. Before joining Highbridge, Mr. Segal worked at Sanford Bernstein & Co., LLC. He also serves on the board of directors of Hycroft Mining Corporation, where he is a member of its Audit and Compensation Committees and chair of its Nominating and Governance Committee. Mr. Segal received a bachelor of arts degree in urban studies from the University of Pennsylvania. For these reasons, we believe Mr. Segal is qualified to serve as a director.
Board of Directors
Our board of directors currently consists of four members. All of our directors serve one-year terms, with all directors elected each year. Under the NYSE rules, we will be required to have our compensation and nominating and corporate governance committees be comprised of a majority of independent directors within 90 days of the

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effectiveness of the registration statement of which this prospectus is a part, and we will be required to have a majority of independent directors on our board of directors and to have our compensation and nominating and corporate governance committees be comprised entirely of independent directors within one year of the effectiveness of the registration statement.
In evaluating director candidates, our board of directors will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of our board of directors to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of our board of directors to fulfill their duties. We have no minimum qualifications for director candidates. In general, however, our board of directors will review and evaluate both incumbent and potential new directors in an effort to achieve a diversity of skills and experience among our directors in light of the following criteria:
•
experience in business, government, education, technology or public interests;
•
high-level managerial experience in large organizations;
•
breadth of knowledge regarding our business or industry;
•
specific skills, experience or expertise related to an area of importance to us, such as energy production, consumption, distribution or transportation, government, policy, finance or law;
•
moral character and integrity;
•
commitment to our stockholders’ interests;
•
ability to provide insights and practical wisdom based on experience and expertise;
•
ability to read and understand financial statements; and
•
ability to devote the time necessary to carry out the duties of a director, including attendance at meetings and consultation on company matters.
Committees of the Board of Directors After this Offering
After this offering, our board of directors will have an audit committee, a compensation committee, a nominating and corporate governance committee and a safety, health and environmental committee.
Audit Committee
After this offering, our audit committee is expected to consist of Messrs.          and          , with Mr. Ferrara serving as chairman. Mr.          will be our audit committee “financial expert” as that term is defined in Item 401(h) of Regulation S-K. Messrs.          and          currently qualify as “independent” members of the audit committee as defined in the rules of the SEC and NYSE setting forth independence requirements for public company audit committees. We are required by SEC and NYSE rules to have an audit committee composed of a majority of independent directors within 90 days of the date of the effectiveness of the registration statement of which this prospectus is a part and an audit committee composed entirely of independent directors within one year from that date. We intend to comply with these requirements regarding the independence of our audit committee.
The audit committee will provide assistance to our board of directors in monitoring the quality, reliability and integrity of our accounting policies and financial statements, overseeing our compliance with legal and regulatory requirements and reviewing the independence, qualifications and performance of our internal and independent auditors. The audit committee will also be responsible for (1) the appointment, compensation, and oversight of our independent auditor, (2) approving the overall scope of the audit and approving any non-audit services to be

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performed by the independent auditor, (3) annually reviewing a report by the independent auditor describing the firm’s internal quality control procedures, any material issues raised by the most recent internal quality control review, or peer review, of the auditing firm, and all relationships between us and the independent auditor, (4) discussing the annual audited and quarterly unaudited financial statements with management and the independent auditor, (5) discussing the company’s press releases, as well as financial information and earnings guidance provided to analysts and rating agencies, (6) reviewing and discussing risk assessment and risk management policies as well as procedures management has established to monitor compliance with our Code of Business Ethics, (7) meeting periodically, but separately, with the independent auditor, internal auditors and management, (8) reviewing with the independent auditor any audit problems or difficulties and management’s response, (9) preparing an audit committee report as required by the SEC to be included in our annual proxy statement, (10) establishing policies regarding the company’s hiring of employees or former employees of the independent auditor, (11) annually reviewing and reassessing the adequacy of audit committee’s written charter and recommending any proposed changes to the board of directors, (12) reporting regularly to the full board of directors, (13) conducting an annual performance review and evaluation of the audit committee, and (14) handling other matters that are specifically delegated to the audit committee by the board of directors from time to time.
Compensation Committee
After this offering, we expect that the members of the compensation committee will be Messrs.          and          , with          serving as chairman of the committee. Messrs.          and          currently qualify as “independent” members of the compensation committee as defined in the rules of the NYSE setting forth independence requirements for public company compensation committees. We are required by the SEC and NYSE rules to have a compensation committee composed of a majority of independent directors within 90 days of the date of the effectiveness of the registration statement of which this prospectus is a part and a compensation committee composed entirely of independent directors within one year from that date. We intend to comply with these requirements regarding the independence of our compensation committee.
The compensation committee and its designated subcommittees will be responsible for assisting our board of directors in all matters relating to the compensation of our directors and executive officers and complying with legal and regulatory requirements as they relate to matters of compensation, including (1) reviewing and recommending to the board of directors compensation, including base salary, bonuses and benefits, of our chief executive officer, (2) approving compensation, including salary, bonuses and benefits, of our other executive officers, (3) reviewing and approving corporate goals and objectives relevant to the compensation of executive officers and evaluating their performance in light of these goals and objectives, (4) reviewing and recommending to the board of directors executive compensation policies and practices for our executive officers generally, (5) reviewing director compensation and recommending any proposed changes to the board of directors, (6) reviewing and recommending to the board of directors, or approving, any employment contract or similar agreement for any executive officer, (7) reviewing and consulting with our chief executive officer regarding compensation matters , (8) reviewing, approving and making recommendations to the board of directors with respect to incentive compensation plans and equity-based plans, and administering the plans, (9) monitoring compliance with applicable laws relating to compensation of executive officers, (10) producing a compensation discussion and analysis disclosure or, if applicable, a compensation committee report on executive compensation as required by the SEC to be included in the company’s annual proxy statement or annual report on Form 10-K filed with the SEC, (11) reporting to the full board of directors following the compensation committee’s meetings or actions, (12) conducting an annual performance evaluation of the compensation committee, and (13) handling other matters that are specifically delegated to the compensation committee by the board of directors from time to time.
The compensation committee charter will set forth the committee’s role and responsibilities relative to managing and approving the components of compensation for our executive officers and certain other responsibilities. Under its charter, our compensation committee will be authorized to delegate its responsibilities to one or more subcommittees, and may invite other directors and officers of the company to its meetings in order to carry out its responsibilities. Under the terms of the Contura Energy, Inc. Amended and Restated Management Incentive Plan, as described under “—Management Incentive Plan” below, and the Contura Energy, Inc. 2017 Long-Term Incentive Plan, which will become effective upon the completion of this offering and as described under “—2017 Long-Term Incentive Plan”

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below, our compensation committee is authorized to administer these plans and may delegate its authority thereunder. Pursuant to our Annual Incentive Bonus Plan, as described under “—Annual Incentive Bonus Plan” below, our compensation committee may delegate its powers under the plan to our chief executive officer with respect to participants not subject to Section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”). In addition, the Contura Energy, Inc. Deferred Compensation Plan, which was approved by our compensation committee on April 28, 2017 and is described under “—Deferred Compensation Plan” below, authorizes our chief executive officer and our chief administrative officer to designate employees eligible for participation in the plan with the approval of our compensation committee, and otherwise authorizes our compensation committee to delegate such approval authority to officers of the company.
Our compensation committee has delegated to our chief executive officer authority to administer, grant, and determine awards of non-executive employees under the Annual Incentive Bonus Plan and the Amended and Restated Management Incentive Plan and to add eligible non-executive employee participants in the company’s Key Employee Separation Plan, as described under “—Executive Compensation—Key Employee Separation Plan” below.
Independent Compensation Consultants
The compensation committee has the authority to engage the services of outside advisors and, the compensation committee retained The POE Group, Inc. (the “POE Group”) in December 2016 to assist the compensation committee with its review of our executive and director compensation programs including, without limitation: (i) reviewing the competitive pay practices for benchmarking purposes with respect to compensation and performance, (ii) conducting a competitive assessment of each executive’s total direct compensation (e.g., base salary, annual and long-term incentives), (iii) developing a trends report regarding executive compensation and keeping the compensation committee apprised of regulatory changes and other developments related to executive compensation, (iv) advising the compensation committee regarding annual and long-term incentive plan design, (v) performing a competitive assessment of non-employee director compensation and (vi) assisting with the preparation of proxy disclosures. To maintain the consultants’ independence from management, the consultants did not provide any services to our company, including to members of management, other than services provided to the compensation committee. Prior to retaining the POE Group, the committee reviewed (and will review on an annual basis) the following with the POE Group: (i) whether the POE Group provided other services to the company, (ii) the amount of fees received from us by the POE Group as a percentage of the total revenue of the POE Group, (iii) policies and procedures of the POE Group that are designed to prevent conflicts of interest, (iv) any business or personal relationships of the consultants or the POE Group with members of the compensation committee or our executive officers, and (v) any of our stock owned by the consultants. In each case, the compensation committee has found that the POE Group and the POE Group consultants did not have any relationships with us or own stock in the company.
The independent compensation consultants reported directly to the compensation committee and, with the consent of the committee, coordinated and gathered information with which to advise the committee from members of management and human resources personnel. The work of the POE Group for the committee did not present any conflicts of interest that required the committee’s consideration.
For more information regarding our compensation committee’s processes for determining executive officer compensation and the role of our independent compensation consultants in executive compensation matters, see “Executive Compensation—Executive Compensation Process.”
Nominating and Corporate Governance Committee
After this offering, we expect that our nominating and corporate governance committee will consist of Messrs.          and          , with Mr. Trangucci serving as chairman of the committee. Messrs.          and          currently qualify as “independent” members of the nominating and corporate governance committee as defined in the rules of the NYSE setting forth independence requirements for public company nominating and corporate governance committees. The nominating and corporate governance committee will assist the board of directors in identifying individuals qualified to become board members and executive officers and selecting, or recommending that the board select, director nominees for election to the board of directors and its committees. The nominating and

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corporate governance committee will also be responsible for (1) developing and recommending governance policies and procedures to the board of directors, (2) reviewing conflicts of interest that may affect directors, (3) monitoring our compliance with corporate governance practices and policies, (4) leading the board of directors in its annual review of the board’s performance, (5) making recommendations regarding committee purpose, structure and operation and (6) overseeing and approving a management continuity planning process.
Safety, Health and Environmental Committee
After this offering, we expect that the members of the safety, health and environmental committee will be Messrs.          and          , with Mr. Crutchfield serving as chairman of the committee. Under the committee’s charter, a majority of its members must satisfy the independence standards of the NYSE and any applicable regulatory requirements.
The safety, health and environmental committee provides oversight of the company’s performance in relation to safety, occupational health, environmental and sustainability issues, including: (i) reviewing appropriate objectives and policies for the company relative to the protection of the safety and health of employees, contractors, customers, the public and the environment; (ii) overseeing the company’s monitoring and enforcement of these policies and related procedures and practices and, in connection with this oversight, assessing reports and other information provided by company management and such external resources as the committee deems appropriate, (iii) overseeing the company’s policies and procedures for identifying, assessing, monitoring and managing the principal risks in the company’s business associated with safety and occupational health, the protection of the environment and sustainable development and, in connection with this oversight, assessing reports and other information provided by company management and such external resources as the committee deems appropriate; (iv) discussing with management annually the scope, plans, and resources for conducting audits of the company’s safety, health, environmental and sustainable practices and performance and, at least annually, reviewing significant results of these audits; (v) reviewing the company’s response to significant safety, health, environmental and sustainability-related public policy, legislative, regulatory, political and social issues and trends that may affect the business operations, financial performance, or public image of the company or the industry; and (vi) performing other duties as assigned to it from time to time by the board of directors.
Code of Business Conduct and Ethics
The board of directors has adopted a Code of Business Conduct and Ethics (the ‘‘Code of Ethics’’) that is applicable to all directors, employees and officers of the company. The Code of Ethics will constitute the company’s ‘‘code of ethics’’ within the meaning of Section 406 of the Sarbanes-Oxley Act and will be available on our website at www.conturaenergy.com. Information on our website is not part of this prospectus and does not constitute an offer for the sale of our securities. In addition, printed copies of the Code of Ethics will be available upon written request to Investor Relations, 340 Martin Luther King Jr. Blvd., Bristol, Tennessee 37620. The company intends to disclose future amendments to certain provisions of the Code of Ethics, or waivers of such provisions applicable to the company’s directors and executive officers, on our website.
Corporate Governance Guidelines
Our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE.
Compensation Committee Interlocks and Insider Participation
None of our executive officers serves, or has served during the past year, as a member of our board of directors or compensation committee of any other company that has one or more executive officers serving as a member of our board of directors or compensation committee.


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Compensation of Our Directors
In 2016, each non-employee director received an annual equity award of $75,000 granted in the form of restricted stock units (“RSUs”) and a cash retainer of $75,000, which each non-employee director had the opportunity to elect, and each did elect, pursuant to our Non-Employee Director Compensation Program, as described below under “—Non-Employee Directors Deferred Compensation Program” (the “Director Program”), to receive in RSUs in lieu of cash in order to defer such payments. In addition to the annual retainer, non-employee directors may be entitled to receive additional cash retainers in connection with service as chair members of the committees of our board of directors. The following chart summarizes the additional cash retainers to which non-employee directors may be entitled:
Position
Annual Fee
Non-Employee Chairman of the Board
$
25,000

Lead Independent Director if Employee Director is Chairman of the Board
20,000

Audit and Safety, Health and Environmental Committee Chairs
15,000

Compensation and Nominating and Corporate Governance Committee Chairs
10,000

Non-employee directors’ annual equity awards are currently granted in the form of RSUs. These awards are granted pursuant to RSU agreements that generally provide for vesting on the first anniversary of the grant date. The awards are subject to forfeiture in the event a director breaches certain confidentiality covenants and will accelerate and vest in connection with a change in control of our company or if the director ceases to serve as a member of our board of directors as a result of permanent disability or death.
Our chief executive officer, who is our only employee director, did not receive any additional compensation in connection with his service on our board of directors. The compensation paid to our chief executive officer is reported in the Summary Compensation Table and the other tables below beginning with “—2016 Summary Compensation Table.”
Additionally, we reimburse directors for travel expenses incurred in connection with attending board of directors, committee and stockholder meetings and for other business-related expenses, in accordance with our reimbursement policies, as they may be amended from time to time.
On January 18, 2017, our compensation committee approved an amendment to the Director Program, which modified annual cash retainer amounts for certain board positions. In addition, the amendment provided for a true-up payment for directors who held these positions during the period from August 1, 2016 to January 18, 2017. These 2017 true-up payments were made in 2017 and, therefore, are not included in the Director Compensation Table below. The following chart summarizes the cash retainer amounts to which non-employee directors are entitled after the amendment to the Director Program:
Position
 
Annual Fee
Non-Employee Chairman of the Board
 
$
75,000

Lead Independent Director if Employee Director is Chairman of the Board
 
20,000

Audit Committee Chair
 
20,000

Compensation and Safety, Health and Environmental Committee Chairs
 
15,000

Nominating and Corporate Governance Committee Chair
 
10,000

On April 19, 2017, our board of directors approved an amendment to the Director Program, providing for a $5,000 annual payment to be made to non-chair committee members for service on each respective board of

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directors committee. For 2017, the payments were paid promptly following the date of the amendment, and for future years, they will be paid promptly following the company’s annual meeting.
Non-Employee Directors Deferred Compensation Program
In August 2016, the compensation committee approved the Non-Employee Director Restricted Stock Unit Election program for deferrals of cash compensation that would otherwise be paid to non-employee directors. The purpose of the program is to permit non-employee directors of the company to defer the receipt of compensation that would otherwise become payable to them. According to the terms of the program, participants may elect to defer 100% of their annual cash retainer to be received in the form of RSUs, and from July 26, 2016 to December 31, 2016, each of the three non-employee directors did elect to defer. The non-employee directors will also have to elect the length of the deferral, which can be until the director’s separation of service from the company or a specific future date which is not to be earlier than thirty days following the one-year anniversary of the date of grant. Each director’s account balance will be distributed in the form of shares of common stock on or within 30 days of the distribution date elected by the director. In the event of a change in control of our company, all deferred share units may be distributed to participants, regardless of the elected distribution date, on or within 30 days of the change in control.
2016 Director Compensation Table
The following table sets forth information concerning the compensation for our directors during the fiscal year ended December 31, 2016.  
Name
Fees Earned or Paid in Cash
($)
 
Stock Awards
($) (1)
 
Option Awards
($)
 
Non-Equity Incentive Plan Compensation ($)
 
Change in Pension Value and Non-qualified Deferred Compensation Earnings
 
All Other Compensation
($)
 
Total
($)
Albert E. Ferrara, Jr.
15,000
 
149,984

 
—

 
—

 
—

 
—

 
164,984
Jonathan Segal
   10,000
 
149,984

 
—

 
—

 
—

 
—

 
159,984
Neale X. Trangucci
25,000
 
149,984

 
—

 
—

 
—

 
—

 
174,984
_______________
(1)
The values in this column are based on the aggregate grant date fair values of awards computed in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification, (“ASC”) Topic 718, “Compensation—Stock Compensation” (“FASB ASC Topic 718”).
The values set forth in this column relate to the following RSU awards: on August 1, 2016, Messrs. Ferrara, Segal and Trangucci each received an award of 9,374 RSUs, each with an aggregate grant date fair value of $149,984, which consisted of 4,687 RSUs in connection with their annual equity awards, and 4,687 RSUs in connection with their deferral of cash fees for service on our board in 2016, which fees were deferred and converted into RSUs that will vest on July 31, 2017 and which RSU amounts granted on each payment date are determined by dividing the cash fees deferred on that date by the closing market price per share of our common stock on that date.
As of December 31, 2016, Messrs. Ferrara, Segal and Trangucci each held an aggregate of 9,374 RSUs.

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EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Compensation of our named executive officers (“NEOs”) is determined under our compensation program for senior executives. Following completion of this offering, this program will be overseen by the compensation committee, which will determine the compensation of our executive officers.
The following discussion relates to the compensation of our NEOs whose compensation is disclosed below, as well as the overall principles underlying our executive compensation policies as we move towards becoming a public company. Our NEOs are:
•
Kevin S. Crutchfield, Chief Executive Officer (“CEO”),
•
Charles Andrew Eidson, Executive Vice President (“EVP”) and Chief Financial Officer,
•
Mark M. Manno, EVP, General Counsel, Corporate Secretary & Chief Procurement Officer,
•
V. Keith Hainer, EVP and Chief Operating Officer, and
•
Gary W. Banbury, EVP and Chief Administrative Officer.
2016 Business Highlights and Impacts on Compensation
We are providing information regarding our business performance and the impact of business performance upon the compensation actually realized by our NEOs in order to enable our stockholders to better understand our executive compensation programs, the key business factors that affect its design and the payments ultimately made under the programs.
2016 Business Performance
In 2016, the company performed well, highlighted by the following significant achievements for the period from July 26, 2016 to December 31, 2016:
•
Total revenues for 2016 were $689.4 million;
•
Coal revenues for the fourth quarter of 2016 were $399.3 million;
•
Total liquidity of approximately $127.9 million was maintained as of December 31, 2016, comprised of cash and cash equivalents;
•
Net income for the fourth quarter of 2016 was $35 million;
•
Adjusted EBITDA for 2016 was $129 million; and
•
We achieved safety and environmental goals with non-fatal days lost of 2.50 and an environmental compliance score of 16.67.
Compensation Executive Summary
Our executive compensation programs are designed to attract, retain and reward executives who create long-term shareholder value, share our mission, and perform in a manner that enables the company to achieve its strategic goals. Our compensation programs accomplish this by providing a market-based total compensation program tied to financial and operating performance and the interests of our shareholders. Our compensation programs reflect,

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reinforce and communicate our commitment to operate safely, responsibly and ethically, and continually strive to improve and deliver quality in everything we do.
•
Our executive compensation programs are administered by our compensation committee, appointed by our board of directors. The compensation committee has the responsibility to review and approve executive and director compensation and ensure our programs align with the policies and philosophies of the company.
•
Variable compensation, both short- and long-term, comprises the majority of the compensation opportunities for our executive team. Long-term compensation opportunity is emphasized over short-term opportunity to encourage executive retention and to align our executives’ interests with long-term results.
•
The company’s Annual Incentive Bonus Plan (described in “—2016 Annual Bonuses” below) measures both financial and operational performance goals, with an emphasis on financial measures. All executives have identical goals, supporting our belief in the importance of teamwork among our leadership team. Pay for performance is emphasized through a plan design that includes a threshold performance level, with significant upside should performance significantly exceed expectations, and by establishing maximum incentive payouts (caps).
•
Long-term incentives are the most important component of our total reward program. The opportunity for executives to earn equity awards, over time, aligns our executive team with the interests of our shareholders. The long-term compensation design is based on a portfolio approach which consists of vested stock options and vested restricted stock with one-year sale restrictions and stock options and restricted stock subject to three-year time-based vesting schedules.
•
Executive benefits and perquisites reflect the culture of our company. We may employ special arrangements (such as the Contura Energy, Inc. Deferred Compensation Plan described in “—Deferred Compensation Plan” below) when existing tax-qualified retirement plans are subject to limitations on benefits under the Internal Revenue Code or when significant competitive gaps exist in comparison to our industry peers. We utilize limited perquisites to enable us to attract and retain executive talent and further our business goals.
•
We believe our executives should own stock in the company, and our executive compensation program is designed to encourage executive stock ownership.
•
Our severance and change in control polices generally include a double trigger payout approach and do not employ tax gross-ups (in the case of a change in control).
Executive Compensation Process
Compensation Committee’s Role in Determining Executive Compensation
The compensation committee is responsible for ensuring that the company’s executive compensation policies and programs reflect the short-term and long-term interests of the company’s stockholders and are competitive in the markets in which the company competes for talent. The compensation committee reviews and approves the design of the compensation program, compensation levels, and benefit programs for the NEOs and other members of the management committee. When appropriate, the compensation committee consults with other board committees, such as the safety, health and environmental committee to determine appropriate performance targets that relate to the company’s non-financial achievements.
The compensation committee is committed to ensuring that our compensation and benefit programs are aligned with our values and business strategy by reviewing and analyzing the competitiveness of our executive compensation programs and our performance. Each key component of compensation (base salary, short-term incentives and long-term incentives) is reviewed for both internal equity and, when appropriate comparisons are available, for external competitiveness based on industry peers and published survey data.

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The compensation committee also takes into account external market conditions, such as competition for executives for a particular position, and position-specific factors when approving the total compensation for each NEO. The position-specific factors influencing the compensation levels include largely qualitative factors such as experience, tenure, job performance, contributions to our financial results, scope of responsibilities, and complexity of the position.
Role of Management and CEO in Determining Executive Compensation
As part of our process for establishing executive compensation, the CEO, the executive leader of administration and the human resources department provide information and recommendations to the compensation committee and compensation consultants regarding compensation program design and appropriate performance metrics. The CEO reviews the performance of the other NEOs with the compensation committee and makes recommendations to the committee regarding compensation levels and awards for the other NEOs. With respect to the CEO’s compensation, the committee recommends his compensation to the board following a review of market data provided by our compensation consultant and the performance of the CEO.
Compensation Consultants
The compensation committee has engaged the POE Group to advise it on executive compensation matters. The compensation consultants report directly to the committee and, with the consent of the committee, coordinate and gather from members of management information with which to advise the committee.
Ultimately, decisions about the amount and form of executive compensation, except for that of our chief executive officer whose compensation is approved by our board of directors, are made by the compensation committee alone and may reflect factors and considerations other than the information and advice provided by our compensation consultants or management.
Competitive Analysis in 2016
During 2016, the compensation consultants reviewed the compensation of NEOs at other public companies of similar size and character to better understand how our compensation compares to our peers with whom we compete for talent. The consultants also reviewed compensation surveys such as those produced by Equilar and Mercer to better understand the compensation marketplace for the industry in which we operate.

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2016 Primary Elements of Compensation
The 2016 compensation program for our NEOs consisted of a number of elements that support our performance and retention objectives. The compensation earned under certain components may vary significantly based on company performance. The following chart summarizes the main components of our 2016 executive compensation program and the primary objective of each.
Compensation Element
 
Description
 
Form
 
Objective
Base salary
 
Fixed based on level of responsibility, experience, tenure and qualifications
 
•    Cash
 
•
Support talent attraction and retention
 
 
 
 
 
 
 
Annual Incentive
Bonus
 
Variable based on the achievement of annual financial, safety and environmental metrics
 
•    Cash
 
•
Link pay and performance
•
Drive the achievement of short-term business objectives
 
 
 
 
 
 
 
Long-Term Incentive Awards
 
Variable based on the achievement of longer-term goals and stockholder value creation
 
•    Vested restricted stock subject to one-year sale restrictions
•    Vested stock options subject to one-year sale restrictions for shares acquired on exercise
 
•
Support talent attraction and retention
•
Link pay and performance
•
Drive the achievement of longer-term business objectives
•
Align NEO and stockholder interests
 
 
 
 
 
 
 
Other Compensation and Benefits Programs
 
Employee health, welfare and retirement benefits
 
•    Group medical benefits
•    Life and disability insurance
•    401(k) plan participation
 
•
Support talent attraction and retention
Internal Pay Equity
The compensation committee annually reviews the pay relationship between our CEO and our other NEOs to assess whether the differential is appropriate with regard to both the total direct compensation and each compensation element.
The following table summarizes our CEO’s 2016 total direct compensation (salary, target bonus opportunity and target long-term incentive opportunity) as a multiple of the target total direct compensation of the second most highly paid NEO and the average target total direct compensation of our other NEOs.
CEO Compensation as a Multiple of:
2016 Base
Salary
 
2016 Target
Bonus
 
2016 Target
Long-Term
Incentive
Opportunity
 
2016 Total
Direct
Compensation
Second Highest Paid NEO
2.09x
 
2.61x
 
5.00x
 
2.64x
Average of NEOs other than the CEO
2.29x
 
3.23x
 
6.86x
 
3.12x

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Pay Mix
As illustrated in the chart below, approximately 65% of our CEO’s and 52% of our other NEOs’ 2016 target total direct compensation is “at risk,” with most of the compensation subject to the achievement of short- and long-term financial or operational performance objectives. The compensation breakdown shown in the chart below reflects annualized target compensation for 2016. We believe that this balance of fixed and variable compensation is consistent with the company’s executive compensation philosophy and maintains a strong link between the NEOs’ compensation and company performance, motivating executives to deliver strong business performance and, importantly, to create stockholder value.
paymixchart.jpg

Base Salary
Base salary is the fixed element of each NEOs annual cash compensation, and the foundation upon which other primary elements of compensation are based. The compensation committee awards competitive salaries in order to assist in attracting and retaining each NEO. Base salaries are reviewed by the compensation committee annually and determined with reference to the median salaries for similarly-situated executives and also each NEOs position-specific skills, tenure, experience, responsibility and performance.
For 2016, the annual base salaries of our NEOs were as follows:
Name
Base Salary
Kevin S. Crutchfield
$
1,045,000

Charles Andrew Eidson
$
500,000

Mark M. Manno
$
500,000

V. Keith Hainer
$
425,000

Gary W. Banbury
$
400,000


2016 Annual Bonuses

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The Contura Energy, Inc. Annual Incentive Bonus Plan (the “Bonus Plan” or “CIB”) provides annual cash incentives to our executive officers and other key employees to reward performance, as measured against fundamental company financial and operational goals. In establishing 2016 performance goals, the compensation committee considered the economic environment and challenges to be faced during the fiscal year. The compensation committee designed the performance goals to ensure that performance significantly in excess of the target performance goals would be rewarded with above target payout levels, up to the cap established by the compensation committee. In setting the target goals, the compensation committee sought to establish challenging but attainable goals that would motivate and reward the NEOs for strong performance without encouraging excessive risk taking.
Performance Metrics
For 2016, the compensation committee approved a mix of performance measures based on financial metrics and operational metrics, as shown in the table below. Additional information regarding the performance metrics are included in the footnotes to the table below, including reconciliation of the non-GAAP measurements to the most closely-related GAAP measurements.
The compensation committee approved the following metrics, the respective weighting of each metric and the performance thresholds for the executives’ 2016 annual bonuses under the Bonus Plan. The metrics were intended to align annual incentive compensation for 2016 with the goals and objectives set forth in the company’s business plan. If the threshold level of performance for any of our metrics is not achieved, the resulting payout as a percentage of target is 0%, and no payouts are made under the metric.
The table below sets forth the performance metrics and their respective weightings and thresholds as well as the actual achievement of each metric based on the company’s financial and operational results for the period from July 26, 2016 to December 31, 2016:
 
Metric Goals & Performance
Performance Metric
Weighting (A)
 
Threshold
(Payout - 50%)
 
Target
(Payout - 100%)
 
Maximum
(Payout - 200%)
 
Actual Performance
 
Payout as % of Target (B)
 
As % of Target Bonus Opportunity (AxB)
CIB Free Cash Flow (1)
35.00
%
 
$38.0M

 
$42.0M

 
$46.0M

 
$102.6M
 
200.00
%
 
70.00
%
CIB Cost of Coal Sales per Ton Sold (2)
25.00
%
 

$17.70

 

$16.10

 

$14.50

 
$17.14
 
67.50
%
 
16.88
%
CIB SG&A (3)
20.00
%
 
$15.0M

 
$13.5M

 
$12.0M

 
$12.0M
 
200.00
%
 
40.00
%
NFDL (4)
10.00
%
 
3.03

 
2.76

 
2.48

 
2.50
 
192.86
%
 
19.29
%
Environmental Compliance (5)
10.00
%
 
10.28

 
8.94

 
8.04

 
16.67
 
0.00
%
 
0.00
%
Total
100
%
 
 
 
 
 
 
 
 
 
 
 
146.16
%
______________
(1)
CIB Free Cash Flow was $102.56 million in 2016 under the formula previously adopted by the compensation committee and, as a result, 244.19% of the target performance goal was achieved resulting in a payout pursuant to the Free Cash Flow metric of 200% of target, the maximum payout.

CIB Free Cash Flow was calculated as follows: 2nd Half 2016 Income from continuing operations before interest expense, income tax expense, depreciation, depletion and amortization, and amortization of acquired intangibles, less interest income and income tax benefit (“EBITDA”), less capital expenditures and excluding the effect of (i) annual bonus, equity and sales related expenses, (ii) impairment of tangible and intangible assets and related charges, (iii) gains or losses associated with asset retirement obligations (“ARO”), (iv) costs, revenues, gains or losses associated with future and completed business combinations, reorganizations and/or restructuring programs, (v) litigation or claim judgments or settlement and (vi) extraordinary, unusual,

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infrequent or non-recurring items not encompassed in the above exclusions, as determined by the board of directors.

(2)
CIB Cost of Coal Sales per Ton Sold was $17.14 in 2016 under the formula previously adopted by the compensation committee and, as a result, 93.54% of the target performance goal was achieved resulting in a payout pursuant to this metric of 67.50% of target.

CIB Cost of Coal Sales per Ton Sold was calculated as follows: Budgeted weighted average 2nd Half 2016 Cost of Coal Sales per Ton Sold (based on pro-rata 2016 budgeted volumes), excluding the effect of (i) annual bonus, equity and sales related expenses, (ii) impairment of tangible and intangible assets and related charges, (iii) gains or losses associated with ARO, (iv) costs, revenues, gains or losses associated with future and completed business combinations, reorganizations and/or restructuring programs, (v) litigation or claim judgments or settlement and (vi) extraordinary, unusual, infrequent or non-recurring items not encompassed in the above exclusions, as determined by the board of directors.

(3)
CIB SG&A Expense was $12.0 million in 2016 under the formula previously adopted by the compensation committee and, as a result, 111.11% of the target performance goal was achieved resulting in a payout pursuant to the SG&A Expense metric of 200% of target, the maximum payout.

CIB SG&A Expense was calculated as follows: Budgeted 2nd Half 2016 SG&A expense, excluding the effect of (i) annual bonus and equity expenses, (ii) impairment of tangible and intangible assets and related charges, (iii) gains or losses associated with ARO, (iv) costs, revenues, gains or losses associated with future and completed business combinations, reorganizations and/or restructuring programs, (v) litigation or claim judgments or settlement, and (vi) extraordinary, unusual, infrequent or non-recurring items not encompassed in the above exclusions, as determined by the board of directors.

(4)
Non-Fatal Days Lost (“NFDL”) was 2.50 in 2016, meaning that the safety objective was achieved at 109% of the target, which resulted in a pay-out under this objective, after interpolation, of 192.86% of target. Non-Fatal Days Lost measures the average number of days each employee spends annually unable to work or able to work only in a restricted capacity due to a non-fatal injury.

NFDL is a standard established by the Mine Safety and Health Administration and is widely used by coal companies to judge their safety performance.

(5)
Environmental Compliance, which is measured by dividing the number of water quality exceedances by the number of year-to-date active outlets, was 16.67 in 2016 under the formula previously adopted by the compensation committee. Since we did not meet our threshold performance for this metric, 0.0% of the target performance goal was achieved and no payout was made pursuant to this metric.

Environmental Compliance was calculated as follows: Number of 2nd half 2016 water quality exceedances, divided by Number of 2nd half 2016 year-to-date active outlets, multiplied by 100.

Targets and Payouts for 2016
The compensation committee aims for the target amount of executives’ bonus opportunities to be at the median of competitors and industry peers. Potential 2016 bonus payouts for our NEOs ranged from 0% to 200% of the target opportunity, based on the achievement of performance metrics. The target opportunity was prorated based on the company’s results for the five-month period from July 26, 2016 to December 31, 2016, such that each NEOs adjusted target opportunity was 41.67% of his annual target opportunity. This five-month period corresponds with the portion of 2016 after the company emerged from its restructuring proceedings.
The following table sets forth the payouts earned by each NEO pursuant to the Bonus Plan for 2016. Each NEOs Annual Bonus payment equaled 146.16% of his target bonus amount, such that bonuses ranged from $182,701 to $795,512 (for our CEO).

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Officer
2016 Base
Salary
 
2016 Annual Target Bonus Opportunity (as a % of salary)
 
2016 Adjusted Target Bonus Opportunity (as a % of salary)
 
2016 Target Bonus (A)
 
2016 Actual Performance as a Percent of Target Bonus Opportunity (B)
 
2016 CIB Bonus
Kevin S. Crutchfield
$
1,045,000

 
125.00
%
 
52.08
%
 
$
544,271

 
146.16
%
 
$
795,512

Charles Andrew Eidson
$
500,000

 
100.00
%
 
41.67
%
 
$
208,333

 
146.16
%
 
$
304,502

Mark M. Manno
$
500,000

 
100.00
%
 
41.67
%
 
$
208,333

 
146.16
%
 
$
304,502

V. Keith Hainer
$
425,000

 
75.00
%
 
31.25
%
 
$
132,813

 
146.16
%
 
$
194,120

Gary W. Banbury
$
400,000

 
75.00
%
 
31.25
%
 
$
125,000

 
146.16
%
 
$
182,701

Long-Term Incentive Awards
In 2016, the company adopted the Contura Energy, Inc. Management Incentive Plan (the “MIP”) under which grants of restricted stock and stock options to its NEOs and other executives and key employees have been or will be made totaling 10% of the company’s equity on a fully-diluted basis. Awards made pursuant to the MIP were granted in two installments — the first in July, 2016 and the second in March, 2017 — each comprising approximately half of the MIP’s total share pool. The entire share pool under the MIP will be allocated as of the date of this offering, except to the extent any award is forfeited, canceled or expires and such shares are returned to the pool for possible regrant.
The initial MIP awards were granted on July 26, 2016, the date of Alpha’s emergence from bankruptcy. These grants consisted of 50% restricted stock and 50% incentive stock options, and were granted primarily to link our NEOs’ compensation to future stock price performance and to establish the NEOs’ stock ownership in the company. The restricted stock awards vested on the date of grant, however these shares are prohibited from being sold within one year of the grant date. The incentive stock option awards were comprised of two tranches, the first with a $2.50 exercise price (which was the fair market value of a share of our common stock on the grant date), and the second with a $5.00 exercise price (the trailing volume-weighted average price for the 30-day period following the grant date, but in any case not less than $2.50 or more than $5.00). The stock option awards vested on the date of grant and can be exercised at the NEOs discretion, however, the common shares acquired on exercise are prohibited from being sold within one year of the grant date.
A second round of equity awards pursuant to the MIP was made on March 7, 2017. These awards were granted approximately 23% in the form of non-qualified stock options with a $66.13 exercise price and approximately 77% in the form of restricted stock and are scheduled to vest one-third on each of the first, second and third anniversaries of the grant date, subject to the employee’s continued employment through the applicable vesting date. All awards will fully vest in connection with a change in control of the company or an initial public offering, which includes this offering.
The number of common shares underlying equity awards granted to our NEOs is summarized in the following table.

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Officer
2016 Shares of Restricted Stock 
 
2016 Incentive Stock Options
($2.50 Exercise Price)
 
2016 Incentive Stock Options
($5.00 Exercise Price)
 
Total Number of Shares Subject to 2016 Long-Term Incentive Award
 
2017 Shares of Restricted Stock
 
2017 Non-Qualified Stock Options ($66.13 Exercise Price)
 
Total
Number of Shares Subject to 2017 Long-Term Incentive Award
Kevin S. Crutchfield
150,150

 
75,075

 
75,075

 
300,300

 
223,125

 
67,445

 
290,570

Charles Andrew Eidson
30,030

 
15,015

 
15,015

 
60,060

 
44,591

 
13,479

 
58,070

Mark M. Manno
30,030

 
15,015

 
15,015

 
60,060

 
44,591

 
13,479

 
58,070

V. Keith Hainer
16,514

 
8,258

 
8,258

 
33,030

 
15,000

 
4,384

 
19,384

Gary W. Banbury
18,018

 
—

 
—

 
18,018

 
13,365

 
4,040

 
17,405

Deferred Compensation
Our NEOs are eligible to participate in the Contura Energy, Inc. Deferred Compensation Plan (the “Deferred Compensation Plan”) which permits certain of our highly-compensated employees to receive supplemental retirement benefits in excess of the tax-qualified plan limits under the Code. The Deferred Compensation Plan is designed to further the interests of our shareholders by helping us attract and retain key talent by providing them with these additional retirement benefits. Under the Deferred Compensation Plan, the company maintains a supplemental retirement account for each participant to which the company credits annual contributions equal to the sum of (i) the participant’s compensation that is in excess of the federal tax-qualified plan limit under Section 401(a)(17) of the Code multiplied by the aggregate matching company contribution percentage for our tax-qualified retirement plans in effect for the applicable year, plus, in the discretion of our compensation committee, (ii) a discretionary contribution in an amount equal to a percentage of the participant’s eligible compensation under our tax-qualified plans. The Deferred Compensation Plan is described in further detail in “—Deferred Compensation Plan” below.
Severance and Change in Control Arrangements
We have entered into an employment agreement with our CEO which is intended to retain and competitively compensate him for his position with the company and provide severance benefits on specified terminations of employment. Our other NEOs are participants in our Key Employee Separation Plan, which provides participants with severance benefits following a qualifying termination of employment and enhanced benefits in connection with a change in control. The terms and estimated amounts of these benefits are described below under “—Chief Executive Officer” and “—Key Employee Separation Plan.”
The compensation committee believes these change in control and termination provisions are necessary to ensure that the actions and recommendations of senior management and other employees with respect to change in control transactions are in Contura’s and our stockholders’ best interests, and to reduce the distraction regarding the impact of such a transaction on the employment status of an NEO. These programs were reviewed by our board who concluded that the terms of these programs were in line with market practices.
The CEO’s employment agreement and the Key Employee Separation Plan do not provide for payment to cover “golden parachute” excise taxes imposed under Section 4999 of the Code. Rather, payments due in connection with a change of control to participants will be reduced to the extent necessary to avoid the excise tax, unless it is determined that the net after-tax benefits to a participant would be greater if the reductions were not imposed (i.e., “best net” treatment).
Retirement and Other Benefits
Our NEOs are eligible to participate in our employee benefit plans provided to other employees, including health and welfare benefits and the company’s 401(k) plan.

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Tax and Accounting Considerations
We recognize a charge to earnings for accounting purposes for equity awards over their vesting period. In the past, we have not considered the accounting impact as a material factor in determining the equity award amounts for our executive officers. However, as we become a public company, we expect that the compensation committee will consider the accounting impact of equity awards in addition to considering the impact to dilution and overhang when deciding the amounts and terms of equity grants.
We do not require executive compensation to be tax deductible for our company, but instead balance the cost and benefits of tax deductibility to comply with our executive compensation goals. For example, Section 162(m) of the Code generally disallows a tax deduction to a publicly held corporation for compensation in excess of $1 million paid in any taxable year to its chief executive officer and certain other executive officers unless the compensation qualifies as “performance-based compensation” within the meaning of the Code. As a private company, we have not been subject to the deductibility limit of Section 162(m), and have not taken such limit into consideration in setting compensation for our executive officers because Section 162(m) did not apply to us. Once we are a public company (and, with respect to Section 162(m), following the expiration of a transition period for newly public companies), we expect that the compensation committee will consider the tax deductibility of compensation, but will be fully authorized to approve compensation that is not tax deductible when it believes that such payments are appropriate to attract and retain executive talent.
Risk Assessment of Compensation Programs
While we do not expect that our compensation programs create risks that are reasonably likely to have a material adverse effect on the company, our compensation committee expects to conduct a risk assessment of our compensation programs prior to the effective date of this offering.
2016 Summary Compensation Table
The following summary compensation table sets forth information concerning the compensation of Kevin S. Crutchfield, our CEO, Charles Andrew Eidson, our Chief Financial Officer, and our other three most highly compensated executive officers for the fiscal year ended December 31, 2016 (Mark M. Manno, V. Keith Hainer and Gary W. Banbury).
Name and Principal Position
Fiscal Year
 
Salary (1)
 
Bonus
 
Stock Awards (2)
 
Option Awards (3)
 
Non-Equity Incentive Plan Compensation (4)
 
Change in Pension Value and Non-qualified Deferred Compensation Earnings
 
All Other Compensation
 
Total
Kevin S. Crutchfield
Chief Executive Officer
2016
 
$
438,096

 
$
—

 
$
375,375

 
$
238,739

 
$
795,512

 
$
—

 
$
—

 
$
1,847,722

Charles Andrew Eidson
Chief Financial Officer
2016
 
209,615

 
—

 
75,075

 
47,748

 
304,502

 
—

 
—

 
636,940

Mark M. Manno
Executive Vice President, General Counsel, Secretary and Chief Procurement Officer
2016
 
209,615

 
—

 
75,075

 
47,748

 
304,502

 
—

 
—

 
636,940

V. Keith Hainer
Executive Vice President, Chief Operating Officer
2016
 
178,173

 
—

 
41,285

 
26,260

 
194,210

 
—

 
—

 
439,928

Gary W. Banbury
Executive Vice President, Chief Administrative Officer
2016
 
167,692

 
—

 
45,045

 
—

 
182,701

 
—

 
—

 
395,438

______________
(1)
The values set forth in this column for Messrs. Crutchfield, Eidson, Manno, Hainer and Banbury represent the salaries paid for the period of July 26, 2016 to December 31, 2016. The annual base salaries for Messrs.

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Crutchfield, Eidson, Manno, Hainer and Banbury are $1,045,000, $500,000, $500,000, $425,000 and $400,000, respectively.
(2)
The values set forth in this column reflect the aggregate grant date fair value of awards computed in accordance with FASB ASC Topic 718. The restricted stock awards set forth in this column were granted with a grant date fair market value of $2.50 per share.
(3)
The values set forth in this column reflect the aggregate grant date fair value of awards computed in accordance with FASB ASC Topic 718. The options set forth in this column were granted on July 26, 2016 in two tranches. The first had an exercise price of $2.50, which was the fair market value of a share of our common stock on the grant date. The company elected to grant the second tranche of options with an exercise price that was no less than, but potentially in excess of (subject to a cap), the fair market value of a share of our common stock on the grant date. The exercise price of the second tranche of options was $5.00, which was calculated based on the trailing volume-weighted average price for the 30-day period following the grant date (but not to exceed $5.00). Each option in these tranches has a grant date fair value, computed in accordance with FASB ASC Topic 718, of $1.67 and $1.51, respectively.
(4)
The values set forth in this column represent annual bonuses earned in respect of 2016 based on performance against metrics described in “—Targets and Payouts for 2016.”

2016 Grants of Plan-Based Awards
The following table sets forth information concerning grants of plan-based awards made to our named executive officers during the fiscal year ended December 31, 2016.
 
 
 
Option Awards
 
Stock Awards
 
 
 
Estimated Future Payouts Under Non-Equity Incentive Plan Awards (1) (2)
 
Estimated Future Payouts Under Equity Incentive Plan Awards
 
All Other Stock Awards: Number of Shares of Stock or Units (#) (3)
 
All Other Option Awards: Number of Securities Underlying Options
(#) (4)
 
Exercise or Base Price of Option Awards
($/Sh)
 
Grant Date Fair Value of Stock and Option Awards (5)
Name
Grant Date
 
Minimum
 
Target
 
Maximum
 
Minimum
 
Target
 
Maximum
 
Kevin S. Crutchfield
—

 
$
272,136

 
$
544,271

 
$
1,088,542

 
—

 
—

 
—

 
—

 
 
 
$
—
 
$
—

 
7/26/2016 (4)

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
75,075
 
 
2.50
 
125,375

 
7/26/2016 (4)

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
75,075
 
 
5.00 (6)
 
113,363

 
7/26/2016 (3)

 
—

 
—

 
—

 
—

 
—

 
—

 
150,150

 
 
 
 
—
 
375,375

Charles Andrew Eidson
—

 
104,167

 
208,333

 
416,666

 
—

 
—

 
—

 
—

 
 
 
 
—
 
—

 
7/26/2016 (4)

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
15,015
 
 
2.50
 
25,075

 
7/26/2016 (4)

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
15,015
 
 
5.00 (6)
 
22,673

 
7/26/2016 (3)

 
—

 
—

 
—

 
—

 
—

 
—

 
30,030

 
 
 
 
—
 
75,075

Mark M. Manno
—

 
104,167

 
208,333

 
416,666

 
—

 
—

 
—

 
—

 
 
 
 
—
 
—

 
7/26/2016 (4)

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
15,015
 
 
2.50
 
25,075

 
7/26/2016 (4)

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
15,015
 
 
5.00 (6)
 
22,673

 
7/26/2016 (3)

 
—

 
—

 
—

 
—

 
—

 
—

 
30,030

 
 
 
 
—
 
75,075

V. Keith Hainer
—

 
66,407

 
132,813

 
265,626

 
—

 
—

 
—

 
—

 
 
 
 
—
 
—

 
7/26/2016 (4)

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
8,258
 
 
2.50
 
13,791

 
7/26/2016 (4)

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
8,258
 
 
5.00 (6)
 
12,470

 
7/26/2016 (3)

 
—

 
—

 
—

 
—

 
—

 
—

 
16,514

 
 
 
 
—
 
41,285

Gary W. Banbury
—

 
62,500

 
125,000

 
250,000

 
—

 
—

 
—

 
—

 
 
 
 
—
 
—

 
7/26/2016 (3)

 
—

 
—

 
—

 
—

 
—

 
—

 
18,018

 
 
 
 
—
 
45,045

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
_____________
(1)
The amounts in this column reflect annual bonuses that were eligible to be earned in respect of performance in 2016.

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(2)
The amounts in the threshold, target and maximum columns were adjusted for 2016 to reflect the performance period of July 26, 2016 to December 31, 2016. The target annual bonus amounts for Messrs. Crutchfield, Eidson, Manno, Hainer and Banbury are $1,306,250, $500,000, $500,000, $318,750 and $300,000, respectively, with the threshold and maximum columns representing 50% and 200%, respectively, of the target amounts.
(3)
Represents a restricted stock award granted on July 26, 2016 under the Contura Energy, Inc. Management Incentive Plan.
(4)
Represents a stock option award granted on July 26, 2016 under the Contura Energy, Inc. Management Incentive Plan.
(5)
The grant date fair value calculations are computed in accordance with FASB ASC Topic 718.
(6)
Represents a stock option award granted on July 26, 2016 under the Contura Energy, Inc. Management Incentive Plan with an exercise price equal to the trailing volume-weighted average price over the 30-day period following the date of grant, subject to a maximum exercise price of $5.00, as specified in the applicable award agreement.
Outstanding Equity Awards at 2016 Fiscal Year End
The following table summarizes the number of shares of common stock underlying outstanding equity incentive plan awards for each named executive officer as of December 31, 2016.
Name
Numbers of Securities Underlying Unexercised Options (#) Exercisable (1)
 
Option Exercise Price
 
Option Expiration Date
 


Number of Shares or Units of Stock That Have Not Vested (#)
 

Market Value of Shares or Units of Stock That Have Not Vested
 
Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)
 
Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
Kevin S. Crutchfield
75,075

 
$
2.50

 
7/26/2026

 
—

 
$
—

 
—

 
$
—

 
75,075

 
5.00

 
7/26/2026

 
—

 
—

 
—

 
—

Charles Andrew Eidson
15,015

 
2.50

 
7/26/2026

 
—

 
—

 
—

 
—

 
15,015

 
5.00

 
7/26/2026

 
—

 
—

 
—

 
—

Mark M. Manno
15,015

 
2.50

 
7/26/2026

 
—

 
—

 
—

 
—

 
15,015

 
5.00

 
7/26/2026

 
—

 
—

 
—

 
—

V. Keith Hainer
8,258

 
2.50

 
7/26/2026

 
—

 
—

 
—

 
—

 
8,258

 
5.00

 
7/26/2026

 
—

 
—

 
—

 
—

Gary W. Banbury
—

 
—

 
—

 
—

 
—

 
—

 
—

______________
(1)
All options in this column were fully vested at grant.
Option Exercises and Stock Vested in 2016
The following table shows information regarding options that were exercised by and the vesting of stock for our named executive officers during the fiscal year ended December 31, 2016.

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Option Awards
 
Stock Awards
Name
Numbers of Shares
Acquired on Exercise (#)
 
Value Realized on Exercise
 
Number of Shares Acquired on Vesting (#)
 

Value Realized on Vesting (1)
Kevin S. Crutchfield
—

 
$
—

 
150,150
 
$
375,375

Charles Andrew Eidson
—

 
—

 
30,030
 
75,075

Mark M. Manno
—

 
—

 
30,030
 
75,075

V. Keith Hainer
—

 
—

 
16,514
 
41,285

Gary W. Banbury
—

 
—

 
18,018
 
45,045

______________
(1)
The value realized upon vesting was determined by multiplying the number of shares by the fair value per share of our common stock on the vesting date of July 26, 2016.
Potential Payments on Termination and Change in Control
Each of our NEOs may be eligible to receive benefits under the circumstances described below if the officer experiences a qualifying termination of employment or we undergo a change in control.
Chief Executive Officer
Under the terms of his July 26, 2016 Employment Agreement, Mr. Crutchfield will serve as the company’s Chief Executive Officer until December 31, 2017, and this term will automatically renew for successive 12-month periods unless terminated by either party with 90 days’ written notice. Mr. Crutchfield’s annual base salary is $1,045,000 and his annual target bonus opportunity is 125% of base salary, subject to any applicable performance criteria.
If Mr. Crutchfield is terminated without cause (which includes his gross negligence or willful misconduct in the performance of his duties, conviction of a felony, material violation of our code of ethics or material breach of his employment agreement) or resigns for good reason (which includes a material reduction in his salary or target bonus opportunity, our failure to allow him to participate in our equity-based compensation plans, a material diminution in his position or duties, or a material relocation), he will be entitled to receive the following severance benefits, subject to his execution of a release of claims:
•
a lump sum cash payment equal to two times base salary plus two times target annual bonus for the year in which the termination occurs;
•
vesting of all equity awards (with stock options remaining exercisable for up to two years post- termination); and
•
reimbursement by us for up to 18 months of Consolidated Omnibus Budget Reconciliation Act (COBRA) health and dental insurance premiums and life insurance premiums for him and his dependents.
If Mr. Crutchfield is terminated without cause or resigns for good reason during the period beginning three months prior to and ending twelve months following a change in control (as defined in the agreement), he will be entitled to receive the following enhanced severance benefits:
•
a lump sum cash payment equal to two and one-half times base salary plus two and one-half times annual target bonus for the year in which the termination occurs;
•
vesting of all equity awards (with stock options remaining exercisable for up to two years post-termination);

148



•
a lump sum cash payment of the pro rata share of his annual bonus for the year of termination;
•
a lump sum cash payment of $15,000 to cover the cost of outplacement services; and
•
reimbursement by us for up to 18 months of COBRA health insurance premiums and dental and life insurance premiums for him and his dependents.
If Mr. Crutchfield’s employment is terminated due to death or disability, he will be entitled to receive a prorated target bonus for the year of termination.
Upon a termination of his employment, Mr. Crutchfield is subject to restrictive covenants regarding confidentiality (perpetual), non-competition (during employment and for one year thereafter), and employee and customer non-solicitation (during employment and for one year thereafter). If Mr. Crutchfield resigns for any reason other than for good reason or if he elects not to renew the term of his employment agreement, we may only invoke his non-competition and non-solicitation covenants if we agree to pay him a cash payment equal to two and one-half times base salary plus two and one-half times annual target bonus for the year in which the termination occurs.
Key Employee Separation Plan
Our NEOs, other than our CEO, are eligible to receive severance benefits under the Contura Energy, Inc. Key Employee Separation Plan (the “KESP”), which was approved by our board of directors on July 26, 2016.
The KESP provides that, following a change in control (as defined in the plan), each participant will receive a bonus for the year in which the change in control occurs, prorated through the date of the change in control.
If a participant’s employment is terminated by the company for any reason other than cause, death or disability, or if the participant resigns for good reason (all as defined in the KESP), during the period beginning three months prior to and ending one year following a change in control of the company, the participant will be entitled to receive (i) a cash payment equal to the sum of base salary and target bonus for the year of termination, multiplied by a factor of 2x under the terms of the KESP (the “Severance Multiple”), (ii) an annual cash incentive bonus for the year of termination, prorated through the termination date, (iii) a cash payment of $15,000 for outplacement services, and (iv) continued COBRA coverage for a period of up to 18 months (the “Severance Benefits”). If a participant is terminated prior to the 90-day period immediately preceding a change in control for any reason other than cause, death or disability, the participant will be eligible to receive the Severance Benefits, except the Severance Multiple will be 1.5x, as provided by the terms of the KESP.
In the event a participant experiences a termination of employment under any of the circumstances described in the preceding paragraph, whether prior to or during the change in control period, any outstanding stock options or restricted stock will become fully vested on the date of termination. All options will remain exercisable for a period of up to one year following the termination.
Participants are required to execute a general release, non-disparagement and non-competition agreement as a condition to receiving the Severance Benefits, which includes restrictive covenants regarding confidentiality (perpetual), non-competition (for one year post-termination), employee and customer non-solicitation (for one year post-termination) and non-disparagement (perpetual).
The following table sets forth information concerning the change in control and severance payments to be made to each of our NEOs in connection with a change in control or termination of employment, presuming a termination or change in control date of December 31, 2016. Additional descriptions of the terms of our agreements, plans and arrangements with our NEOs are set forth above in “—Compensation Discussion and Analysis.”
The payments and benefits detailed in the tables below are in addition to any payments and benefits under our plans or arrangements which are offered or provided generally to all salaried employees on a non-discriminatory

149



basis and any accumulated vested benefits for each NEO, and any stock options vested as of December 31, 2016 (which are set forth in the Outstanding Equity Awards at Fiscal Year-End Table).
Name
Termination Without Cause or for Good Reason (Not in Connection with a Change in Control) (1)
 
Termination Without Cause or for Good Reason in Connection with a Change in Control (1)
 
Death
Kevin S. Crutchfield
$
4,742,767
 
$
7,239,642
 
$
1,306,250

Charles Andrew Eidson
2,051,217(2)
 
3,051,217(3)
 
—
 
Mark M. Manno
2,051,217(2)
 
3,051,217(3)
 
—
 
V. Keith Hainer
1,484,985(2)
 
2,175,610(3)
 
—
 
Gary W. Banbury
1,400,407(2)
 
2,050,407(3)
 
—
 
______________
(1)
The amounts reflected in these columns include the cash payments described under “Chief Executive Officer” and “Key Employee Separation Plan” above. Payments for continued health and welfare benefits assume a cost of approximately $1,787 per month in medical and dental insurance based on 2016 COBRA rates and $450 per month in life and accidental death & dismemberment insurance premiums.
(2)
These amounts include payment for the sum of base salary and 2016 target bonus with a Severance Multiple of 1.5.
(3)
These amounts include payment for the sum of base salary and 2016 target bonus with a Severance Multiple of 2.
Employee Benefit Plans
2017 Long-Term Incentive Plan
We expect that our 2017 Long-Term Incentive Plan (the “2017 Plan”) will become effective in connection with this offering. The 2017 Plan provides for the grant of equity-based awards to our employees, consultants, service providers and non-employee directors.
Administration. The 2017 Plan will be administered by our compensation committee, which will have the authority to determine eligible participants, the types of awards to be granted, the number of shares covered by any awards, the terms and conditions of any awards (and amend any terms and conditions), and the methods by which awards may be settled, exercised, cancelled, forfeited or suspended.
Shares Reserve; Adjustments. The maximum number of shares available for issuance under the 2017 Plan will not exceed          . The share pool will be increased on the first day of each year by the percentage of shares outstanding on the last day of the prior year (or by a lower number determined by our board of directors in its discretion). Any shares underlying awards that are forfeited, cancelled, expired, terminated or are otherwise lapsed, in whole or in part, or are settled in cash or withheld by us in respect of taxes, will become available for future grant under our 2017 Plan.
In the event of certain changes in our corporate structure, including any extraordinary dividend or other distribution, recapitalization, stock split, reorganization, merger, consolidation, spin-off, or other similar corporate transaction or event affecting our common stock, or changes in applicable laws, regulations or accounting principles, the compensation committee will make appropriate adjustments to prevent undue enrichment or harm to the number and type of common shares subject to awards, and to the grant, purchase, exercise or hurdle price for any award.
Individual Award Limits. Under the 2017 Plan, in any one fiscal year, participants may not receive grants of stock options or stock appreciation rights for more than          shares of our common stock. To the extent that awards under the 2017 Plan are intended to qualify as “qualified performance-based compensation” under Section 162(m) of the Code, participants may not receive grants in any one fiscal year of (i) restricted stock units, restricted stock,

150



performance awards or other stock-based awards for more than the greater of          shares of our common stock or shares of our common stock with an aggregate fair market value of $          , and (ii) performance awards or other cash-based awards for more than $          .
Non-Employee Director Limits. Under the 2017 Plan, in any one fiscal year, non-employee Directors may not be granted (i) awards of more than           shares of our common stock (or if greater, in the case of restricted stock units, restricted stock performance awards and other stock-based awards, shares of our common stock with an aggregate fair market value of $          ) or (ii) awards denominated in cash of more than $          .
Stock Options. The 2017 Plan permits the grant of incentive stock options to employees and/or nonstatutory stock options to all eligible participants. The exercise price of stock options may not be less than the fair market value of our common stock on the grant date, provided that if an incentive stock option is granted to a 10% shareholder, the exercise price may not be less than 110% of the fair market value of our common stock. Each stock option agreement will set forth the vesting schedule of the options and the term of the options, which may not exceed 10 years (or five years in the case of an incentive stock option granted to a 10% shareholder). The compensation committee will determine the method of payment of the exercise price.
Stock Appreciation Rights. The 2017 Plan permits the grant of stock appreciation rights, which entitle the holder to receive shares of our common stock or cash having an aggregate value equal to the appreciation in the fair market value of our common stock between the grant date and the exercise date, times the number of shares subject to the award. The exercise price of stock appreciation rights may not be less than the fair market value of our common stock on the date of grant. Each stock appreciation rights agreement will set forth the vesting schedule of the stock appreciation rights.
Restricted Stock and Restricted Stock Units. The 2017 Plan permits the grant of restricted stock and restricted stock units. Restricted stock awards are grants of shares of our common stock, subject to certain condition and restrictions as specified in the applicable award agreement. Restricted stock units represent the right to receive shares of our common stock (or a cash amount equal to the value of our common stock) on future specified dates.
Performance Awards. The 2017 Plan permits the grant of performance awards which are payable upon the achievement of performance goals determined by the compensation committee. The compensation committee may, in its discretion, add restrictions or conditions to the receipt of payment under a performance award.
Other Cash-Based Awards and Other Stock-Based Awards. The 2017 Plan permits the grant of other cash-based and other stock-based awards, the terms and conditions of which will be determined by the compensation committee and specified in the applicable award agreement.
Separation from Service. In the event of a participant’s separation from service, as defined in the 2017 Plan, the compensation committee may determine the extent to which an award may be exercised, settled, vested, paid or forfeited prior to the end of a performance period, or the vesting, exercise or settlement of such award.
Change in Control. In the event of a change in control, as defined in the 2017 Plan, the compensation committee may take certain actions with respect to outstanding awards, including the continuation or assumption of awards, substitution or replacement of awards by a successor entity, acceleration of vesting and lapse of restrictions, determination of the attainment of performance conditions for performance awards or cancellation of awards in consideration of a payment.
No Repricing. Except pursuant to an adjustment by the compensation committee permitted under the 2017 Plan, no action may directly or indirectly reduce the exercise or hurdle price of any award established at the time of grant without shareholder approval.
Plan Amendment or Suspension. The compensation committee has the authority to amend or suspend the 2017 Plan, provided that no such action may be taken without shareholder approval if the approval is necessary to comply with a tax or regulatory requirement or other applicable law for which the compensation committee deems it

151



necessary or desirable to comply. No amendment may in general adversely and materially affect a participant’s rights under any award without such participant’s written consent.
Term of the Plan. No awards may be granted under the 2017 Plan after our board of directors terminates the plan or 10 years from the effective date, whichever is earlier.
Management Incentive Plan
We granted awards in the form of restricted stock units, restricted stock and stock options (see “—2016 Long-Term Incentive Awards”) pursuant to our Contura Energy, Inc. Management Incentive Plan (the “MIP”) in 2016 and 2017. Prior to the date of this offering, it is anticipated that the MIP’s entire share pool will be allocated, except to the extent any award is forfeited, cancelled or expires and such shares are returned to the pool for possible regrant. All awards granted under the MIP will vest in connection with this offering.
Administration. The MIP is administered by our compensation committee, which has the authority to take a number of actions with respect to the MIP, including determining the individuals eligible for awards, the types of awards, the terms and conditions applicable to awards and to modify, amend, cancel or suspend awards.
Shares Subject to the Plan; Adjustments. As of the date of this offering, it is anticipated that no shares of our common stock will remain available for future issuance pursuant to awards granted under the MIP. In the event of certain changes in our corporate structure, including a stock split, stock dividend, recapitalization, spin-off, merger, reorganization or extraordinary cash dividend, our compensation committee will make appropriate adjustments to prevent dilution or enlargement of the benefits intended to be made under the MIP.
Stock Options. Incentive and non-qualified stock options have been granted under the MIP. Following a termination of employment, non-qualified options may be exercised, to the extent vested as of the date of termination (or to the extent vested pursuant to the terms of the KESP or under a participant’s employment agreement, as applicable), for three months following termination (or pursuant to the terms of the KESP or under a participant’s employment agreement, as applicable). Incentive stock options may be exercised, to the extent vested upon a participant’s termination of employment, for three months following termination, provided that, in the case of certain of the option grants, if the termination is by the company without cause or by the participant for good reason (both as defined in the MIP), or due to the participant’s death or disability, vested options are exercisable until either the fourth anniversary of the grant date or the second anniversary of the termination, whichever is later (but in no case later than the expiration date).
Restricted Shares and Restricted Stock Units. Restricted shares and restricted stock units have been granted under the MIP. Restricted shares, which were granted to our NEOs and to other key employees in two installments, vest and become non-forfeitable as set forth in the applicable award agreement, subject to the recipient’s continued employment with us. The first installment of restricted share awards vested on the date of grant and the second installment will vest ratably over a three-year period. Upon a participant’s termination of employment, all unvested restricted shares are immediately forfeited (except as otherwise provided in the participant’s employment agreement or in the KESP). Restricted stock units were granted to non-employee directors and are scheduled to fully vest on the day before the first anniversary of the grant date, subject to the director’s continued service with us. All unvested restricted stock units are immediately forfeited upon a director’s termination of service.
Change-in-Control. Upon a change in control of the company or an initial public offering (including this offering), all awards granted under the MIP will vest. In the event of certain corporate transactions specified in the MIP, including a merger, consolidation, sale of all or substantially all of our assets, or an initial public offering, the compensation committee may take any action it deems necessary with respect to outstanding equity awards, including providing for the assumption of awards, or the cashing-out awards.
Amendments, Suspensions or Termination. Our board of directors may suspend or terminate the MIP at any time and may amend the MIP from time to time. Amendments, suspensions or terminations must be approved by our shareholders if such approval is necessary to comply with tax or regulatory requirements that our board deems it

152



necessary or desirable to comply. The MIP may not be amended if the effect of the amendment is to reduce the benefits of the awards granted pursuant to the second installment of awards in March 2017. According to its terms, the MIP will automatically terminate in 2026, unless earlier terminated.
Annual Incentive Bonus Plan
The company has adopted an Annual Incentive Bonus Plan, (the “Bonus Plan”) in which our officers and key employees are eligible to participate. The Bonus Plan is designed to advance the interests of our shareholders by providing incentives to employees to achieve performance goals critical to the success and growth of our company.
The maximum amount that may be awarded under the Bonus Plan to a participant in any one year is $15 million.
Under the Bonus Plan, the compensation committee has full authority to make awards and to establish the terms of such awards, including performance goals and performance measures used. Awards under the Bonus Plan may be based on a percentage of an employee’s base salary or expressed in another way. The compensation committee has the authority to reduce awards if it concludes that doing so is necessary or appropriate under the circumstances.
If a participant in the Bonus Plan is involuntarily terminated (other than for cause, as defined in the participant’s employment agreement or, in the absence of an employment agreement, as defined in any applicable company plans or employment policies in effect at the time of the termination) during the period beginning three months prior to and ending one year following a change of control of the company (as defined in the Bonus Plan), Bonus Plan awards will be deemed fully earned at the target level. If a participant separates from service for any other reason prior to the end of a performance period, the award will be forfeited and the participant will not be entitled to any cash payment for the applicable performance period.
If we determine that a participant engaged either in intentional misconduct which caused the need for a restatement of our financial results or in ethical misconduct in violation of our code of business ethics, we may require the participant to pay back any cash compensation previously paid under the Bonus Plan.
Each year, the compensation committee approves performance measures or metrics upon which awards may be paid out under the Bonus Plan. In 2016, the compensation committee approved the following metrics, as discussed more fully in “—Performance Metrics”: Free Cash Flow, Cost of Coal Sales per Ton Sold, SG&A Expense, NFDL and Environmental Compliance. In January 2017, the compensation committee narrowed the metrics under the Bonus Program to the following: EBITDA (40%), Cost of Coal Sales per Ton Sold (30%), NFDL (20%) and Environmental Compliance (10%).
Deferred Compensation Plan
The company approved the Contura Energy, Inc. Deferred Compensation Plan (the “Deferred Compensation Plan”) to permit certain of our highly-compensated employees to receive supplemental retirement benefits in excess of the tax-qualified plan limits under the Code. The Deferred Compensation Plan is designed to further the interests of our shareholders by helping us attract and retain key talent by providing them with these additional retirement benefits.
Under the Deferred Compensation Plan, our CEO and Chief Accounting Officer may designate those key employees who are eligible to participate in the Deferred Compensation Plan. The compensation committee has the authority to approve designated participants before they may participate in the plan, unless the compensation committee delegates such authority to an executive officer. The company maintains a supplemental retirement account for each participant to which the company credits annual contributions equal to the sum of (i) the participant’s compensation that is in excess of the federal tax-qualified plan limit under Section 401(a)(17) of the Code multiplied by the aggregate matching company contribution percentage for our tax-qualified retirement plans in effect for the applicable year, plus, in the discretion of our compensation committee, (ii) a discretionary

153



contribution in an amount equal to a percentage of the participant’s eligible compensation under our tax-qualified plans.
Upon a participant’s termination of employment without cause or by the participant for good reason, involuntary termination in connection with a change in control (as determined by the company in its discretion prior to the change in control) or due to death or disability (all as defined in the participant’s employment agreement or under the 2017 Plan, as applicable), the participant will receive a prorated discretionary contribution credit as of December 31st of the year in which the termination occurred. All contributions made to participant accounts are fully vested when credited.
The company may amend, modify or suspend the Deferred Compensation Plan in its discretion, provided that any such amendment, modification or suspension does not reduce the accrued benefit of any participant in the plan (unless such modification or amendment is for the purpose of bringing the plan into compliance with Section 409A of the Code).

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PRINCIPAL AND SELLING STOCKHOLDERS
The following table and accompanying footnotes show information regarding the beneficial ownership of our common stock before and after this offering, for:
•
each of the selling stockholders;
•
each person who is known by us to own beneficially more than 5% of our common stock;
•
each member of our board of directors and each of our named executive officers; and
•
all members of our board of directors and our executive officers as a group.
All information with respect to beneficial ownership has been furnished by the respective 5% or more stockholders, selling stockholders, directors or named executive officers, as the case may be.
The number of shares outstanding and percentage of beneficial ownership before the offering set forth below is based on the number of shares of our common stock to be issued and outstanding immediately prior to the effectiveness of the registration statement of which this prospectus is a part. The number of shares and percentage of beneficial ownership after the offering set forth below is based on shares of our common stock to be issued and outstanding immediately after this offering.
To the extent the underwriters sell more than           shares of common stock, the underwriters have the option for a period of 30 days after the date of this prospectus to purchase up to an additional           shares from the selling stockholders.

155



 
 
 
 
 
Shares to be Sold
In this Offering
 
Shares Beneficially Owned
After This Offering
Name and Address of
Beneficial Owner (1)
Shares Beneficially
Owned Prior to
This Offering
 
Assuming the
Underwriters’
Over-allotment
Option is
Not Exercised
 
Assuming the
Underwriters’
Over-allotment
Option is
Exercised in Full
 
Assuming the
Underwriters’
Over-allotment
Option is
Not Exercised
 
Assuming the
Underwriters’
Over-allotment
Option is
Exercised in Full
Number
 
Percent
 
Number
 
Percent
 
Number
 
Percent
 
Number
 
Percent
 
Number
 
Percent
Selling Stockholders and five percent stockholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Directors and named executive officers:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Kevin S. Crutchfield
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Charles Andrew Eidson
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mark M. Manno
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
V. Keith Hainer
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gary W. Banbury
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Albert E. Ferrara, Jr.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Neale X. Trangucci
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jonathan Segal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Directors and executive officers as a group (8 total persons)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
______________
(1)
The shares of our common stock beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares voting power, which includes the power to vote or direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage, but not for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed beneficial owner of the same securities and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. Except as otherwise indicated in these footnotes, each of the beneficial owners has, to our knowledge, sole voting and investment power with respect to the indicated shares of common stock. Unless otherwise indicated, the address for each listed beneficial owner is: 340 Martin Luther King Jr. Blvd., Bristol, Tennessee 37620.



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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Review and Approval of Related Party Transactions
Upon completion of this offering, pursuant to its written charter, our audit committee will review and, subject to certain exceptions, approve, amend, ratify, terminate or rescind, related-party transactions submitted for consideration by the company’s General Counsel, which include any related party transactions that we would be required to disclose pursuant to Item 404 of Regulation S-K promulgated by the SEC. For a discussion of the composition and responsibilities of our audit committee see “Management—Committees of the Board of Directors After this Offering—Audit Committee.” In determining whether to approve a related party transaction, the audit committee will consider a number of factors, including whether the related party transaction complies with the restrictions set forth in our debt facilities and whether it is on terms and conditions no less favorable to us than may reasonably be expected in arm’s-length transactions with unrelated parties.
Relationship with Alpha Natural Resources, Inc.
We were incorporated in the State of Delaware on June 10, 2016 and were formed to acquire and operate certain of Alpha Natural Resources, Inc.’s core coal operations, as part of Alpha’s bankruptcy restructuring. Alpha was a coal producer with operations in Central Appalachia, Northern Appalachia, and the Powder River Basin. On July 26, 2016, a consortium of former Alpha creditors acquired Contura common stock in exchange for a partial release of their creditor claims pursuant to the Alpha Restructuring settlement. We entered into various settlement agreements with Alpha and/or the Alpha bankruptcy successor ANR, Inc. and third parties as part of the Alpha Restructuring. We assumed acquisition-related obligations through those settlement agreements which became effective on July 26, 2016, the effective date of Alpha’s plan of reorganization. Contura began operations on July 26, 2016 upon Alpha’s emergence from Chapter 11 bankruptcy protection.
Transition Services Agreement
We entered into a Transition Services Agreement (the “TSA”) with Alpha Natural Resources, Inc. and ANR, Inc., dated July 26, 2016, for certain back office services and support to be provided from the date of the TSA until various dates, depending on the service. The services provided range from certain accounting, tax, benefit, payroll, legal and regulatory, IT support and other services, and their durational periods range from approximately one month to up to one year following the Closing Date.
We also entered into three amendments to the TSA, with the first being on August 26, 2016 (the “First Amendment”), the second being on October 20, 2016 (the “Second Amendment”) and the third being on February 22, 2017 (the “Third Amendment”). The First Amendment revised various mail notice provisions and bank account information, among other things. The Second Amendment provided for a thirty-day extension to the provision of certain telecommunications services. The Third Amendment extended the time period for the provision of certain services through December 31, 2017. Any future additions to services provided or extensions of service terms will be executed via further amendments to the TSA.
Contingent Credit Agreement
The Contingent Credit Support Commitment (“Contingent Commitment”) is an unsecured obligation to ANR that requires the company to provide ANR with revolving credit support in an aggregate total amount of $35,000,000 from July 26, 2016 (“Effective Date”) through September 30, 2018. ANR is entitled to draw against the Contingent Commitment if, and only if, the amount of cash and cash equivalents on ANR’s balance sheet falls below $20,000,000 at any time prior to September 30, 2018 (the amount of any such shortfall, the “Shortfall”), in which case, ANR is entitled to draw against the Contingent Commitment an amount equal to the lesser of the Shortfall and the then-remaining undrawn amount of the Contingent Commitment. ANR is able to draw upon and repay the Contingent Commitment as necessary through September 30, 2018. The company must fund a draw on the Contingent Commitment within 10 business days of notice from ANR. ANR will be required to repay the funds drawn against the Contingent Commitment (i) prior to September 30, 2018 to the extent the amount of cash and cash

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equivalents on ANR’s balance sheet is greater than $20,000,000 as of the end of any calendar quarter ending on or before September 30, 2018 (exclusive of the amount outstanding from the Contingent Commitment) or (ii) if any amounts are outstanding under the Contingent Commitment after September 30, 2018, to the extent the amount of cash and cash equivalents on ANR’s balance sheet at the end of any calendar quarter is greater than $30,000,000 (exclusive of the amount outstanding from the Contingent Commitment), within 10 business days following the closing of its books for the relevant calendar quarter. Notwithstanding the above, all outstanding balances under the Contingent Commitment must be repaid by September 30, 2019.
As of December 31, 2016, ANR had not drawn against the Contingent Commitment.
Alpha Resolution of Reclamation Obligations Agreement
Pursuant to the Reclamation Funding Agreement dated July 12, 2016, separate interest bearing segregated deposit accounts (“Restricted Cash Reclamation Accounts”) were established for certain applicable federal and state environmental regulatory authorities to provide certain funding for the reclamation, mitigation and water treatment, and certain management work to be done at reclaim-only sites related to certain obligations under the various permits associated with ANR’s retained assets.
Funding of Restricted Cash Reclamation
Pursuant to the Reclamation Funding Agreement, the company must pay the aggregate amount of $50,000,000 into the various Restricted Cash Reclamation Accounts as follows: $8,000,000 immediately upon the Effective Date; $10,000,000 on the anniversary of the Effective Date in each of 2017, 2018, and 2019; and $12,000,000 on the anniversary of the Effective Date in 2020. The initial $8,000,000 payment was paid as part of the Alpha Restructuring settlement process.
Contingent Funding of Restricted Cash Reclamation
Pursuant to the Reclamation Funding Agreement, under certain circumstances, the company will be required to pay up to an aggregate amount of $50,000,000 into various Restricted Cash Reclamation Accounts from 2021 through 2025 as follows: (1) if ANR does not contribute $50,000,000 of free cash flow, as defined in the agreement, into the Restricted Cash Reclamation Accounts through December 31, 2020; and (2) if ANR makes any reorganized ANR contingent revenue payment, as defined in the agreement, that reduces the amount of free cash flow that ANR otherwise would have contributed to the Restricted Cash Reclamation Accounts, then the company will be obligated to pay the amount of the difference between (a) the amount of free cash flow that ANR would have contributed to the Restricted Cash Reclamation Accounts had it not made such reorganized ANR contingent revenue payment and (b) the amount of free cash flow actually contributed.
Registration Rights Agreement
We and certain of our stockholders entered into a registration rights agreement in connection with the Alpha Restructuring. Pursuant to the registration rights agreement, such stockholders may, subject to various conditions and limitations, require us to file registration statements to register the resale of the shares held by such stockholders or to include their shares in registration statements that we file for ourselves or other stockholders, subject to the 180-day lock-up period described in “Shares Eligible For Future Sale—Lock-up Agreements.” We have also agreed to reimburse the parties to the registration rights agreement for certain expenses incurred in connection with the filing of any registration statement and the marketing of any securities registered pursuant to the registration rights agreement. See “Shares Eligible for Future Sale—Registration Rights.”


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DESCRIPTION OF CAPITAL STOCK
The following is a description of the material terms of our amended and restated certificate of incorporation and amended and restated bylaws as in effect as of the date hereof. We refer you to our amended and restated certificate of incorporation and amended and restated bylaws, copies of which will be filed as exhibits to the registration statement of which this prospectus forms a part.

Our authorized capital stock consists of 20,000,000 shares of common stock, par value $0.01 per share and 2,000,000 shares of preferred stock, par value $0.01 per share.
Common Stock
Common stock outstanding. As of December 31, 2016 there were 10,309,310 shares of common stock outstanding which were held of record by 62 stockholders. There will be          shares of common stock outstanding, assuming no exercise of the underwriters’ option and no exercise of outstanding options, after giving effect to the sale of the shares of common stock offered hereby. All outstanding shares of common stock are fully paid and non-assessable, and the shares of common stock to be issued upon completion of this offering will be fully paid and non-assessable.
Voting rights. The holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders.
Dividend rights. Subject to preferences that may be applicable to any outstanding preferred stock, the holders of common stock are entitled to receive ratably such dividends, if any, as may be declared from time to time by the board of directors out of funds legally available therefor. See “Dividend Policy.”
Rights upon liquidation. In the event of liquidation, dissolution or winding up of Contura, the holders of common stock are entitled to share ratably in all assets remaining after payment of liabilities, subject to prior distribution rights of preferred stock, if any, then outstanding.
Other rights. The holders of our common stock have no preemptive or conversion rights or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock.
Preferred Stock
As of December 31, 2016, there were no shares of preferred stock outstanding. Our board of directors has the authority to issue the preferred stock in one or more series and to fix the designations, powers, preferences and relative, participating, optional or other rights, if any, and the qualifications, limitations or restrictions thereof, if any, with respect to each such class or series of preferred stock and the number of shares constituting each such class or series, and to increase or decrease the number of shares of any such class or series to the extent permitted by Delaware law.
The issuance of preferred stock may have the effect of delaying, deferring or preventing a change in control of Contura without further action by the stockholders and may adversely affect the voting and other rights of the holders of common stock. At present, Contura has no plans to issue any of the preferred stock.
Warrants
On July 26, 2016, we issued 810,811 warrants pursuant to Alpha’s Plan of Reorganization. The warrants are exercisable into a maximum of 810,811 shares of common stock with an initial exercise price of $55.93 per share and are exercisable for cash or on a cashless basis at any time from July 26, 2016 until July 26, 2023.

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Registration Rights
We and certain of our stockholders entered into a registration rights agreement in connection with the Alpha Restructuring. Pursuant to the registration rights agreement, such stockholders may, subject to various conditions and limitations, require us to file registration statements to register the resale of the shares held by such stockholders or to include their shares in registration statements that we file for ourselves or other stockholders, subject to the 180-day lock-up period described in “Shares Eligible For Future Sale—Lock-up Agreements.” We have also agreed to reimburse the parties to the registration rights agreement for certain expenses incurred in connection with the filing of any registration statement and the marketing of any securities registered pursuant to the registration rights agreement. See “Shares Eligible For Future Sale—Registration Rights.”
Anti-takeover Effects of Certain Provisions of Our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws
Removal of Directors; Vacancies
Our board of directors currently consists of four directors. The exact number of directors will be fixed from time to time by resolution of the board. No director may be removed except for cause, and directors may be removed for cause by an affirmative vote of shares representing a majority of the shares then entitled to vote at an election of directors. Any vacancy occurring on the board of directors and any newly created directorship may be filled only by a majority of the remaining directors in office.
No Cumulative Voting
The Delaware General Corporation Law (“DGCL”) provides that stockholders are not entitled to the right to cumulate votes in the election of directors unless our amended and restated certificate of incorporation provides otherwise. Our amended and restated certificate of incorporation prohibits cumulative voting.
Calling of Special Meetings of Stockholders
Our amended and restated certificate of incorporation and our amended and restated bylaws provide that special meetings of our stockholders may be called only by our board of directors or the chairman of our board of directors or by our corporate secretary at the request in writing of holders of record of 20% of our outstanding capital stock entitled to vote.
Stockholder Action by Written Consent
Pursuant to Section 228 of the DGCL, any action required to be taken at any annual or special meeting of the stockholders may be taken without a meeting, without prior notice and without a vote if a consent or consents in writing, setting forth the action so taken, is signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares of our stock entitled to vote thereon were present and voted, unless our amended and restated certificate of incorporation provides otherwise. Our amended and restated certificate of incorporation allows for this.
Advance Notice Requirements for Stockholder Proposals and Director Nominations
Our amended and restated bylaws provide that stockholders seeking to nominate candidates for election as directors or to bring business before an annual meeting of stockholders must provide timely notice of their proposal in writing to our corporate secretary.
Generally, to be timely, a stockholder’s notice must be received at our principal executive offices not less than 30 days nor more than 60 days prior to the first anniversary date of the date on which the company first mailed its proxy materials for the previous year’s annual meeting. Our amended and restated bylaws also specify requirements as to the form and content of a stockholder’s notice. These provisions may impede stockholders’ ability to bring

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matters before an annual meeting of stockholders or make nominations for directors at an annual meeting of stockholders.
Amendments to Our Amended and Restated Bylaws
Our amended and restated certificate of incorporation grants our board of directors the authority to adopt, amend or repeal our amended and restated bylaws without a stockholder vote in any manner not inconsistent with the laws of the State of Delaware.
Limitations on Liability and Indemnification of Officers and Directors
Our amended and restated certificate of incorporation provides that no director will be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except as required by applicable law, as in effect from time to time. Currently, Delaware law requires that liability be imposed for the following:
•
any breach of the director’s duty of loyalty to our company or our stockholders;
•
any act or omission not in good faith or which involved intentional misconduct or a knowing violation of law;
•
unlawful payments of dividends or unlawful stock repurchases or redemptions as provided in Section 174 of the Delaware General Corporation Law; and
•
any transaction from which the director derived an improper personal benefit.
As a result, neither we nor our stockholders have the right, through stockholders’ derivative suits on our behalf, to recover monetary damages against a director for breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior, except in the situations described above.
Our amended and restated certificate of incorporation provides that, to the fullest extent permitted by law, we will indemnify any officer or director of our company against all damages, claims and liabilities arising out of the fact that the person is or was our director or officer, or served any other enterprise at our request as a director, officer, employee, agent or fiduciary. We will reimburse the expenses, including attorneys’ fees, incurred by a person indemnified by this provision when we receive an undertaking to repay such amounts if it is ultimately determined that the person is not entitled to be indemnified by us. Amending this provision will not reduce our indemnification obligations relating to actions taken before an amendment.
Delaware Anti-Takeover Statute
We are subject to Section 203 of the DGCL. Subject to specified exceptions, Section 203 prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three years after the date of the transaction in which the person became an interested stockholder. “Business combinations” include mergers, asset sales and other transactions resulting in a financial benefit to the “interested stockholder.” Subject to various exceptions, an “interested stockholder” is a person who together with his or her affiliates and associates, owns, or within three years did own, 15% or more of the corporation’s outstanding voting stock. These restrictions generally prohibit or delay the accomplishment of mergers or other takeover or change-in-control attempts.
Transfer Agent and Registrar
Computershare Trust Company, N.A. is the transfer agent and registrar for our common stock.

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Listing
We intend to apply to list our common stock on the NYSE under the symbol “CTRA.”
Authorized but Unissued Capital Stock
The DGCL does not require stockholder approval for any issuance of authorized shares. However, the listing requirements of the NYSE, which would apply so long as our common stock is listed on the NYSE, require stockholder approval of certain issuances equal to or exceeding 20% of the then-outstanding voting power or then-outstanding number of shares of common stock. These additional shares may be used for a variety of corporate purposes, including future public offerings, to raise additional capital or to facilitate acquisitions.
One of the effects of the existence of unissued and unreserved common stock may be to enable our board of directors to issue shares to persons friendly to current management, which issuance could render more difficult or discourage an attempt to obtain control of our company by means of a merger, tender offer, proxy contest or otherwise, and thereby protect the continuity of our management and possibly deprive the stockholders of opportunities to sell their shares of common stock at prices higher than prevailing market prices.

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SHARES ELIGIBLE FOR FUTURE SALE
Future sales of substantial amounts of shares of our common stock, including shares issued upon the exercise of outstanding options, vesting of restricted stock units and exercise of outstanding warrants, in the public market after this offering, or the possibility of these sales occurring, could adversely affect the prevailing market price for our common stock from time to time or impair our ability to raise equity capital in the future.
Based on the number of shares outstanding as of          , upon the completion of this offering,         shares of our common stock will be outstanding, assuming no exercise of outstanding options, no vesting of outstanding restricted stock units and no exercise of outstanding warrants. Of the outstanding shares,         shares sold in this offering will be freely tradable, except that any shares acquired by our affiliates, as that term is defined in Rule 144 under the Securities Act, in this offering may only be sold in compliance with the limitations described below.
In addition, as described below, 9,350,000 shares of common stock and 810,811 warrants issued in reliance on Section 1145(a)(1) of the Bankruptcy Code pursuant to Alpha’s Plan of Reorganization (and the shares of common stock issuable upon exercise of such warrants) may be resold without registration unless the seller is an “underwriter” with respect to those securities. The remaining shares of common stock and warrants will be deemed restricted securities, as defined under Rule 144 under the Securities Act were issued and sold by us in reliance on exemptions from the registration requirements of the Securities Act. These securities may be sold in the public market only if registered or pursuant to an exemption from registration, such as Rule 144 or Rule 701 under the Securities Act.
The restricted shares and the shares held by our affiliates will be available for sale in the public market as follows:
•
          shares of common stock will be eligible for sale at various times after the date of this prospectus pursuant to Rule 144; and
•
          shares of common stock subject to the lock-up agreements will be eligible for sale at various times beginning 180 days after the date of this prospectus pursuant to Rule 144 or Rule 701, as applicable.
Shares of Common Stock and Warrants Issued in Reliance on Section 1145 of the Bankruptcy Code
We relied on Section 1145(a)(1) of the Bankruptcy Code to exempt from the registration requirements of the Securities Act the offer and sale of certain shares of common stock and the warrants issued pursuant to Alpha’s Plan of Reorganization. Section 1145(a)(1) exempts the offer and sale of securities under a plan of reorganization from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied. 9,350,000 shares of common stock and 810,811 warrants issued pursuant to Alpha’s Plan of Reorganization (and the shares of common stock issuable upon exercise of such warrants) may be resold without registration unless the seller is an “underwriter” with respect to those securities. Section 1145(b)(1) defines an “underwriter” as any person who:
•
purchases a claim against, an interest in, or a claim for an administrative expense against the debtor, if that purchase is with a view to distributing any security received in exchange for such a claim or interest;
•
offers to sell securities offered under the plan for holders of those securities; offers to buy those securities from the holders of the securities, if the offer to buy is (i) with a view to distributing those securities; and (ii) under an agreement made in connection with the plan, with the consummation of the plan, or with the offer or sale of securities under the plan; or
•
is an “affiliate” of the issuer.
To the extent a person is deemed to be an “underwriter,” resales by such person would not be exempted by Section 1145 from registration under the Securities Act or other applicable law. Those persons would, however, be

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permitted to sell our shares of common stock or warrants without registration if they are able to comply with the provisions of Rule 144, as described further below.
Rule 144
In general, a person who has beneficially owned restricted shares of our common stock or warrants for at least six months would be entitled to sell such securities, provided that (i) such person is not deemed to have been one of our affiliates at the time of, or at any time during the 90 days preceding, a sale and (ii) we are subject to the Exchange Act periodic reporting requirements for at least 90 days before the sale. Persons who have beneficially owned restricted shares of our common stock or warrants for at least six months but who are our affiliates at the time of, or any time during the 90 days preceding, a sale, would be subject to additional restrictions, by which such person would be entitled to sell within any three month period only a number of securities that does not exceed the greater of either of the following:
•
1% of the number of shares of our common stock then outstanding, which will equal approximately          shares immediately after this offering; or
•
the average weekly trading volume of our common stock on the NYSE during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale;
provided, in each case, that we are subject to the Exchange Act periodic reporting requirements for at least 90 days before the sale. Such sales both by affiliates and by non-affiliates must also comply with the manner of sale, current public information and notice provisions of Rule 144 to the extent applicable.
Rule 701
In general, under Rule 701, our employees, directors, officers, consultants or advisors who purchase shares from us in connection with a compensatory benefit plan or other written agreement before the effective date of this offering is entitled to resell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirements or other restrictions contained in Rule 701.
Rule 701 is available to an issuer before it becomes subject to the reporting requirements of the Exchange Act, and will apply to shares acquired upon the exercise of options, including exercises after the date of this prospectus. Securities issued in reliance on Rule 701 are restricted securities and, subject to the contractual restrictions described above, beginning 90 days after the date of this prospectus, may be sold by persons other than “affiliates,” as defined in Rule 144, subject only to the manner of sale provisions of Rule 144 and by “affiliates” under Rule 144 without compliance with its one-year minimum holding period requirement.
Registration Rights
We and certain of our stockholders entered into a registration rights agreement in connection with the Alpha Restructuring. Pursuant to the registration rights agreement, such stockholders may, subject to various conditions and limitations, require us to file registration statements to register the resale of the shares held by such stockholders or to include their shares in registration statements that we file for ourselves or other stockholders, subject to the 180-day lock-up period described below. We have also agreed to reimburse the parties to the registration rights agreement for certain expenses incurred in connection with the filing of any registration statement and the marketing of any securities registered pursuant to the registration rights agreement. Registration of these shares under the Securities Act would result in these shares becoming freely tradable without restriction immediately upon the registered sale of such shares. These shares may also be sold pursuant to Section 1145 of the Bankruptcy Code unless the seller is an “underwriter” with respect to such shares as described above.

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Registration on Form S-8
Following completion of this offering, we intend to file one or more registration statements on Form S-8 under the Securities Act to register shares of common stock issuable under our stock incentive plans. As a result, shares of common stock issued pursuant to such stock incentive plans, including upon exercise of stock options and restricted stock units, will be eligible for resale in the public market without restriction, subject to the Rule 144 limitations applicable to affiliates and the lock-up agreements described below.
Equity Awards
As of          , 2017,         options to purchase a total of          shares of common stock and          shares of common stock underlying restricted stock units were outstanding. All of the shares subject to such options and restricted stock units are subject to lock-up agreements. An additional          shares of common stock were available for future grants under our equity incentive plans.
Lock-up Agreements
All of our directors, executive officers, selling stockholders and holders of           of our common stock have agreed subject to certain exceptions, not to offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of, directly or indirectly, or enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of any shares of common stock or any securities convertible into or exercisable or exchangeable for shares of common stock for a period of 180 days after the date of this prospectus, without the prior written consent of the representatives of the underwriters. See “Underwriting.”

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MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSEQUENCES TO NON-U.S. HOLDERS
The following are the material U.S. federal income and estate tax consequences of the ownership and disposition of our common stock acquired in this offering by a “Non-U.S. Holder” that does not own, and has not owned, actually or constructively, more than 5% of our common stock. You are a Non-U.S. Holder if for U.S. federal income tax purposes you are a beneficial owner of our common stock that is:
•
a nonresident alien individual;
•
a foreign corporation; or
•
a foreign estate or trust.
You are not a Non-U.S. Holder for purposes of this discussion if you are a nonresident alien individual present in the United States for 183 days or more in the taxable year of disposition, or if you are a former citizen or former resident of the United States for U.S. federal income tax purposes. If you are such a person, you should consult your tax adviser regarding the U.S. federal income tax consequences of the ownership and disposition of our common stock.
If you are a partnership for U.S. federal income tax purposes, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner, certain determinations made at the partner level and your activities. 
This discussion is based on the Code, administrative pronouncements, judicial decisions and final, temporary and proposed Treasury regulations, changes to any of which subsequent to the date of this prospectus may affect the tax consequences described herein, possibly with retroactive effect. This discussion does not describe all of the tax consequences that may be relevant to you in light of your particular circumstances, including alternative minimum tax and Medicare contribution tax consequences and does not address any aspect of state, local or non-U.S. taxation, or any taxes other than income and estate taxes. You should consult your tax adviser with regard to the application of the U.S. federal tax laws to your particular situation, as well as any tax consequences arising under the laws of any state, local or non-U.S. taxing jurisdiction.
Dividends
As discussed under “Dividend Policy” above, we have never declared or paid a distribution on our common stock. In the event that we do make distributions of cash or other property, those distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, they will constitute a return of capital, which will first reduce your basis in our common stock, but not below zero, and then will be treated as gain from the sale of our common stock, as described below under “—Gain on Disposition of Our Common Stock.”
Dividends paid to you generally will be subject to withholding tax at a 30% rate or a reduced rate specified by an applicable income tax treaty. In order to obtain a reduced rate of withholding, you will be required to provide a properly executed applicable Internal Revenue Service (“IRS”) Form W-8 certifying your entitlement to benefits under a treaty.
If dividends paid to you are effectively connected with your conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, are attributable to a permanent establishment or fixed base maintained by you in the United States), you will generally be taxed on the dividends in the same manner as a U.S. person. In this case, you will be exempt from the withholding tax discussed in the preceding paragraph, although you will be required to provide a properly executed IRS Form W-8ECI in order to claim an exemption from withholding. You should consult your tax adviser with respect to other U.S. tax consequences of the ownership and

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disposition of our common stock, including the possible imposition of a branch profits tax at a rate of 30% (or a lower treaty rate) if you are a corporation.
Gain on Disposition of Our Common Stock
Subject to the discussions below under “—Information Reporting and Backup Withholding” and “—FATCA,” you generally will not be subject to U.S. federal income or withholding tax on gain realized on a sale or other taxable disposition of our common stock unless:
•
the gain is effectively connected with your conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment or fixed base maintained by you in the United States), or
•
we are or have been a “United States real property holding corporation,” as described below, at any time within the five-year period preceding the disposition or your holding period, whichever period is shorter, and our common stock has ceased to be regularly traded on an established securities market prior to the beginning of the calendar year in which the sale or disposition occurs.
Generally, a domestic corporation is a United States real property holding corporation if the fair market value of its United States real property interests, as defined in the Code and applicable Treasury regulations, equals or exceeds 50% of the aggregate fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a United States real property holding corporation for U.S. federal income tax purposes. However, as long as our common stock is considered to be “regularly traded on an established securities market” (within the meaning of the Treasury regulations), only a Non-U.S. holder that actually or constructively owns, or owned at any time during the five-year period preceding the disposition or the Non-U.S. holder’s holding period for the common stock, whichever period is shorter, more than 5% of our common stock will be taxable on gain realized on the disposition of our common stock as a result of our status as a United States real property holding corporation. If our common stock were not considered to be regularly traded on an established securities market, such holder (regardless of the percentage of stock owned) would be subject to U.S. federal income tax on a taxable disposition of our common stock (as described in the preceding paragraph), and a 15% withholding tax would apply to the gross proceeds from such disposition.
If you recognize gain on a sale or other disposition of our common stock that is effectively connected with your conduct of a trade or business in the United States (and if required by an applicable income tax treaty, is attributable to a permanent establishment or fixed base maintained by you in the United States), you will generally be taxed on such gain in the same manner as a U.S. person. You should consult your tax adviser with respect to other U.S. tax consequences of the ownership and disposition of our common stock, including the possible imposition of a branch profits tax at a rate of 30% (or a lower treaty rate) if you are a corporation.
Information Reporting and Backup Withholding
Information returns are required to be filed with the IRS in connection with payments of dividends on our common stock. Unless you comply with certification procedures to establish that you are not a U.S. person, information returns may also be filed with the IRS in connection with the proceeds from a sale or other disposition of our common stock. You may be subject to backup withholding on payments on our common stock or on the proceeds from a sale or other disposition of our common stock unless you comply with certification procedures to establish that you are not a U.S. person or otherwise establish an exemption. Your provision of a properly executed applicable IRS Form W-8 certifying your non-U.S. status will permit you to avoid backup withholding. Amounts withheld under the backup withholding rules are not additional taxes and may be refunded or credited against your U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

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FATCA
Provisions of the Code commonly referred to as “FATCA” require withholding of 30% on payments of dividends on our common stock, as well as of gross proceeds of dispositions occurring after December 31, 2018 of our common stock, to “foreign financial institutions” (which is broadly defined for this purpose and in general includes investment vehicles) and certain other non-U.S. entities unless various U.S. information reporting and due diligence requirements (generally relating to ownership by U.S. persons of interests in or accounts with those entities) have been satisfied, or an exemption applies. An intergovernmental agreement between the United States and an applicable foreign country may modify these requirements. If FATCA withholding is imposed, a beneficial owner that is not a foreign financial institution generally may obtain a refund of any amounts withheld by filing a U.S. federal income tax return (which may entail significant administrative burden). You should consult your tax adviser regarding the effects of FATCA on your investment in our common stock.
Federal Estate Tax
Individual Non-U.S. Holders and entities the property of which is potentially includible in such an individual’s gross estate for U.S. federal estate tax purposes (for example, a trust funded by such an individual and with respect to which the individual has retained certain interests or powers), should note that, absent an applicable treaty exemption, our common stock will be treated as U.S.-situs property subject to U.S. federal estate tax.

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UNDERWRITING
Citigroup Global Markets Inc. (“Citigroup”) is acting as book-running manager of the offering and as representative of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and the selling stockholders have agreed to sell to that underwriter, the number of shares of common stock set forth opposite the underwriter’s name.
Underwriter
Number
of Shares
Citigroup Global Markets Inc.
 
          
 
          
 
Total
 
The underwriting agreement provides that the obligations of the underwriters to purchase the shares included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the shares (other than those covered by the underwriters’ option to purchase additional shares described below) if they purchase any of the shares.
Shares sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount from the public offering price not to exceed $                      per share. If all the shares are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms.
If the underwriters sell more shares than the total number set forth in the table above, the selling stockholders have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to                      additional shares at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional shares approximately proportionate to that underwriter’s initial purchase commitment. Any shares issued or sold under the option will be issued and sold on the same terms and conditions as the other shares that are the subject of this offering.
We, our officers and directors, and certain of our stockholders have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Citigroup, dispose of or hedge any shares or any securities convertible into or exchangeable for our common stock. Citigroup in its sole discretion may release any of the securities subject to these lock-up agreements at any time, which, in the case of officers and directors, shall be with notice.
At our request, the underwriters have reserved up to        % of the shares for sale at the initial public offering price to persons who are directors, officers or employees, or who are otherwise associated with us through a directed share program. The number of shares available for sale to the general public will be reduced by the number of directed shares purchased by participants in the program. Except for certain of our officers, directors and employees who have entered into lock-up agreements as contemplated in the immediately preceding paragraph, each person buying shares through the directed share program has agreed that, for a period of 180 days from the date of this prospectus, he or she will not, without the prior written consent of Citigroup, dispose of or hedge any shares or any securities convertible into or exchangeable for our common stock with respect to shares purchased in the program. For certain officers, directors and employees purchasing shares through the directed share program, the lock-up agreements contemplated in the immediately preceding paragraph shall govern with respect to their purchases. Citigroup in its sole discretion may release any of the securities subject to these lock-up agreements at any time, which, in the case of officers and directors, shall be with notice. Any directed shares not purchased will be offered by the underwriters to the general public on the same basis as all other shares offered. We have agreed to indemnify

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the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the sales of the directed shares.
The initial public offering price for the shares will be determined by negotiations among us, the selling stockholders and the representatives. Among the factors to be considered in determining the initial public offering price will be our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the price at which the shares will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our shares will develop and continue after this offering.
Although our common stock is quoted over-the-counter on the pink sheets, or OTC Pink, these quotations are not considered particularly relevant in determining the initial public offering price because there has historically been low volume resulting in a relative illiquid trading market. The high and low bid quotations for the period starting from August 18, 2016 through the quarter end September 30, 2016 (the first quarter during which our common stock was quoted on OTC Pink) through the quarter ended March 31, 2017 are set forth below. These quotations, as reported by OTC Markets Group, Inc., represent prices between dealers, do not include commissions, mark-ups or mark-downs and do not necessarily represent actual transactions.
 
Common Stock Bid Prices
 
High
 
Low
2017 Quarters Ended
 
 
 
June 30 (through May 1)
$
72.50

 
$
66.50

March 31
71.25

 
58.00

2016 Quarters Ended
 
 
 
December 31
79.00

 
42.00

September 30 (beginning August 18)
42.00

 
16.88

We intend to apply to list our common stock on the NYSE under the symbol “CTRA.”
The following table shows the underwriting discounts and commissions that the selling stockholders are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ over-allotment option.
 
No Exercise
 
Full Exercise
Per share
$
 
$
Total
$
 
$
We and the selling stockholders estimate that our respective portions of the total expenses of this offering will be $          and $          .
In connection with the offering, the underwriters may purchase and sell shares in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the underwriters’ option to purchase additional shares, and stabilizing purchases.
•
Short sales involve secondary market sales by the underwriters of a greater number of shares than they are required to purchase in the offering.
◦
“Covered” short sales are sales of shares in an amount up to the number of shares represented by the underwriters’ option to purchase additional shares.

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◦
“Naked” short sales are sales of shares in an amount in excess of the number of shares represented by the underwriters’ option to purchase additional shares.
•
Covering transactions involve purchases of shares either pursuant to the underwriters’ option to purchase additional shares or in the open market in order to cover short positions.
◦
To close a naked short position, the underwriters must purchase shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.
◦
To close a covered short position, the underwriters must purchase shares in the open market or must exercise the option to purchase additional shares. In determining the source of shares to close the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the underwriters’ option to purchase additional shares.
•
Stabilizing transactions involve bids to purchase shares so long as the stabilizing bids do not exceed a specified maximum.
Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the shares. They may also cause the price of the shares to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the NYSE, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.
Other Relationships
The underwriters are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. The underwriters and their respective affiliates have in the past performed commercial banking, investment banking and advisory services for us from time to time for which they have received customary fees and reimbursement of expenses and may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. In addition, affiliates of some of the underwriters are lenders, and in some cases agents or managers for the lenders, under our credit facility. Certain of the underwriters or their affiliates that have a lending relationship with us routinely hedge their credit exposure to us consistent with their customary risk management policies. A typical such hedging strategy would include these underwriters or their affiliates hedging such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.
We and the selling stockholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

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Selling Restrictions
Notice to Prospective Investors in the European Economic Area
In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of shares described in this prospectus may not be made to the public in that relevant member state other than:
•
to any legal entity which is a qualified investor as defined in the Prospectus Directive;
•
to fewer than 150 natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by us for any such offer; or
•
in any other circumstances falling within Article 3(2) of the Prospectus Directive,
provided that no such offer of shares shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.
For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe for the shares, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state) and includes any relevant implementing measure in the relevant member state. The expression 2010 PD Amending Directive means Directive 2010/73/EU.
The sellers of the shares have not authorized and do not authorize the making of any offer of shares through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the shares as contemplated in this prospectus. Accordingly, no purchaser of the shares, other than the underwriters, is authorized to make any further offer of the shares on behalf of the sellers or the underwriters.
Notice to Prospective Investors in the United Kingdom
This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (each such person being referred to as a “relevant person”). This prospectus and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant person should not act or rely on this document or any of its contents.
Notice to Prospective Investors in France
Neither this prospectus nor any other offering material relating to the shares described in this prospectus has been submitted to the clearance procedures of the Autorité des Marchés Financiers or of the competent authority of another member state of the European Economic Area and notified to the Autorité des Marchés Financiers. The shares have not been offered or sold and will not be offered or sold, directly or indirectly, to the public in France. Neither this prospectus nor any other offering material relating to the shares has been or will be:
•
released, issued, distributed or caused to be released, issued or distributed to the public in France; or

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•
used in connection with any offer for subscription or sale of the shares to the public in France.
Such offers, sales and distributions will be made in France only:
•
to qualified investors (investisseurs qualifiés) and/or to a restricted circle of investors (cercle restreint d’investisseurs), in each case investing for their own account, all as defined in, and in accordance with articles L.411-2, D.411-1, D.411-2, D.734-1, D.744-1, D.754-1 and D.764-1 of the French Code monétaire et financier;
•
to investment services providers authorized to engage in portfolio management on behalf of third parties; or
•
in a transaction that, in accordance with article L.411-2-II-1°-or-2°-or 3° of the French Code monétaire et financier and article 211-2 of the General Regulations (Règlement Général) of the Autorité des Marchés Financiers, does not constitute a public offer (appel public à l’épargne).
The shares may be resold directly or indirectly, only in compliance with articles L.411-1, L.411-2, L.412-1 and L.621-8 through L.621-8-3 of the French Code monétaire et financier.
Notice to Prospective Investors in Hong Kong
The shares may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong) and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.
Notice to Prospective Investors in Japan
The shares offered in this prospectus have not been and will not be registered under the Financial Instruments and Exchange Law of Japan. The shares have not been offered or sold and will not be offered or sold, directly or indirectly, in Japan or to or for the account of any resident of Japan (including any corporation or other entity organized under the laws of Japan), except (i) pursuant to an exemption from the registration requirements of the Financial Instruments and Exchange Law and (ii) in compliance with any other applicable requirements of Japanese law.
Notice to Prospective Investors in Singapore
This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person pursuant to Section 275(1), or any person pursuant to Section 275(1A), and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to compliance with conditions set forth in the SFA.
Where the shares are subscribed or purchased under Section 275 of the SFA by a relevant person which is:

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•
a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or
•
a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary of the trust is an individual who is an accredited investor,
shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferred within six months after that corporation or that trust has acquired the shares pursuant to an offer made under Section 275 of the SFA except:
•
to an institutional investor (for corporations, under Section 274 of the SFA) or to a relevant person defined in Section 275(2) of the SFA, or to any person pursuant to an offer that is made on terms that such shares, debentures and units of shares and debentures of that corporation or such rights and interest in that trust are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets, and further for corporations, in accordance with the conditions specified in Section 275 of the SFA;
•
where no consideration is or will be given for the transfer; or
•
where the transfer is by operation of law.
Notice to Prospective Investors in Australia
No prospectus or other disclosure document (as defined in the Corporations Act 2001 (Cth) of Australia (‘‘Corporations Act’’)) in relation to the common stock has been or will be lodged with the Australian Securities & Investments Commission (‘‘ASIC’’). This document has not been lodged with ASIC and is only directed to certain categories of exempt persons. Accordingly, if you receive this document in Australia:
(a) you confirm and warrant that you are either:
(i) a ‘‘sophisticated investor’’ under section 708(8)(a) or (b) of the Corporations Act;
(ii) a ‘‘sophisticated investor’’ under section 708(8)(c) or (d) of the Corporations Act and that you have provided an accountant’s certificate to us which complies with the requirements of section 708(8)(c)(i) or (ii) of the Corporations Act and related regulations before the offer has been made;
(iii) a person associated with the company under section 708(12) of the Corporations Act; or
(iv) a ‘‘professional investor’’ within the meaning of section 708(11)(a) or (b) of the Corporations Act, and to the extent that you are unable to confirm or warrant that you are an exempt sophisticated investor, associated person or professional investor under the Corporations Act any offer made to you under this document is void and incapable of acceptance; and
(b) you warrant and agree that you will not offer any of the common stock for resale in Australia within 12 months of that common stock being issued unless any such resale offer is exempt from the requirement to issue a disclosure document under section 708 of the Corporations Act.

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VALIDITY OF THE SHARES
The validity of the issuance of the shares of common stock to be sold in this offering will be passed upon for us by Davis Polk & Wardwell LLP, New York, New York. Latham & Watkins LLP, New York, New York will act as counsel to the underwriters.
EXPERTS
The consolidated financial statements of Contura Energy, Inc. and its subsidiaries as of December 31, 2016, and for the period from July 26, 2016 to December 31, 2016  (the Successor period) and the combined financial statements of Contura Energy, Inc. and its subsidiaries as of December 31, 2015 and for the period from January 1, 2016 to July 25, 2016 and for the years ended December 31, 2015 and December 31, 2014 (the Predecessor period), have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.  The audit report refers to the company’s acquisition of 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 financial information for the Successor period is presented on a different cost basis than that for the Predecessor periods and, therefore, is not comparable.
The information appearing in this prospectus relating to the estimates of the quantity and quality of our proven and probable coal reserves was prepared by Marshall Miller & Associates, Inc. an independent engineering firm, and has been included herein in reliance upon the authority of this firm as an expert in the matters.
The sections in this prospectus entitled “Prospectus Summary,” “The Coal Industry” and “Business” contain certain information with respect to the coal industry that has been sourced from Wood Mackenzie. Wood Mackenzie has agreed to be named as an expert with respect to such information, as indicated in the consent of Wood Mackenzie filed as an exhibit to the Registration Statement on Form S-1 of which this prospectus forms a part.
WHERE YOU CAN FIND ADDITIONAL INFORMATION
We have filed with the Securities and Exchange Commission a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act with respect to the issuance of shares of our common stock being offered hereby.
This prospectus, which forms a part of the registration statement, does not contain all of the information set forth in the registration statement. For further information with respect to us and the shares of our common stock, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. The registration statement, such reports and other information can be inspected and copied at the Public Reference Room of the SEC located at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Room of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.
We are not currently subject to the informational requirements of the Exchange Act. As a result of the offering of the shares of our common stock, we will become subject to the informational requirements of the Exchange Act, and, in accordance therewith, will file periodic reports and other information with the SEC.

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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.
ARNU. The Audibert-Arnu dilatometer test, which tests the expansion of coal.
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.
Bituminous coal. A common type of coal with moisture content less than 20% by weight. It is dense and black and often has well-defined bands of bright and dull material.
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).
Captive coal. In the context of coal volume, 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.
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.”
Coal slurry impoundment. Coal slurry consists of solid and liquid waste and is a by-product of the coal mining and preparation processes. It is a fine coal refuse and water mixture. Impoundment is for the storage of liquid and primarily noncombustible solids that are by-products of coal cleaning.
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.
Continuous miner. A machine used in underground mining to cut coal from the seam and load onto conveyors or shuttle cars in a continuous operation. In contrast, a conventional mining unit must stop extracting in order to begin loading.
Continuous mining. A form of underground mining that cuts the coal from the seam and loads the coal on to a conveyor system continuously, thus eliminating the separate cycles of cutting, drilling, shooting and loading.
Fossil fuel. Fuel such as coal, petroleum or natural gas formed from the fossil remains of organic material.
Hard coking coal (“HCC”). Hard coking coal is a type of met coal that is a necessary ingredient in the production of strong coke. It is evaluated based on the strength, yield and size distribution of coke produced from such coal, which is dependent on the rank and plastic properties of the coal. Hard coking coals trade at a premium to other coals due to their importance in producing strong coke and because they are a limited resource.
High BTU coal. Coal which has an average heat content of 12,500 BTUs per pound or greater.
High-Vol. A. High-volatile A bituminous coal.

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High-Vol. B. High-volatile B bituminous coal.
Illinois Basin or ILB. Coal producing area in Illinois, Indiana and western Kentucky.
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.
Low sulfur coal. Low sulfur steam coals have a sulfur content of 1.5% or less, and low sulfur met coals have a sulfur content of 1.0% or less.
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.
Mid-Vol. Mid-volatile bituminous coal.
Mineable Coal. That portion of the coal reserve base which is commercially mineable and excludes all coal that will be left, such as in pillars, fenders or property barriers.
Mst. Million short tons.
Nitrogen oxide (NOx). A gas formed in high temperature environments such as coal combustion.
Northern Appalachia or NAPP. Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.
Overburden. Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.
Powder River Basin or PRB. Coal producing area in northeastern Wyoming and southeastern Montana. This is the largest known source of coal reserves and the largest producing region in the United States.
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 prospectus, 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.

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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.
Steam 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.
Subsidence. Lateral or vertical movement of surface land that occurs when the roof of an underground mine collapses. Longwall mining causes planned subsidence by the mining out of coal that supports the overlying strata.
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 (see “Overburden”).
T&L coal. In the context of coal volume, coal purchased from third-party producers and sold through our Trading and Logistics business.
Thermal coal. See definition for Steam coal.
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.
Wood Mackenzie. Wood Mackenzie Inc.

178



Index to Financial Statements
Table Of Contents
 
Page
 

F-1



Report of Independent Registered Public Accounting Firm
The Board of Directors
Contura Energy, Inc.:
We have audited the accompanying consolidated balance sheet of Contura Energy Inc. and subsidiaries (the Company) as of December 31, 2016, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for the period from July 26, 2016 to December 31, 2016 (the Successor period). We have also audited the accompanying combined balance sheet of the Company’s predecessor (the Predecessor) as of December 31, 2015, and the related combined statements of operations, comprehensive income (loss), predecessor business equity, and cash flows for the period from January 1, 2016 to July 25, 2016 and for each of the years in the two-year period ended December 31, 2015 (the Predecessor periods). These consolidated and combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated and combined financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the Company’s consolidated financial statements referred to above present fairly, in all material respects, the financial position of Contura Energy, Inc. and subsidiaries as of December 31, 2016, and the results of their operations and their cash flows for the Successor period, in conformity with U.S. generally accepted accounting principles. Further, in our opinion the Predecessor’s combined financial statements referred to above present fairly, in all material respects, the financial position of the Predecessor as of December 31, 2015, and the results of their operations and their cash flows for the Predecessor periods, in conformity with U.S. generally accepted accounting principles.
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 period is presented on a different cost basis than that for the Predecessor period and, therefore, is not comparable.
/s/ KPMG LLP
Roanoke, Virginia
May 8, 2017


F-2

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

 
Successor
 
 
Predecessor
 
Period from
July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Revenues:
 

 
 
 

 
 
 
 
Coal revenues
$
612,247

 
 
$
537,320

 
$
1,243,690

 
$
1,464,316

Freight and handling revenues
70,544

 
 
52,076

 
97,237

 
98,109

Other revenues
6,628

 
 
18,542

 
20,704

 
24,600

Total revenues
689,419

 
 
607,938

 
1,361,631

 
1,587,025

Costs and expenses:
 

 
 
 

 
 
 
 
Cost of coal sales (exclusive of items shown separately below)
465,764

 
 
489,652

 
1,106,046

 
1,202,612

Freight and handling costs
70,544

 
 
52,076

 
97,237

 
98,109

Other expenses
2,559

 
 
4,893

 
(931
)
 
15,473

Depreciation, depletion and amortization
43,978

 
 
85,379

 
202,115

 
203,361

Amortization of acquired intangibles, net
61,281

 
 
11,567

 
2,223

 
(1,699
)
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization shown separately above)
19,135

 
 
29,567

 
44,158

 
52,256

Mark-to-market adjustment for acquisition-related obligations
(10,616
)
 
 
—

 
—

 
—

Asset impairment and restructuring
—

 
 
3,755

 
558,699

 
6,849

Goodwill impairment
—

 
 
—

 
—

 
70,017

Total costs and expenses
652,645

 
 
676,889

 
2,009,547

 
1,646,978

Income (loss) from operations
36,774

 
 
(68,951
)
 
(647,916
)
 
(59,953
)
Other (expense) income:
 

 
 
 

 
 
 
 
Interest expense
(20,792
)
 
 
(63
)
 
(437
)
 
(712
)
Interest income
23

 
 
29

 
4

 
7

Mark-to-market adjustment for warrant derivative liability
(33,975
)
 
 
—

 
—

 
—

Bargain purchase gain
7,719

 
 
—

 
—

 
—

Equity loss in affiliates
(2,280
)
 
 
(2,726
)
 
(7,700
)
 
(9,810
)
Miscellaneous income, net
232

 
 
683

 
28

 
383

Total other (expense) income, net
(49,073
)
 
 
(2,077
)
 
(8,105
)
 
(10,132
)
Loss before reorganization items and income taxes
(12,299
)
 
 
(71,028
)
 
(656,021
)
 
(70,085
)
Reorganization items, net
—

 
 
(31,073
)
 
(16,134
)
 
—

Loss before income taxes
(12,299
)
 
 
(102,101
)
 
(672,155
)
 
(70,085
)
Income tax benefit
1,369

 
 
34,889

 
254,595

 
17,740

Net loss
$
(10,930
)
 
 
$
(67,212
)
 
$
(417,560
)
 
$
(52,345
)
Basic loss per common share
$
(1.06
)
 
 


 


 


Diluted loss per common share
$
(1.06
)
 
 


 


 


Weighted average shares - basic
10,309,310

 
 
 
 
 
 
 
Weighted average shares - diluted
10,309,310

 
 
 
 
 
 
 

See accompanying Notes to Financial Statements.
F-3

CONTURA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) AND
PREDECESSOR STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Amounts in thousands)

 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Net loss
$
(10,930
)
 
 
$
(67,212
)
 
$
(417,560
)
 
$
(52,345
)
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
 
Employee benefit plans:
 
 
 
 
 
 
 
 
Current period actuarial (loss) gain, net of income tax of ($1,181), $1,227, ($549) and ($224) for the period from July 26, 2016 to December 31, 2016, for the period January 1, 2016 to July 25, 2016, and for the years ended December 31, 2015 and 2014, respectively
2,087

 
 
(2,188
)
 
6,269

 
446

Prior service (cost) credit for period, net of income tax of $0, $0, $713 and $377 for the period from July 26, 2016 to December 31, 2016, for the period January 1, 2016 to July 25, 2016, and for the years ended December 31, 2015 and 2014, respectively
—

 
 
—

 
(8,141
)
 
(750
)
Less: reclassification adjustment for amounts reclassified to earnings due to amortization of net actuarial loss and settlements, net of income tax of $0, ($74), ($10) and ($14) for the period from July 26, 2016 to December 31, 2016, for the period January 1, 2016 to July 25, 2016, and for the years ended December 31, 2015 and 2014, respectively
—

 
 
132

 
111

 
27

Less: reclassification adjustment for amounts reclassified to earnings due to amortization of prior service credit, net of income tax of $0, ($1,271), ($15) and $0 for the period from July 26, 2016 to December 31, 2016, for the period January 1, 2016 to July 25, 2016, and for the years ended December 31, 2015 and 2014, respectively
—

 
 
2,265

 
166

 
—

Cash flow hedges:
 
 
 
 
 
 
 
 
Reclassification adjustment for amounts reclassified to earnings related to settlement of cash flow hedges, net of income tax of $0, $0, ($442) and ($34) for the period from July 26, 2016 to December 31, 2016, for the period January 1, 2016 to July 25, 2016, and for the years ended December 31, 2015 and 2014, respectively
—

 
 
—

 
1,013

 
68

Total other comprehensive income (loss), net of tax
2,087

 
 
209

 
(582
)
 
(209
)
Total comprehensive loss
$
(8,843
)
 
 
$
(67,003
)
 
$
(418,142
)
 
$
(52,554
)


See accompanying Notes to Financial Statements.
F-4

CONTURA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET AND PREDECESSOR BALANCE SHEET
(Amounts in thousands, except share and per share data)

 
Successor
 
 
Predecessor
 
December 31, 2016
 
 
December 31, 2015
Assets
 

 
 
 
Current assets:
 

 
 
 
Cash and cash equivalents
$
127,948

 
 
$
269

Trade accounts receivable, net
182,600

 
 
84,575

Inventories, net
75,399

 
 
66,505

Assets held for sale
1,714

 
 
—

Prepaid expenses and other current assets
37,555

 
 
30,195

Total current assets
425,216

 
 
181,544

Property, plant, and equipment, net
317,013

 
 
1,493,390

Other acquired intangibles (net of accumulated amortization of $61,851 and $33,565 as of December 31, 2016 and 2015, respectively)
87,149

 
 
12,018

Long-term restricted cash
43,341

 
 
4,190

Long-term deposits
55,501

 
 
1,576

Other non-current assets
18,532

 
 
22,692

Total assets
$
946,752

 
 
$
1,715,410

Liabilities and Stockholders’ Equity / Predecessor Business Equity
 

 
 
 

Liabilities not subject to compromise:
 
 
 
 
Current liabilities:
 

 
 
 

Current portion of long-term debt
$
2,324

 
 
$
68

Trade accounts payable
98,166

 
 
32,696

Acquisition-related obligations - current
27,258

 
 
—

Accrued expenses and other current liabilities
90,864

 
 
95,531

Total current liabilities not subject to compromise
218,612

 
 
128,295

Long-term debt
346,837

 
 
68

Acquisition-related obligations - long-term
59,088

 
 
—

Asset retirement obligations
187,097

 
 
166,194

Deferred income taxes
—

 
 
67,734

Other non-current liabilities
97,894

 
 
66,980

Total liabilities not subject to compromise
909,528

 
 
429,271

Liabilities subject to compromise
—

 
 
72,242

Total liabilities
909,528

 
 
501,513

Commitments and Contingencies (Note 22)
 
 
 
 
Stockholders’ Equity / Predecessor Business Equity


 
 
 
Preferred stock - par value $0.01, 2.0 million shares authorized, none issued
—

 
 
—

Common stock - par value $0.01, 20.0 million shares authorized, 10.3 million issued and outstanding at December 31, 2016 and none issued at December 31, 2015
103

 
 
—

Additional paid-in capital
45,964

 
 
—

Accumulated other comprehensive income
2,087

 
 
4,135

Accumulated deficit
(10,930
)
 
 
(559,922
)
Alpha’s investment
—

 
 
1,769,684

Total stockholders’ equity / Predecessor business equity
37,224

 
 
1,213,897

Total liabilities and stockholders’ equity / Predecessor business equity
$
946,752

 
 
$
1,715,410


See accompanying Notes to Financial Statements.
F-5

CONTURA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS AND
PREDECESSOR STATEMENTS OF CASH FLOWS
(Amounts in thousands)

 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Operating activities:
 

 
 
 
 
 
 
 
Net loss
$
(10,930
)
 
 
$
(67,212
)
 
$
(417,560
)
 
$
(52,345
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 

 
 
 

 
 

 
 

Depreciation, depletion and amortization
43,978

 
 
85,379

 
202,115

 
203,361

Amortization of acquired intangibles, net
61,281

 
 
11,567

 
2,223

 
(1,699
)
Accretion of acquisition-related obligations discount
4,936

 
 
—

 
—

 
—

Mark-to-market adjustment for warrants derivative liability
33,975

 
 
—

 
—

 
—

Mark-to-market adjustments for derivatives
—

 
 
—

 
4,683

 
8,293

Mark-to-market adjustment for acquisition-related obligations
(10,616
)
 
 
—

 
—

 
—

Bargain purchase gain
(7,719
)
 
 
—

 
—

 
—

Equity loss in affiliates
2,280

 
 
2,726

 
7,700

 
9,810

Accretion of asset retirement obligations
10,819

 
 
12,422

 
17,897

 
14,669

Stock-based compensation
1,424

 
 
658

 
2,668

 
9,872

Employee benefit plans, net
3,154

 
 
11,917

 
11,091

 
4,688

Deferred income taxes
(1,180
)
 
 
(34,889
)
 
(250,680
)
 
(32,942
)
Loss (Gain) on disposal of property, plant, and equipment
216

 
 
216

 
17,438

 
896

Asset impairment and restructuring
—

 
 
3,755

 
558,699

 
6,849

Goodwill impairment
—

 
 
—

 
—

 
70,017

Non-cash reorganization items, net
—

 
 
3,837

 
7,726

 
—

Other, net
1,356

 
 
38

 
207

 
(639
)
Changes in operating assets and liabilities
 
 
 
 
 
 
 
 
Trade accounts receivable, net
(114,244
)
 
 
42,793

 
41,403

 
(30,839
)
Inventories, net
(32,046
)
 
 
16,693

 
2,440

 
(4,310
)
Prepaid expenses and other current assets
(817
)
 
 
5,172

 
(2,399
)
 
(5,375
)
Long-term restricted cash
49,459

 
 
(16,339
)
 
(4,190
)
 
—

Long-term deposits
(55,407
)
 
 
(275
)
 
(1,566
)
 
—

Other non-current assets
(14,681
)
 
 
2,956

 
4,216

 
(168
)
Trade accounts payable
59,242

 
 
(6,665
)
 
(1,534
)
 
6,740

Accrued expenses and other current liabilities
51,053

 
 
3,680

 
(31,826
)
 
(19,361
)
Acquisition-related obligations
(9,300
)
 
 
—

 
—

 
—

Asset retirement obligations
(514
)
 
 
(2,143
)
 
(3,619
)
 
(3,236
)
Other non-current liabilities
5,199

 
 
(15,596
)
 
(16,270
)
 
(19,178
)
Net cash provided by operating activities
70,918

 
 
60,690

 
150,862

 
165,103

Investing activities:
 
 
 
 
 
 
 
 
Capital expenditures
(34,497
)
 
 
(23,433
)
 
(59,533
)
 
(68,706
)

See accompanying Notes to Financial Statements.
F-6

CONTURA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS AND
PREDECESSOR STATEMENTS OF CASH FLOWS
(Amounts in thousands)

Acquisition of mineral rights under federal lease
—

 
 
—

 
(42,130
)
 
(42,130
)
Proceeds from sale of property, plant and equipment
1,787

 
 
526

 
10,503

 
4,114

Capital contributions to equity affiliates
(2,738
)
 
 
(2,122
)
 
(5,874
)
 
(7,852
)
Cash acquired in acquisition
51,000

 
 
—

 
—

 
—

Other, net
—

 
 
—

 
—

 
13

Net cash provided by (used in) investing activities
15,552

 
 
(25,029
)
 
(97,034
)
 
(114,561
)
Financing activities:
 
 
 
 
 
 
 
 
Proceeds from borrowings on long-term debt
42,500

 
 
—

 
—

 
—

Principal repayments of capital lease and capital financing obligations
(243
)
 
 
(42
)
 
(1,835
)
 
(1,222
)
Debt issuance costs
(243
)
 
 
—

 
—

 
—

Payments on federal coal lease
—

 
 
—

 
—

 
(3,946
)
Principal repayments of notes payable
(536
)
 
 
—

 
—

 
—

Transfers to Alpha (1)
—

 
 
(35,780
)
 
(51,750
)
 
(45,400
)
Net cash provided by (used in) financing activities
41,478

 
 
(35,822
)
 
(53,585
)
 
(50,568
)
Net increase (decrease) in cash and cash equivalents
127,948

 
 
(161
)
 
243

 
(26
)
Cash and cash equivalents at beginning of period
—

 
 
269

 
26

 
52

Cash and cash equivalents at end of period
$
127,948

 
 
$
108

 
$
269

 
$
26

 
 
 
 
 
 
 
 
 
Supplemental cash flow information:
 
 
 
 
 
 
 
 
Cash paid for interest
$
356

 
 
$
—

 
$
—

 
$
—

Cash paid for income taxes
$
—

 
 
$
—

 
 
 
$
15,202

Cash received from income tax refunds
$
—

 
 
$
—

 
$
3,915

 
$
—

Supplemental disclosure of non-cash investing and financing activities:
 

 
 
 

 
 

 
 

Capital leases and capital financing - equipment
$
3,473

 
 
$
—

 
$
—

 
$
1,097

Accrued capital expenditures
$
4,778

 
 
$
13,376

 
$
17,213

 
$
18,563

Issuance of equity in connection with acquisition
$
44,644

 
 
$
—

 
$
—

 
$
—

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

 
 
$
—

 
$
—

 
$
—

______________
(1)  See Basis of Presentation within Note 1.


See accompanying Notes to Financial Statements.
F-7

CONTURA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY AND
STATEMENTS OF PREDECESSOR BUSINESS EQUITY
(Amounts in thousands)

 
Common Stock
 
 
 
Accumulated
Other
Comprehensive Income (Loss)
 
 
 
 
 
Total Stockholders’ Equity / Predecessor Business Equity
 
Shares
 
Amount
 
Additional Paid-in Capital
 
 
Accumulated Deficit
 
Alpha’s Investment
 
Predecessor
 
 
 
 
 
 
 
 
 
 
 
 
 
Balances, December 31, 2013
 
 
$
—

 
$
—

 
$
4,926

 
$
(90,017
)
 
$
1,821,598

 
$
1,736,507

Net loss
 
 
—

 
—

 
—

 
(52,345
)
 
—

 
(52,345
)
Other comprehensive income (loss), net
 
 
—

 
—

 
(209
)
 
—

 
—

 
(209
)
Net distributions to Alpha
 
 
—

 
—

 
—

 
—

 
(19,611
)
 
(19,611
)
Balances, December 31, 2014
—

 
$
—

 
$
—

 
$
4,717

 
$
(142,362
)
 
$
1,801,987

 
$
1,664,342

Net loss
 
 
—

 
—

 
—

 
(417,560
)
 
—

 
(417,560
)
Other comprehensive income (loss), net
 
 
—

 
—

 
(582
)
 
—

 
—

 
(582
)
Net distributions to Alpha
 
 
—

 
—

 
—

 
—

 
(32,303
)
 
(32,303
)
Balances, December 31, 2015
—

 
$
—

 
$
—

 
$
4,135

 
$
(559,922
)
 
$
1,769,684

 
$
1,213,897

Net loss
 
 
—

 
—

 
—

 
(67,212
)
 
—

 
(67,212
)
Other comprehensive income (loss), 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
10,000

 
100

 
44,544

 
—

 
—

 
—

 
44,644

Net loss
—

 
—

 
—

 
—

 
(10,930
)
 
—

 
(10,930
)
Other comprehensive loss, net
—

 
—

 
—

 
2,087

 
—

 
—

 
2,087

Stock-based compensation and net issuance of common stock for share vesting
309

 
3

 
1,420

 
—

 
—

 
—

 
1,423

Balances, December 31, 2016
10,309

 
$
103

 
$
45,964

 
$
2,087

 
$
(10,930
)
 
$
—

 
$
37,224




See accompanying Notes to Financial Statements.
F-8

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


(1) Business and Basis of Presentation
Business
Contura Energy, Inc. (“Contura”, the “Company”, “we” or “us”) is a Tennessee-based Company with affiliate mining operations across multiple major coal basins in Pennsylvania, Virginia, West Virginia and Wyoming. With customers across the globe, high-quality reserves, and significant port capacity, Contura supplies both met coal to produce steel and steam coal to generate power. Contura was formed to acquire and operate certain of Alpha Natural Resources, Inc.’s (“Alpha”) core coal operations (see Note 3), as part of the Alpha restructuring. Contura began operations on July 26, 2016, with mining complexes in Northern Appalachia (Cumberland mine complex), the Powder River Basin (Belle Ayr and Eagle Butte complexes), and three Central Appalachian mining complexes (the Nicholas mine complex in Nicholas County, West Virginia, and the McClure and Toms Creek mine complexes in Virginia).
Contura also acquired Alpha’s 40.6% interest in the Dominion Terminal Associates coal export terminal in eastern Virginia, which is accounted for under the equity method. Refer to Note 26 for subsequent event disclosure related to the Company’s increased ownership interest in Dominion Terminal Associates.
As a result of the Alpha core coal operations’ acquisition, the historical financial statements are separated into Predecessor and Successor periods. Predecessor represents Contura prior to July 26, 2016, whereas Successor refers to the Company beginning July 26, 2016 and thereafter. For more detailed information regarding the Company’s and Predecessor’s consolidation and accounting policies, please refer to the Basis of Presentation discussion below and Note 2.
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 and the combined statements of operations, statements of comprehensive income (loss), balance sheet, statements of cash flows, and statements of equity for the Predecessor are known as the “Financial Statements.” The Financial Statements are generally referred to as consolidated (to reflect the Successor’s capital structure), and references across periods are generally labeled “Balance Sheets,” “Statements of Operations,” “Statements of Cash Flows,” and “Statements of Stockholders’ Equity.”
The Consolidated Financial Statements include all wholly-owned subsidiaries’ results of operations for the period from July 26, 2016 to December 31, 2016. All significant intercompany transactions have been eliminated in consolidation.
The 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 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 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 Predecessor balance sheet and statements of Predecessor business equity as “Alpha’s investment” and in the Predecessor statements of cash flows as “Transfers (to) from Alpha.” Due to non-cash asset transfers and expense allocations reflected in these combined statements of cash flows for the Predecessor period, cash transfers to Alpha will not equal net distributions to Alpha as reported on the statements of Predecessor business equity.
The Predecessor Financial Statements also include expense allocations of $57,217 for the period from January 1, 2016 to July 25, 2016, and $92,009 and $103,996 for the years ended December 31, 2015 and 2014, respectively, for

F-9


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 in the accompanying Consolidated Statements of Operations. These amounts exclude reorganization items which are discussed in Note 20. These expenses have been allocated to the Predecessor on the basis of 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 Predecessor Financial Statements, including the assumptions regarding the allocation of corporate expenses from Alpha, are reasonable. Nevertheless, the Predecessor Financial Statements may not include all of the expenses that would have been incurred had the Company been a stand-alone Company during the years 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 periods presented. Actual costs that would have been incurred if the Predecessor had been a stand-alone Company would depend on multiple factors, 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 (the “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 applicable portion of the Predecessor periods.  The Bankruptcy Court approved the Alpha Debtors Plan of Reorganization on July 7, 2016 and Alpha Debtors emerged from bankruptcy on July 26, 2016.
During the Predecessor period, certain prepetition liabilities have been reclassified as liabilities subject to compromise. Liabilities subject to compromise may include estimated or liquidated amounts for certain obligations arising prior to Alpha’s 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. See Note 20 for further disclosures related to Reorganization Items.
The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).
(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; postemployment and other employee benefit obligations; useful lives for, depletion and amortization; reserves for workers’ compensation and black lung claims; deferred income taxes; 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.

F-10


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, 2016, the Company’s cash equivalents consisted of highly rated money market funds.
Restricted Cash
Restricted cash represents 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 $11,195, $28,146, and $4,000 as of December 31, 2016 and $4,190, $0, and $0 as of December 31, 2015 for securing the Company’s obligations under certain worker’s compensation, reclamation related bonds, and financial guarantees, respectively, which have been written on the Company’s behalf. The Company’s restricted cash is primarily invested in interest bearing accounts.
Deposits
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, 2016, the Company had cash collateral in the form of deposits to secure the Company’s obligations under reclamation related bonds and various other operating agreements in the amounts of $52,578 and $2,923, respectively. Deposits totaled $1,576 as of December 31, 2015 and related to security deposits and other various operating agreements.
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 and $4,623 at December 31, 2016 and 2015, respectively. 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.
The Company adopted ASU 2015-11 during the year ended December 31, 2015, which required the Company to measure inventory at the lower of cost and 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. Prior to the adoption of ASU 2015-11, coal inventories were stated at the lower of average cost or market. Market represented the estimated replacement cost, subject to a floor and ceiling, which considered the future sales price of the product as well as remaining estimated preparation and selling costs.
Material and supplies inventories are valued at average cost, less an allowance for obsolete and surplus items.
Assets Held for Sale
The criteria to determine whether an asset should be classified as held-for-sale include: management with the authority to do so commits to a plan to sell the asset; the asset is available for immediate sale in its present condition

F-11


subject only to terms that are usual and customary for sales of such assets; an active program to locate a buyer and other actions required to complete the plan to sell the asset have been initiated; the sale of the asset is probable and expected to be completed within one year; the asset 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 property is classified as held for sale on the Company’s Balance Sheet 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. Assets held for sale of $1,714 as of December 31, 2016 represents the fair value of fixed assets at a closed mine within the Company’s Northern Appalachia Operations segment. There were no assets held for sale as of December 31, 2015.
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 $5,264 and $6,963 as of December 31, 2016 and 2015, respectively.
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.
Advanced mining royalties (net of allowance) were $1,417 and $6,017 as of December 31, 2016 and 2015, 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, 2013
$
3,087

Provision for non-recoupable advance mining royalties
187

Write-offs of advance mining royalties
(78
)
Balance at December 31, 2014
3,196

Provision for non-recoupable advance mining royalties
243

Write-offs of advance mining royalties
(71
)
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


F-12


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 twenty-five 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 cost of coal sales. 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.
Acquired Intangibles
Application of acquisition accounting related to 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 acquisition date for new contracts of similar terms and conditions.
During the period from July 26, 2016 to December 31, 2016, coal supply agreement assets were amortized over the actual number of tons shipped and amortized over a weighted average useful life of approximately sixteen months. Coal supply agreement liabilities were completely amortized at December 31, 2016. Coal supply agreement assets are reported in other acquired intangibles and coal supply agreement liabilities are reported in other non-current liabilities in the Balance Sheets.
During the period from January 1, 2016 to July 25, 2016 and for years ended December 31, 2015 and 2014, coal supply agreement assets related to acquisitions in the Predecessor period were amortized over the actual amount of tons shipped under each contract.
The following tables summarize the other acquired intangibles as of December 31, 2016 and 2015:
 
Successor
 
July 26, 2016 Acquisition value
 
Accumulated amortization
 
December 31, 2016
Balance, net
Assets:
 
 
 
 
 
Above-market coal supply agreements
$
149,000

 
$
(61,851
)
 
$
87,149

 
 
 
 
 
 
Liabilities:
 
 
 
 
 
Below-market coal supply agreements
$
570

 
$
(570
)
 
$
—


F-13


The following table summarize the changes to coal supply agreements and other acquired intangibles during the year ended December 31, 2015:
 
Predecessor
 
December 31, 2015
 
Acquisition value
 
Accumulated amortization
 
December 31, 2015
Balance, net
Assets:
 
 
 
 
 
Above-market coal supply agreements
$
44,933

 
$
(33,457
)
 
$
11,476

Other intangible assets
$
650

 
$
(108
)
 
542

Other acquired intangibles, net
$
45,583

 
$
(33,565
)
 
$
12,018

Amortization of other acquired intangible assets was $61,851, $11,567, $2,223, and $2,474 of expense and amortization of other non-current liabilities was a credit to expense of ($570), $0, $0, and ($4,173) resulting in a net expense (credit) of $61,281, $11,567, $2,223, and ($1,699) for the period from July 26, 2016 to December 31, 2016, the period from January 1, 2016 to July 25, 2016 and years ended December 31, 2015 and 2014, respectively, which is reported as amortization of acquired intangibles, net in the Statement of Operations. Future net amortization expense related to acquired intangibles is expected to be as follows:  
2017
$
(69,669
)
2018
(14,650
)
2019
(1,870
)
2020
(960
)
Total net future amortization expense
$
(87,149
)
Asset Impairment and Disposal of Long-Lived Assets
Long-lived assets, such as property, plant, and equipment, and purchased 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. Assets to be disposed would separately be presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and would no longer be depreciated. The assets and liabilities of a disposal group classified as held for sale would be presented separately in the Balance Sheets. See Note 9 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.

F-14


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 using a fair value approach at the reporting unit level in two steps. Step one compares the fair value of each reporting unit to its carrying amount. If step one indicates that the carrying value of a reporting unit exceeds its fair value, the second step is performed to measure the amount of impairment, if any. Goodwill impairment exists when the estimated implied fair value of goodwill is less than its carrying value.
The Company performed its goodwill impairment testing as of December 31, 2014. As a result of its testing, the Company wrote off $70,017 of goodwill for the year ended December 31, 2014. This resulted in the elimination of all goodwill.
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 13 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 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. 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 17 for further disclosures related to income taxes.
Revenue Recognition
The Company earns revenues primarily through the sale of coal produced at Company operations and coal purchased from third parties. The Company recognizes revenue using the following general revenue recognition criteria: (i) persuasive evidence of an arrangement exists; (ii) delivery has occurred or services have been rendered; (iii) the price to the buyer is fixed or determinable; and (iv) collectability is reasonably assured.

F-15


Delivery on our coal sales is determined to be complete for revenue recognition purposes when title and risk of loss has 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 passes as the coal is loaded into transport carriers for delivery to the customer. For international shipments, title generally passes at the time coal is loaded onto the shipping vessel.
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 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 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 852 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 20 for further details regarding reorganization items.
Workers’ Compensation and Pneumoconiosis (Black Lung) Benefits 
Workers’ Compensation
As of December 31, 2016, the Company primarily utilizes high-deductible insurance programs for workers’ compensation claims at its operations, except for the Company’s operations in Wyoming, where the Company participates in a compulsory state-run fund for workers’ compensation. 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 obligations are included in the Balance Sheets as accrued expenses and other current liabilities and other non-current liabilities. See Note 18 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, 2016, the Company 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. See Note 18 for further disclosures related to black lung benefits.

F-16


Life Insurance Benefits
As part of the Alpha restructuring and the Retiree Committee Settlement Agreement (see Note 12), 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.
Earnings (Loss) Per Share
 Basic earnings per share is computed by dividing net income by the weighted-average number of outstanding common shares for the period. Diluted earnings 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 per share is computed by increasing the weighted-average number of outstanding common shares computed in basic earnings per share to include the additional common shares that would be outstanding after issuance and adjusting net income for changes that would result from the issuance. Only those securities that are dilutive are included in the calculation. See Note 5 for further disclosures related to earnings 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. See Note 19 for further disclosures related to stock-based compensation arrangements.
Derivative Instruments and Hedging Activities
The Company had formerly entered into swap agreements with financial institutions to mitigate the risk of price volatility for diesel fuel. All existing swap agreements were terminated in August 2015 due to Alpha’s bankruptcy filing.
Derivative financial instruments are recognized as either assets or liabilities in the Balance Sheets and measured at fair value. On the date a derivative instrument is entered into, the Company may designate a qualifying derivative instrument as a hedge of the variability of cash flows to be received or paid related to a recognized asset or liability or forecasted transaction (cash flow hedge). The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash flow hedges to specific firm commitments or forecasted transactions. The Company also formally assesses both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of the related hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Company discontinues hedge accounting prospectively and records all future changes in fair value in current period earnings or losses.
For derivative instruments that have not been designated as cash flow hedges, changes in fair value are recorded in current period earnings or losses. For derivative instruments that have been designated as cash flow hedges, the effective portion of the changes in fair value are recorded in accumulated other comprehensive income (loss) and any portion that is ineffective is recorded in current period earnings or losses. Amounts recorded in accumulated other comprehensive income (loss) are reclassified to earnings or losses in the period the underlying hedged transaction affects earnings or when the underlying hedged transaction is probable of not occurring. See Note 16 for further disclosures related to derivative financial instruments and hedging activities.

F-17


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. The warrants are fair-valued using a Black-Scholes pricing model and result in a mark to market non-cash adjustment at each reporting period with changes in value reflected in earnings.
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 16 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 miscellaneous income (expense), net, 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 $1,171 and $4,312 as of December 31, 2016 and 2015, respectively.
New Accounting Pronouncements
On May 28, 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 is a comprehensive revenue recognition standard that will supersede nearly all existing revenue recognition guidance under current U.S. GAAP and replace it with a principle based approach for determining revenue recognition. ASU 2014-09 will require that companies recognize revenue based on the value of transferred goods or services as they occur in the contract. The ASU also will require additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. These updates are effective for annual reporting periods beginning after December 15, 2018 (December 15, 2017 for public entities) and interim periods within those annual periods. Early adoption is permitted. The Company has not yet selected a transition method and is currently evaluating the effect of the standard on its ongoing financial reporting.
In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory (“ASU 2015-11”). The standard requires that an entity should measure inventory at the lower of cost and net realizable value. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, and should be applied prospectively. Early adoption was permitted and the Company adopted ASU 2015-11 during the three months ended December 31, 2015. Adoption of the standard did not have a material impact on the Company’s results of operations.
In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805), Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). ASU 2015-16 requires that the cumulative impact of a measurement period adjustment (including the impact on prior periods) be recognized in the reporting period in which the adjustment is identified. The new standard is effective for annual reporting periods beginning after December 15, 2017 (December 15, 2016 for public entities) and interim periods within those annual periods. Early adoption is permitted. The Company adopted ASU 2015-16 during the period from July 26, 2016 to December 31, 2016.

F-18


In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740), Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). The standard requires companies to classify all deferred tax assets and liabilities as noncurrent in a classified statement of financial position. The new standard is effective for annual periods beginning after December 15, 2017 (December 15, 2016 for public entities) and interim periods within annual periods beginning after December 15, 2018. Early adoption is permitted and the Company adopted ASU 2015-17 during the period from July 26, 2016 to December 31, 2016.
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 address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. ASU 2016-01 is effective for annual periods beginning after December 15, 2018 (December 15, 2017 for public entities) and interim periods within those annual periods. Early adoption is not permitted. The Company is currently evaluating the impact this guidance will have on financial statements and disclosures.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). ASU 2016-02 is a comprehensive new lease standard that amends various aspects of existing guidance for leases and requires additional disclosures about leasing arrangements. It will require lessees to recognize lease assets and lease liabilities for those leases classified as operating leases under previous GAAP. Topic 842 retains a distinction between finance leases and operating leases. It is effective for annual periods beginning after December 15, 2019 (December 15, 2018 for public entities) and interim periods within those annual periods. Early adoption is permitted. In the financial statements in which the ASU is first applied, leases shall be measured and recognized at the beginning of the earliest comparative period presented with an adjustment to equity. Practical expedients are available for election as a package and if applied consistently to all leases. The Company is currently evaluating the impact this guidance will have on financial statements and disclosures.
In March 2016, the FASB issued ASU 2016-09 Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The areas for simplification in this Update involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2017 (December 15, 2016 for public entities), and interim periods within annual periods beginning after December 15, 2018. Early adoption is permitted and the Company adopted ASU 2016-09 during the period from July 26, 2016 to December 31, 2016. Adoption of the standard did not have a material impact on the Company’s results of operations.
In August 2016, the FASB issued ASU 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) (“ASU 2016-15”). The amendments in this Update provide guidance on the presentation of certain issues in the statement of cash flows. ASU 2016-15 is effective for annual reporting periods beginning after December 15, 2018 (December 15, 2017 for public entities), and interim periods within fiscal years beginning after December 15, 2019. Early adoption is permitted. The Company has not yet selected a transition method and is still evaluating the effect of the standard on its ongoing financial reporting.
In October 2016, the FASB issued ASU 2016-16 Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory (“ASU 2016-16”). The amendments in this Update address the income tax accounting of intra-entity transfers. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2018 (December 15, 2017 for public entities), and interim periods within fiscal years beginning after December 15, 2019. Early adoption is permitted in the first interim period of a fiscal year. The Company does not expect a material impact on its financial statements and disclosures.
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. ASU 2016-18 is effective for annual reporting periods beginning after December 15, 2018 (December 15, 2017 for public entities), and interim periods within annual periods beginning after December 15, 2019

F-19


(December 15, 2017 for public entities). Early adoption is permitted. The Company is currently evaluating the impact this guidance will have on financial statements and disclosures.
In January 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805) (“ASU 2017-01”). The amendments in this Update provide guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for annual reporting periods beginning after December 15, 2018 (December 15, 2017 for public entities), and interim periods within annual periods beginning after December 15, 2019 (December 15, 2017 for public entities). The Company is currently evaluating the impact this guidance will have on financial statements and disclosures.
In March 2017, the FASB issued ASU 2017-07 Compensation - Retirement Benefits (Topic 715) (“ASU 2017-07”). The amendments in this Update provide guidance on the presentation of retirement benefits. ASU 2017-07 is effective for annual reporting periods beginning after December 15, 2018 (December 15, 2017 for public entities), and interim periods within annual periods beginning after December 15, 2019 (December 15, 2017 for public entities). The Company is currently evaluating the impact this guidance will have on financial statements and disclosures.
(3) Acquisition
On July 26, 2016, a consortium of former Alpha creditors acquired Company 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, Contura purchased certain former core coal operations of Alpha as further described in Note 1.  As consideration for the purchased assets, in addition to the assumption by Contura of certain assumed liabilities and the credit release by former Alpha creditors, Contura delivered to Alpha the following consideration: (i) 10,000,000 shares of Contura common stock with a fair value of $44,644 (representing 100% of the issued and outstanding Contura common stock at that time), (ii) a promissory note with a face amount of $300,000 and fair value of $285,936 (the “Buyer Takeback Paper” or “Senior Secured First Lien Notes”), (iii) a promissory note with a face amount of $5,500 and fair value of $4,208 (the “GUC Distribution Note”) and warrants to acquire 810,811 shares of Contura common stock with a fair value of $1,167. Contura is accounting for the acquisition as a business combination.
Purchase Price
The purchase price of $335,955 consisted of the following:
Fair value of common stock issued
$
44,644

Issuance of 10% Senior Secured First Lien Notes (net of discount of $14,064)
285,936

Issuance of GUC Distribution Note (net of discount of $1,292)
4,208

Issuance of warrants
1,167

Purchase price
$
335,955


F-20


Allocation of Purchase Price
The total purchase price has been preliminarily allocated to the net tangible and intangible assets as of July 26, 2016 as follows:
Cash and cash equivalents
$
51,000

Trade accounts receivable
68,355

Inventories
43,705

Assets held for sale
2,178

Prepaid expenses and other current assets
36,493

Property, plant, and equipment
348,407

Other acquired intangibles
149,000

Long-term restricted cash
92,800

Long-term deposits
94

Other non-current assets
3,688

Total assets
$
795,720

 
 
Current portion of long-term debt
$
1,112

Trade accounts payable
39,993

Acquisition-related obligations - current (1)
42,235

Accrued expenses and other current liabilities
42,905

Long-term debt
11,720

Acquisition-related obligations - long-term (1)
59,092

Asset retirement obligations
196,487

Other non-current liabilities
58,502

Total liabilities
452,046

 
 
Bargain purchase gain
7,719

 
 
Allocation of purchase price
$
335,955

______________
(1)
See Note 12.
The above purchase price allocation includes provisional amounts for certain assets and liabilities. The purchase price allocation will continue to be refined during the one-year measurement period, which will end no later than July 26, 2017, under acquisition accounting primarily in the area of income taxes and other contingencies. During the measurement period, the Company expects to receive additional detailed information to refine the provisional allocation presented above.
Through the acquisition, the Company recognized a bargain purchase gain of $7,719 which resulted from the excess of the fair value of the acquired assets over liabilities assumed through the acquisition. The bargain purchase gain was recognized within other income (expense) within the Consolidated Statements of Operations for the period from July 26, 2016 to December 31, 2016. The bargain purchase gain is not recognized for tax purposes.

F-21


(4) Accumulated Other Comprehensive Income (Loss)
The following tables summarize the changes to accumulated other comprehensive income (loss) during the period from July 26, 2016 to December 31, 2016, for the period from January 1, 2016 to July 25, 2016, and for the years ended December 31, 2015, and 2014:
 
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

 
Predecessor
 
Balance
January 1, 2015
 
Other comprehensive
income (loss) before reclassifications
 
Amounts reclassified
from accumulated other comprehensive income (loss)
 
Balance
December 31, 2015
Employee benefit costs
$
5,730

 
$
(1,872
)
 
$
277

 
$
4,135

Cash flow hedges
(1,013
)
 
—

 
1,013

 
—

 
$
4,717

 
$
(1,872
)
 
$
1,290

 
$
4,135

 
Predecessor
 
Balance
January 1, 2014
 
Other comprehensive
income (loss) before reclassifications
 
Amounts reclassified
from accumulated other comprehensive income (loss)
 
Balance
December 31, 2014
Employee benefit costs
$
6,007

 
$
(304
)
 
$
27

 
$
5,730

Cash flow hedges
(1,081
)
 
—

 
68

 
(1,013
)
 
$
4,926

 
$
(304
)
 
$
95

 
$
4,717


F-22


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 period from July 26, 2016 to December 31, 2016, for the period from January 1, 2016 to July 25, 2016, and for the years ended December 31, 2015, and 2014:
Details about accumulated other comprehensive income (loss) components
Amounts reclassified from accumulated other comprehensive income (loss)
Affected line item in the Statements of Operations
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31,
 
 
2015
 
2014
 
Employee benefit costs:
 
 
 
 
 
 
 
 
 
 
Amortization of actuarial loss
$
—

 
 
$
206

 
$
121

 
$
41

 
(1) 
Amortization of prior service credit
—

 
 
824

 
181

 
—

 
(1) 
Other
—

 
 
2,712

 
—

 
—

 
(1) 
Total before income tax
—

 
 
3,742


302

 
41

 
 
Income tax expense
—

 
 
(1,345
)
 
(25
)
 
(14
)
 
Income tax benefit
Total, net of income tax
$
—

 
 
$
2,397

 
$
277

 
$
27

 
 
 
 
 
 
 
 
 
 
 
 
 
Cash flow hedges:
 
 
 
 
 
 
 
 
 
 
Commodity swaps-diesel fuel
—

 
 
—

 
1,455

 
102

 
Cost of coal sales
Total before income tax
—

 
 
—

 
1,455

 
102

 
 
Income tax expense
—

 
 
—

 
(442
)
 
(34
)
 
Income tax benefit
Total, net of income tax
$
—

 
 
$
—

 
$
1,013

 
$
68

 
 
______________
(1)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit costs for black lung. See Note 18.

(5) Earnings (Loss) Per Share
The number of shares used to calculate basic earnings per common share is based on the weighted average number of the Company’s outstanding common shares during the respective periods. The number of shares used to calculate diluted earnings per common share is based on the number of common shares used to calculate basic earnings per share plus the dilutive effect of stock options and other stock-based instruments held by the Company’s employees and directors during each period, and the Company’s outstanding Series A warrants. The warrants become dilutive for earnings per common share calculations when the market price of the Company’s common stock exceeds the exercise price. In periods of net loss, the number of shares used to calculate diluted earnings per share is the same as basic earnings per share.

F-23


(6) Inventories, net
Inventories, net consisted of the following: 
 
Successor
 
 
Predecessor
 
December 31,
2016
 
 
December 31,
2015
Raw coal
$
5,055

 
 
$
4,502

Saleable coal
58,376

 
 
47,401

Materials, supplies and other, net
11,968

 
 
14,602

Total inventories, net
$
75,399

 
 
$
66,505

(7) Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consisted of the following:
 
Successor
 
 
Predecessor
 
December 31,
2016
 
 
December 31,
2015
Prepaid insurance
$
2,073

 
 
$
4,425

Insurance and indemnification receivables
—

 
 
3,600

Maintenance and repairs contract
3,480

 
 
1,477

Deferred longwall move expenses
5,264

 
 
6,963

Refundable income taxes
1,305

 
 
—

Prepaid property tax
2,804

 
 
1,698

Prepaid freight
9,065

 
 
4,106

Other non-trade receivables
4,146

 
 
—

Other prepaid expenses
9,418

 
 
7,926

Total prepaid expenses and other current assets
$
37,555

 
 
$
30,195


F-24


(8) Property, Plant, and Equipment, Net
Property, plant, and equipment, net consisted of the following: 
 
Successor
 
 
Predecessor
 
December 31,
2016
 
 
December 31,
2015
Plant and mining equipment
$
171,846

 
 
$
848,145

Owned and leased mineral rights (1)
126,219

 
 
1,310,249

Mine development
10,750

 
 
156,866

Land
24,684

 
 
66,412

Office equipment, software and other
978

 
 
6,867

Construction in progress
34,009

 
 
7,851

Total property, plant, and equipment
368,486

 
 
2,396,390

Less accumulated depreciation, depletion and amortization
51,473

 
 
903,000

Total property, plant, and equipment, net
$
317,013

 
 
$
1,493,390

______________
(1)
Amount at December 31, 2016 relates to asset retirement obligation assets associated with active mining operations. Amount at December 31, 2015 relates to asset retirement obligation assets associated with active mining operations as well as actual mining property and mineral rights.

Included in plant and mining equipment are assets under capital leases totaling $2,888 and $2,291 with accumulated depreciation of $231 and $2,127 as of December 31, 2016 and 2015, respectively.
Depreciation, depletion and amortization expense associated with property, plant and equipment, net was $43,978 for the period from July 26, 2016 to December 31, 2016, $85,379 for the period January 1, 2016 to July 25, 2016 and $202,115 and $203,361 for the years ended December 31, 2015 and 2014, respectively. Depreciation expense for the period from July 26, 2016 to December 31, 2016 and the years ended December 31, 2015 and 2014 includes a credit of ($7,656), ($1,774) and ($11,158), respectively, related to revisions to asset retirement obligations. See Note 13 for further disclosures related to asset retirement obligations.
(9) 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. As a result of a longer than expected recovery in the met coal markets and lower production and shipment levels compared with previous estimates and announcements made regarding plans to curtail certain coal mining operations, the Company determined that indicators of impairment with respect to certain of its long-lived assets or asset groups existed during the year ended December 31, 2015. 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.
The Company performed a long-lived asset impairment test as of December 31, 2015 and determined that the undiscounted cash flows were less than the carrying value for certain asset groups. For the year ended December 31, 2015, the Company recorded $556,165 in impairment charges, of which $72,012 was recorded for asset groups in Central Appalachia Operations (“CAPP”), $224,139 was recorded for asset groups in Northern Appalachia Operations (“NAPP”), $260,011 was recorded on asset groups in Powder River Basin Operations (“PRB”), and $3 was recorded on asset groups in Trading and Logistics Operations.

F-25


For the period ended July 25, 2016, and year ended December 31, 2015 and 2014, the Company recorded severance expenses and other restructuring-related charges of $1,614, $2,445, and $10,084, respectively. Of these amounts, $600, $1,550, and $1,092 were recorded on CAPP and $334, ($458), and $8,862 were recorded on NAPP for period ended July 25, 2016, and years ended December 31, 2015 and 2014, respectively.
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 and NAPP, respectively. For the year ended December 31, 2015, the Company recorded losses related to non-core property divestitures of $89, of which $21 and $39 related to CAPP and NAPP, respectively. For the year ended 2014, the Company recorded a gain on non-core property divestitures of ($3,235), all of which related to assets within the NAPP segment.
There were no asset impairments or restructuring charges during the period from July 26, 2016 to December 31, 2016.
(10) Accrued Expenses and Other Current Liabilities
Accrued expenses and other current liabilities consisted of the following: 
 
Successor
 
 
Predecessor
 
December 31,
2016
 
 
December 31,
2015
Wages and benefits
$
32,020

 
 
$
24,259

Current portion of asset retirement obligations
4,298

 
 
10,155

Taxes other than income taxes
13,208

 
 
35,385

Interest payable
13,574

 
 
—

Deferred revenue
3,780

 
 
3,510

Maintenance and repairs contract liability
8,541

 
 
114

Freight accrual
3,006

 
 
1,225

Other
12,437

 
 
20,883

Total accrued expenses and other current liabilities
$
90,864

 
 
$
95,531

(11) Long-Term Debt
Long-term debt consisted of the following: 
 
Successor
 
 
Predecessor
 
December 31,
2016
 
 
December 31,
2015
Term Facility (1)
$
42,500

 
 
$
—

LC Facility
—

 
 
—

Closing Tranche Term Loan - due January 2018 (1)
8,500

 
 
—

GUC Distribution Note - due January 2018 (1)
5,500

 
 
—

10% Senior Secured First Lien Notes - due August 2021 (1)
300,000

 
 
—

Other
7,024

 
 
136

Debt discount and issuance costs
(14,363
)
 
 
—

Total long-term debt (2)
349,161

 
 
136

Less current portion
(2,324
)
 
 
(68
)
Long-term debt, net of current portion
$
346,837

 
 
$
68


F-26


______________
(1)
On March 17, 2017, the Company entered into a $400,000 Term Loan Credit Facility with a maturity date on March 17, 2024. In connection with the transaction, the Company paid all of its outstanding 10.00% Senior Secured First Lien Notes due 2021. The proceeds of the Term Loan Credit Facility were also used to repay the Term Facility due 2020, the Closing Tranche Term Loan due 2018 and the GUC Distribution Note due 2018. See Note 26 for further disclosures on this subsequent event.
(2)
On April 3, 2017, the Company entered into an Asset-Based Revolving Credit Agreement, under which the Company may borrow cash or draw letters of credit from, on a revolving basis, in an amount up to $125,000, subject to certain limitations set forth therein. Any borrowings under the asset-based revolving credit facility will have a maturity date of April 4, 2022 and will bear interest at rates ranging from 1.00% to 2.50% depending on loan type. No letters of credit were outstanding, no cash borrowing transactions had taken place and $125,000 was available under the facility. See Note 26 for further disclosures on this subsequent event.

Asset-Based Term Loan Credit Agreement
On July 26, 2016, the Company entered into an Asset-Based Term Loan Credit Agreement (“ABL Facility”) with Credit Suisse Loan Funding LLC, as lender, Wilmington Trust, National Association, as administrative agent and collateral agent, and Citigroup Global Markets Inc., as sole lead arranger. Under the ABL Facility, the lender provided commitments to the Company for (i) the term loan credit facility (“Term Facility”) in an aggregate principal amount of $42,500, (ii) a cash collateralized letter of credit facility (“LC Facility”), which provided for the issuance of letters of credit secured by 105% cash collateral, and (iii) the Closing Tranche Term Loan, in each case, on the terms and subject to the conditions set forth therein. These commitments by the lender were secured by certain eligible accounts receivable and eligible inventory.
Loans under the Term Facility had an interest rate of LIBOR plus a margin of 5% (subject to a LIBOR floor of 1%) and matured on July 26, 2020. The LC Facility was available at any time and from time to time commencing on the effective date until five days prior to the LC termination date of July 26, 2020. The Closing Tranche Term Loan had an aggregate principal amount of $8,500, an interest rate of LIBOR plus a margin of 5% (subject to a LIBOR floor of 1%), and a maturity of January 26, 2018. As of December 31, 2016, the interest rate of the Closing Tranche Term Loan was 6%.
The Company did not have any letters of credit outstanding under the LC Facility as of December 31, 2016.
GUC Distribution Note
On July 26, 2016, the Company entered into a $5,500 promissory note (“GUC Distribution Note”) agreement with U.S. Bank National Association, as nominee and agent for the benefit of the holders of Allowed Category I General Unsecured Claims pursuant to the Alpha restructuring. The GUC Distribution Note had no interest and a maturity date of January 26, 2018.
10% Senior Secured First Lien Notes
On July 26, 2016, the Company and Wilmington Trust, National Association, as trustee and collateral agent, entered into an indenture governing the Company’s issuance of the 10.00% Senior Secured First Lien Notes (“Senior Secured First Lien Notes”), initially in an aggregate principal amount of $300,000.
Unless earlier paid or deemed paid, the Senior Secured First Lien Notes had a maturity of August 1, 2021 (the “Maturity Date”), and, on the Maturity Date, the Company would have paid each holder of notes $1 in cash for each $1 principal amount of the Senior Secured First Lien Notes held, together with accrued and unpaid interest to, but not including, the Maturity Date. The Senior Secured First Lien Notes accrued interest at a rate equal to 10% per annum from the most recent date to which interest had been paid or duly provided for, or, if no interest had been paid or duly provided for, the issue date, until the date the principal amount of such Senior Secured First Lien Notes was paid or deemed paid. Interest was payable semi-annually in arrears on February 1 and August 1 of each year,

F-27


beginning February 1, 2017, to the registered holder of each such Senior Secured First Lien Note as of the close of business on January 15 and July 15, as the case may have been, immediately preceding the applicable interest payment date (each such date, a “Regular Record Date”), regardless of whether such Senior Secured First Lien Note was repurchased or redeemed after such Regular Record Date. Interest was computed on the basis of a 360-day year comprised of twelve 30-day months. The Senior Secured First Lien Notes collateral included a first-priority lien on all assets except for certain excluded assets, as defined in the indenture relating to the Senior Secured First Lien Notes, other than the ABL Facility collateral, and a secondary-priority lien on the ABL Facility collateral.
The ABL Facility, the GUC Distribution Note, the Senior Secured First Lien Notes and related documents contained affirmative and negative covenants with no financial covenants. The Company was in compliance with all covenants under these agreements as of December 31, 2016.
Capital Leases
The Company entered into capital leases for certain property and other equipment during 2016 and 2015. The Company’s liability for capital leases totaled $2,745 and $136, with $1,007 and $68 reported as the current portion of long-term debt as of December 31, 2016 and 2015, respectively.
Future Maturities
Future maturities of long-term debt as of December 31, 2016 are as follows: 
2017
$
2,324

2018
17,928

2019
772

2020
42,500

2021
300,000

Total long-term debt
$
363,524

(12) Acquisition-Related Obligations
Acquisition-related obligations consisted of the following:
 
December 31,
2016
Retiree Committee VEBA Funding Settlement Liability
$
10,000

UMWA Funds Settlement Liability
7,500

UMWA VEBA Funding Settlement Liability
9,300

UMWA Contingent VEBA Funding Note 1
8,750

UMWA Contingent VEBA Funding Note 2
8,750

Reclamation Funding Liability
42,000

Contingent Reclamation Funding Liability
20,370

Contingent Credit Support Commitment
4,567

Other
2,261

Discount
(27,152
)
Total acquisition-related obligations - long-term
86,346

Less current portion
(27,258
)
Acquisition-related obligations, net of current portion
$
59,088


F-28


The Company entered into various settlement agreements with Alpha and/or the Alpha bankruptcy successor ANR, Inc. (“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.
Contingent Credit Support Commitment
The Contingent Credit Support Commitment (“Contingent Commitment”) is an unsecured obligation to ANR that requires the Company to provide ANR with revolving credit support in an aggregate total amount of $35,000 from July 26, 2016 (“Effective Date”) through September 30, 2018. ANR is entitled to draw against the Contingent Commitment if, and only if, the amount of cash and cash equivalents on ANR’s balance sheet falls below $20,000 at any time prior to September 30, 2018 (the amount of any such shortfall, the “Shortfall”), in which case, ANR is entitled to draw against the Contingent Commitment an amount equal to the lesser of the Shortfall and the then-remaining undrawn amount of the Contingent Commitment. ANR is able to draw upon and repay the Contingent Commitment as necessary through September 30, 2018. The Company must fund a draw on the Contingent Commitment within 10 business days of notice from ANR. ANR will be required to repay the funds drawn against the Contingent Commitment (i) prior to September 30, 2018 to the extent the amount of cash and cash equivalents on ANR’s balance sheet is greater than $20,000 as of the end of any calendar quarter ending on or before September 30, 2018 (exclusive of the amount outstanding from the Contingent Commitment) or (ii) if any amounts are outstanding under the Contingent Commitment after September 30, 2018, to the extent the amount of cash and cash equivalents on ANR’s balance sheet at the end of any calendar quarter is greater than $30,000 (exclusive of the amount outstanding from the Contingent Commitment), within 10 business days following the closing of its books for the relevant calendar quarter. Notwithstanding the above, all outstanding balances under the Contingent Commitment must be repaid by September 30, 2019.
As of December 31, 2016, ANR had not drawn against the Contingent Commitment. The Company is electing to use the fair value option to measure this liability at each reporting period. During the period from July 26, 2016 to December 31, 2016, the Company recorded a mark to market non-cash gain of $17,386, which is classified as other operating income in the Consolidated Statement of Operations. As of December 31, 2016, the fair value of the Contingent Commitment was $4,567, all of which is classified as a loan commitment within acquisition-related obligations - current in the Consolidated Balance Sheet.
Retiree Committee VEBA Funding Settlement
The Retiree Committee Settlement Agreement requires the Company to provide funding to the voluntary employees’ beneficiary association fund (“VEBA”) established by the retiree committee, which represented the interests of certain non-union Alpha retirees during the Alpha bankruptcy case, in an aggregate nominal amount of $13,000 (the “Retiree Committee VEBA Funding Settlement Liability”) for the benefit of the VEBA beneficiaries pursuant to the following schedule: (a) $3,000 within 10 business days after the later of the Effective Date or Alpha Natural Resources, Inc. and such subsidiaries (“Debtors”)receipt of written notice; (b) $3,000 on January 1, 2017; (c) $3,500 on January 1, 2018; (d) $2,500 on January 1, 2019; and (e) $1,000 on January 1, 2020. The initial $3,000 installment was paid as part of the Alpha bankruptcy settlement process and is therefore not reflected in the cash flows of the Company for the period from July 26, 2016 to December 31, 2016.
As of December 31, 2016, the carrying value of the Retiree Committee VEBA Funding Settlement liability is $8,260, net of discount of $1,740, and was classified as an acquisition-related obligation, with $3,000 classified as current in the Consolidated Balance Sheet. 
UMWA Funds Settlement
The United Mine Workers of America (“UMWA”) Funds Settlement (“UMWA Funds Settlement”) provides for the Coal Act Funds, the 1974 Pension Plan, the 1993 Benefit Plan, the CDSP and the Account Plan (collectively, the “UMWA Funds”) to receive an initial distribution of $2,500 in cash (to be allocated among the UMWA Funds by the UMWA Funds in their discretion) on the Effective Date. The Company is required to make periodic cash payments

F-29


(to be allocated among the UMWA Funds by the UMWA Funds in their discretion) on the dates and in the amounts listed: December 31, 2017: $500; December 31, 2018: $1,000; December 31, 2019: $2,000; December 31, 2020: $2,000; December 31, 2021: $2,000. The initial distribution of $2,500 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, 2016, the carrying value of the UMWA Funding Settlement liability was $4,050, net of discount of $3,450, and was classified as an acquisition-related obligation, with $500 classified as current in the Consolidated Balance Sheet. 
UMWA VEBA Funding and Contingent Notes Settlements
UMWA VEBA Funding
Pursuant to the UMWA VEBA Funding Settlement agreement entered into on July 5, 2016, the Company was required to contribute $10,000 to a voluntary employees’ beneficiary association fund (the “VEBA trust”) on or before the Effective Date. Beginning on November 1, 2016, and again on the first of each month through April 1, 2017, the Company is required to deposit $3,000 into the VEBA trust (total of $18,000 in six monthly payments). On or before November 15, 2016, and February 15, 2017 the Company is required to deposit $300 into the VEBA trust (total of $600 in two payments). The initial $10,000 contribution 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. During the period from July 26, 2016 to December 31, 2016, the Company made $9,300 of the required deposits, all of which was classified as operating activities in the Consolidated Statement of Cash Flows.
As of December 31, 2016, the carrying value of the UMWA VEBA Funding Settlement liability is $9,037, net of discount of $263, all of which was classified as an acquisition-related obligation - current in the Consolidated Balance Sheet. 
UMWA Contingent VEBA Funding Notes 
Pursuant to the UMWA VEBA Funding Settlement agreement entered into on July 5, 2016, if federal legislation providing retirement benefits to the UMWA Retirees has not been enacted or if monies under the legislation have not become available for the benefits before August 1, 2017, on August 1, 2017, the Company is required to issue to the VEBA a 7-year 5% unsecured note (“UMWA Contingent VEBA Funding Note 1”) with a face value of $8,750. The note will have a maturity of 7 years and will be subordinate to the Company’s Senior Secured First Lien Notes.
As of December 31, 2016, the carrying value of the UMWA Contingent VEBA Funding Note 1 was $4,307, net of discount of $4,443, all of which was classified as an acquisition-related obligation - long-term in the Consolidated Balance Sheet. 
If federal legislation providing retirement benefits to the UMWA Retirees has not been enacted or if moneys under the legislation have not become available for the benefits before December 1, 2017, on December 1, 2017, the Company is also required to issue to the VEBA a 7-year 5% unsecured note (“UMWA Contingent VEBA Funding Note 2”) with a face value of $8,750. The note will have a maturity of 7 years and will be subordinate to the Company’s Senior Secured First Lien Notes.
As of December 31, 2016, the carrying value of the UMWA Contingent VEBA Funding Note 2 was $4,270, net of discount of $4,480, all of which was classified as an acquisition-related obligation - long-term in the Consolidated Balance Sheet. 
Reclamation Funding Agreement
Pursuant to the Reclamation Funding Agreement dated July 12, 2016, separate interest bearing segregated deposit accounts (“Restricted Cash Reclamation Accounts”) were established for certain applicable federal and state

F-30


environmental regulatory authorities to provide certain funding for the reclamation, mitigation and water treatment, and certain management work to be done at reclaim-only sites related to certain obligations under the various permits associated with ANR’s retained assets.
Funding of Restricted Cash Reclamation
Pursuant to the Reclamation Funding Agreement, 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; $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, 2016, the carrying value of the Funding of Restricted Cash Reclamation liability is $29,223, net of discount of $12,777, with $10,000 classified as current, all of which was classified as an acquisition-related obligation in the Consolidated Balance Sheet. 
Contingent Funding of Restricted Cash Reclamation
Pursuant to the Reclamation Funding Agreement, under certain circumstances, the Company will be required to pay up to an aggregate amount of $50,000 into various Restricted Cash Reclamation Accounts from 2021 through 2025 as follows: (i) if ANR does not contribute $50,000 of free cash flow, as defined in the agreement, into the Restricted Cash Reclamation Accounts through December 31, 2020; and (ii) if ANR makes any reorganized ANR contingent revenue payment, as defined in the agreement, that reduces the amount of free cash flow that ANR otherwise would have contributed to the Restricted Cash Reclamation Accounts, then the Company will be obligated to pay the amount of the difference between (a) the amount of free cash flow that ANR would have contributed to the Restricted Cash Reclamation Accounts had it not made such reorganized ANR contingent revenue payment and (b) the amount of free cash flow actually contributed.
The Company is electing to use the fair value option to measure this liability at each reporting period. During the period from July 26, 2016 to December 31, 2016, the Company recorded a mark to market non-cash loss of $6,770 which is classified as other operating income (loss) in the Consolidated Statement of Operations. As of December 31, 2016, the carrying value of the Contingent Funding of Restricted Cash Reclamation liability was $20,370, all of which was classified as an acquisition-related obligation - long-term in the Consolidated Balance Sheet. 
(13) Asset Retirement Obligations
As of December 31, 2016 and 2015, the Company had recorded asset retirement obligation accruals for mine reclamation and closure costs totaling $191,395 and $176,349, respectively. The portion of the costs expected to be paid within a year of $4,298 and $10,155 as of December 31, 2016 and 2015, respectively, is included in accrued expenses and other current liabilities. See Note 22 for information regarding the Company’s outstanding surety bonds.  

F-31


Changes in the asset retirement obligations were as follows:
Predecessor
 
Total asset retirement obligations at December 31, 2014
$
161,021

Accretion for the period
17,897

Revisions in estimated cash flows (1)
1,050

Expenditures for the period
(3,619
)
Total asset retirement obligations at December 31, 2015
$
176,349

Accretion for the period
12,422

Asset sales
(53
)
Revisions in estimated cash flows
(23
)
Expenditures for the period
(2,143
)
Total asset retirement obligations at July 25, 2016
$
186,552


Successor
 
Total asset retirement obligations at July 26, 2016
$
204,326

Accretion for the period
10,819

Revisions in estimated cash flows (2)
(23,236
)
Expenditures for the period
(514
)
Total asset retirement obligations at December 31, 2016
$
191,395

Less current portion
(4,298
)
Long-term portion
$
187,097

______________
(1) Amount includes ($1,774), primarily related to changes to the estimated costs and timing of future cash flows for sites with no remaining asset values and changes in the discount rate, offset by an increase in estimated steam restoration costs within the Northern Appalachia Operations segment, which was recorded as a reduction to depreciation, depletion, and amortization in the Statements of Operations for the year ended December 31, 2015.
(2) Amount includes ($7,656), primarily related to a reduction in estimated steam restoration costs within the Northern Appalachia Operations segment, which was recorded as a reduction to depreciation, depletion, and amortization in the Statements of Operations for the period from July 26, 2016 to December 31, 2016.


F-32


(14) Other Non-Current Liabilities
Other non-current liabilities consisted of the following: 
 
Successor
 
 
Predecessor
 
December 31,
2016
 
 
December 31,
2015
Workers’ compensation obligations
$
17,008

 
 
$
20,895

Black lung obligations
13,501

 
 
23,814

Warrants (1)
35,141

 
 
—

Life insurance benefits
11,687

 
 
—

Deferred coal revenue
1,000

 
 
12,147

Taxes other than income taxes
6,590

 
 
9,636

Other
12,967

 
 
488

Total other non-current liabilities
$
97,894

 
 
$
66,980

______________
(1)
See Note 16.

(15) 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, long-term restricted cash, long-term deposits, trade accounts payable, and accrued expenses and other current liabilities approximate fair value as of December 31, 2016 and 2015 due to the short maturity of these instruments.
The following table sets forth by level, within the fair value hierarchy, the Company’s long-term debt at fair value as of December 31, 2016:
 
Successor
 
December 31, 2016
 
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 Facility
$
42,164

 
$
42,164

 
$
—

 
$
42,164

 
$
—

Closing Tranche Term Loan - due January 2018
8,500

 
8,500

 
—

 
—

 
8,500

GUC Distribution Note - due January 2018
4,546

 
4,967

 
—

 
—

 
4,967

10% Senior Secured First Lien Notes - due August 2021
286,927

 
320,625

 
320,625

 
—

 
—

Total long-term debt
$
342,137

 
$
376,256

 
$
320,625

 
$
42,164

 
$
13,467

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

The following table sets forth by level, within the fair value hierarchy, the Company’s acquisition-related obligations at fair value as of December 31, 2016:

F-33


 
Successor
 
December 31, 2016
 
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
$
8,260

 
$
8,937

 
$
—

 
$
—

 
$
8,937

UMWA Funds Settlement Liability
4,050

 
5,100

 
—

 
—

 
5,100

UMWA VEBA Funding Settlement Liability
9,037

 
9,156

 
—

 
—

 
9,156

UMWA Contingent VEBA Funding Note 1
4,307

 
5,381

 
—

 
—

 
5,381

UMWA Contingent VEBA Funding Note 2
4,270

 
5,206

 
—

 
—

 
5,206

Reclamation Funding Liability
29,223

 
33,549

 
—

 
—

 
33,549

Total acquisition-related obligations
$
59,147

 
$
67,329

 
$
—

 
$
—

 
$
67,329

______________
(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, 2016. 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.
 
Successor
 
December 31, 2016
 
Total Fair
Value
 
Quoted Prices
in Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
Warrants (1)
$
35,141

 
$
—

 
$
—

 
$
35,141

Contingent Credit Support Commitment (2)
4,567

 
—

 
—

 
4,567

Contingent Reclamation Funding Liability (2)
20,370

 
—

 
—

 
20,370

______________
(1) See Note 16 for further disclosures on warrants and the mark-to-market effect on earnings.
(2) See Note 12 for further disclosures on these acquisition-related obligations and their mark to market effect on earnings.

For the period from July 26, 2016 to December 31, 2016, the Company fair valued assets and liabilities on a non-recurring basis in connection with acquisition accounting (see Note 3). 
The Company did not have any long-term debt, acquisition-related obligations or financial and non-financial assets that require fair value disclosure as of December 31, 2015.
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the tables above.

F-34


Level 1 Fair Value Measurements
10% Senior Secured First Lien Notes - due August 2021 - The fair value is based on observable market data.
Level 2 Fair Value Measurements
Term Facility - due July 2020 - The Company believes the carrying value of this obligation is a reasonable estimate of fair value as these obligations were repaid at face value without any premium or discount subsequent to December 31, 2016. The Company also observed limited trading volumes at par as of December 31, 2016.
Level 3 Fair Value Measurements
Closing Tranche Term Loan - due January 2018 - The Company believes the carrying value of this obligation is a reasonable estimate of fair value as these obligations were repaid at face value without any premium or discount subsequent to December 31, 2016.
GUC Distribution Note - due January 2018, Retiree Committee VEBA Funding Settlement Liability, UMWA Funds Settlement Liability, VEBA Funding Settlement Liability, UMWA Contingent VEBA Funding Note 1, UMWA Contingent VEBA Funding Note 2 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 Credit Support Commitment - Observable transactions are not available to aid in determining the fair value of this commitment. The fair value of the Contingent Credit Support Commitment was derived by using the present value of the Company’s estimated obligation to provide ANR with revolving credit support, discounted using the Company’s credit-adjusted risk-free borrowing rate. The Company’s estimated obligation to provide ANR with revolving credit support was derived based on a probability-weighted analysis of scenarios developed from ANR’s projected cash flows. The present value of the Company’s estimated obligation is calculated net of present value of the anticipated ANR repayments, discounted using an estimate of ANR’s weighted average cost of capital.
Contingent Reclamation Funding Liability - Observable transactions are not available to aid in determining the fair value of this obligation. The fair value of the Contingent Reclamation Funding Liability was derived by aggregating the present value of the Company’s estimated cash flow payments into the various Restricted Cash Reclamation Accounts, using the Company’s credit-adjusted risk free rate. The Company’s estimated cash flow payments were reduced by the present value of the expected ANR cash flow payments into the various Restricted Cash Reclamation Accounts, discounted at an estimate of ANR’s weighted average cost of capital.
Warrants - The fair value of the warrants liability 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 OTC market price, the stated exercise price, the remaining time to maturity, the annual risk-free interest rate based on the US Constant Maturity 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.
Long-lived assets - The fair values of certain asset groups were estimated using a discounted cash flow analysis utilizing market-place participant assumptions.

F-35


(16) Derivative Financial Instruments
Swap Agreements
The Company uses diesel fuel in its production process and incurs significant expenses for its purchases. Diesel fuel expenses represented approximately 3%, 3%, 5% and 6% of cost of coal sales for the period July 26, 2016 to December 31, 2016, for the period January 1, 2016 to July 25, 2016, and for the years ended December 31, 2015 and 2014, respectively. The Company is subject to the risk of price volatility for this commodity and as a part of its risk management strategy, the Company had formerly entered into swap agreements with financial institutions to mitigate the risk of price volatility for diesel fuel. The terms of the swap agreements allowed the Company to pay a fixed price and receive a floating price, which provided a fixed price per unit for the volume of purchases being hedged. All existing swap agreements were terminated in August 2015 due to Alpha’s bankruptcy filing. All cash flows associated with derivative instruments are classified as operating cash flows in the Statements of Cash Flows for the years ended December 31, 2015 and 2014. 
Warrants
On July 26, 2016 (the “Initial Issue Date”), the Company issued 810,811 warrants, each with an initial exercise price 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. The warrants are exercisable for cash or on a cashless basis at any time from the Initial Issue Date until July 26, 2023. The warrants are classified as a derivative liability and are initially and subsequently marked to market with changes in value reflected in earnings.
The following tables present the fair values and location of the Company’s derivative instruments within the Balance Sheets:
 
 
 
 
Liability Derivatives
 
 
 
 
Successor
 
 
Predecessor
Derivatives not designated as
cash flow hedging instruments
 
Statement of Financial Position Location
 
December 31,
 2016
 
 
December 31,
 2015
Warrants
 
Other non-current liabilities
 
$
35,141

 
 
$
—

The following tables present the gains and losses from derivative instruments for the period from July 26, 2016 to December 31, 2016, for the period January 1, 2016 to July 25, 2016, and for the years ended December 31, 2015 and 2014, and their location within the Financial Statements:
Loss reclassified from accumulated other comprehensive income (loss) to earnings
 
 
Successor
 
 
Predecessor
Derivatives designated as
cash flow hedging instruments
 
Period from July 26, 2016 to
December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Commodity swaps (1)(2)
 
$
—

 
 
$
—

 
$
(1,013
)
 
$
(68
)
______________
(1)
Amounts included in cost of coal sales and coal revenues in the Statements of Operations.
(2)
Net of tax.


F-36


Gain (loss) recorded in earnings
 
 
Successor
 
 
Predecessor
Derivatives not designated as
cash flow hedging instruments
 
Period from July 26, 2016 to
December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Commodity swaps (1)
 
$
—

 
 
$
—

 
$
9,344

 
$
(8,892
)
Warrants (2)
 
(33,975
)
 
 
—

 
—

 
—

Total
 
$
(33,975
)
 
 
$
—

 
$
9,344

 
$
(8,892
)
______________
(1)
Amounts are recorded in other expenses within costs and expenses in the Statements of Operations.
(2)
Amount is recorded as a component of other (expense) income in the Statement of Operations.

(17) 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 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. Deferred tax assets and liabilities are presented in these Financial Statements, but the future utilization of tax basis and carryforward attributes may be limited in the event of an ownership change.
Significant components of income tax expense (benefit) were as follows: 
 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31,
2015
 
Year Ended December 31,
2014
Current tax (benefit) expense:
 

 
 
 
 
 

 
 

Federal
$
(390
)
 
 
$
—

 
$
(3,915
)
 
$
13,707

State
202

 
 
—

 
—

 
1,495

 
$
(188
)
 
 
$
—

 
$
(3,915
)
 
$
15,202

Deferred tax (benefit) expense:
 

 
 
 
 
 

 
 

Federal
$
(1,124
)
 
 
$
(27,318
)
 
$
(231,890
)
 
$
(35,042
)
State
(57
)
 
 
(7,571
)
 
(18,790
)
 
2,100

 
$
(1,181
)
 
 
$
(34,889
)
 
$
(250,680
)
 
$
(32,942
)
Total income tax (benefit) expense:
 

 
 
 
 
 

 
 

Federal
$
(1,514
)
 
 
$
(27,318
)
 
$
(235,805
)
 
$
(21,335
)
State
145

 
 
(7,571
)
 
(18,790
)
 
3,595

 
$
(1,369
)
 
 
$
(34,889
)
 
$
(254,595
)
 
$
(17,740
)
 

F-37


A reconciliation of the statutory federal income tax expense (benefit) at 35% to the actual income tax expense (benefit) is as follows:
 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Federal statutory income tax expense (benefit)
$
(4,305
)
 
 
$
(35,735
)
 
$
(235,255
)
 
$
(24,530
)
Increases (reductions) in taxes due to:
 
 
 
 
 
 
 
 
Percentage depletion allowance
(1,096
)
 
 
(7,658
)
 
(17,009
)
 
(22,933
)
State taxes, net of federal tax impact
(353
)
 
 
(1,522
)
 
(15,598
)
 
139

State tax rate and NOL change, net of federal tax benefit
—

 
 
(3,472
)
 
3,294

 
2,138

Change in valuation allowances
(8,802
)
 
 
3,143

 
91

 
60

Non-taxable bargain purchase gain
(2,702
)
 
 
—

 
—

 
—

Non-deductible mark-to-market adjustment - warrant derivative
11,891

 
 
—

 
—

 
—

Non-deductible goodwill impairment
—

 
 
—

 
—

 
24,506

Non-deductible transaction costs
—

 
 
10,028

 
5,109

 
—

Non-deductible stock-based compensation
—

 
 
—

 
3,861

 
2,651

Charitable contribution carryforward expiration
3,537

 
 
—

 
—

 
—

Other, net
461

 
 
327

 
912

 
229

Income tax benefit
$
(1,369
)
 
 
$
(34,889
)
 
$
(254,595
)
 
$
(17,740
)
 

F-38


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
 
 
Predecessor
 
December 31, 2016
 
 
December 31,
2015
Deferred tax assets:
 

 
 
 

Property, plant, and mineral reserves
$
283,301

 
 
$
—

Asset retirement obligations
16,362

 
 
68,374

Reserves and accruals not currently deductible
6,206

 
 
8,763

Workers’ compensation benefit obligations
16,488

 
 
18,973

Deferred revenue
1,728

 
 
6,256

Goodwill
693

 
 
4,032

Equity method investments
5,079

 
 
4,272

Charitable contribution carryforwards
20,808

 
 
—

Loss and credit carryforwards, net of Section 382 limitation
217,509

 
 
26,922

Other
2,114

 
 
3,891

Gross deferred tax assets
570,288

 
 
141,483

Less valuation allowance
(531,054
)
 
 
(153
)
Total net deferred tax assets
39,234

 
 
141,330

Deferred tax liabilities:
 

 
 
 

Property, plant, and mineral reserves
—

 
 
(190,889
)
Acquired intangibles, net
(31,493
)
 
 
(4,660
)
Prepaid expenses
(5,378
)
 
 
(8,328
)
Acquisition-related obligations
(2,043
)
 
 
—

Other
(320
)
 
 
(5,187
)
Total deferred tax liabilities
(39,234
)
 
 
(209,064
)
Net deferred tax liability
$
—

 
 
$
(67,734
)
Changes in the valuation allowance were as follows: 
 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31,
2015
 
Year Ended December 31,
2014
Valuation allowance beginning of period
$
539,856

 
 
$
153

 
$
62

 
$
2

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

 
91

 
60

Valuation allowance end of period
$
531,054

 
 
$
3,296

 
$
153

 
$
62

 
The Company acquired the core assets of Alpha as part of 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, 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

F-39


restructuring. Due to the change in ownership, the net operating loss and other carryforwards are subjected to significant limitations on their use in future years. In addition, the asset purchase agreement states that any refunds or reductions of taxes payable related to income taxes paid in a period prior to July 26, 2016 are payable to ANR.
As of December 31, 2016, the Company has recorded a full valuation allowance against its net deferred tax assets. Due to our formation through acquisition of certain core coal assets as part of the Alpha restructuring, the Company does not have a 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.
At December 31, 2016, the Company has regular tax net operating loss carryforwards for Federal income tax purposes of approximately $566,000 which are available to offset regular Federal taxable income, subject to the annual Internal Revenue Code Section 382 limitation of approximately $1,000. The Federal net operating loss carryforwards will expire between years 2031 and 2035. Because of the annual Section 382 limitation of $1,000, approximately $19,000 of regular tax net operating loss carryforwards will be available to offset regular taxable income between years 2017 and 2035. The Company has capital loss carryforwards of approximately $782,000, of which approximately $442,000 are subject to the annual Section 382 limitation. The capital loss carryforwards expire in year 2021. The Company has alternative minimum tax credit carryforwards of approximately $92,000, which are available to reduce federal regular income tax in excess of the alternative minimum tax, if any, over an indefinite period, subject to the annual Section 382 limitation. To the extent the annual Section 382 limitation of $1,000 is exhausted by the utilization of net operating loss carryforwards in a given year, there is no additional capacity to utilize the capital loss carryforwards or alternative minimum tax credit carryforwards in that year. The Company also has charitable contribution carryforwards of $59,451, which will expire between years 2017 and 2021. The loss and credit carryforward amounts will be refined during the one-year measurement period, as the Company finalizes the impact of the tax-free reorganization transaction.
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, 2016, the Company has recorded accrued interest and penalties of $0 and $0, respectively.
As of December 31, 2016, tax years 2013 - 2016, which include the impact of net operating loss and other carryforwards and tax basis acquired from Alpha, remain open to federal and state examination.
(18) Employee Benefit Plans
Alpha and the Company provided several types of benefits for its employees, including postemployment health care and life insurance, defined benefit and defined contribution pension plans, and workers’ compensation and black lung benefits.
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 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

F-40


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, $41,645 and $43,420 in expenses related to these allocations from Alpha during the period from January 1, 2016 to July 25, 2016 and for the years ended December 31, 2015 and 2014, respectively, which are reflected in cost of coal sales and selling, general and administrative expenses in the Combined Statements of Operations. These expenses are part of the Alpha allocations described in the basis of presentation portion of Note 1.
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 our 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, 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.
Beginning in 2020, 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, and the potential effects of the recent federal election results, in future periods.
The Company is required by federal and state statutes to provide benefits to employees for awards related to workers’ compensation and black lung. Starting July 26, 2016, the Company’s subsidiaries were insured with a high deductible plan for worker’s compensation and black lung obligations by a third-party insurance provider, except for the Company’s operations in Wyoming, where the Company participates 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 Wyoming where the Company participates in a compulsory state-run fund for workers’ compensation. 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.
As of December 31, 2016, 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. Actual losses may differ from these estimates, which could increase or decrease the Company’s costs. Prior to July 26, 2016, the liability for self-insured workers’ compensation claims was an actuarially determined estimate of the undiscounted ultimate losses to be incurred on such claims based on the Company’s experience, and included a provision for incurred but not reported losses. Additionally prior to July 26, 2016, the liability for self-insured black lung benefits was 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.
For the Company’s subsidiaries that are fully insured for workers’ compensation and black lung claims, the insurance premium expense for the period July 26, 2016 to December 31, 2016, for the period January 1, 2016 to July 25, 2016 and for the years ended December 31, 2015 and 2014 was $165, $212, $2,677, and $16,497, respectively. At December 31, 2016, the Company had $21,510 of workers’ compensation liability, including a current portion of $4,502 recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets, primarily related to obligations assumed in the acquisition.

F-41


For the Company’s subsidiaries that were self-insured for workers’ compensation claims prior to July 26, 2016, the liability at December 31, 2015 was $25,000, including a current portion of $4,106 recorded in accrued expenses and other current liabilities in the Combined Balance Sheets. Self-insured workers’ compensation expense for the period from January 1, 2016 to July 25, 2016 and for the years ended December 31, 2015 and 2014 was $281, $698, and $370, respectively. Certain of the Company’s subsidiaries’ self-insured workers’ compensation obligations were secured by letters of credit in the amount of $4,190 as of December 31, 2015.
Workers’ compensation expense for high-deductible insurance plans for the period from July 26, 2016 to December 31, 2016, for the period from January 1, 2016 to July 25, 2016 and for the years ended December 31, 2015 and 2014 was $4,507, $8,318, $14,178, and $675, respectively.
The following tables set forth the accumulated black lung benefit obligations, fair value of plan assets and funded status for the period July 26, 2016 to December 31, 2016, for the period January 1, 2016 to July 25, 2016 and for the year ended December 31, 2015:
 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
Change in benefit obligation:
 
 
 
 
 
 
Accumulated benefit obligation at beginning of period
$
15,158

 
 
$
28,309

 
$
25,828

Service cost
300

 
 
353

 
394

Interest cost
225

 
 
703

 
865

Actuarial loss (gain)
(2,182
)
 
 
4,113

 
(6,852
)
Benefits paid
—

 
 
(838
)
 
(780
)
Plan Amendments
—

 
 
—

 
8,854

Curtailments
—

 
 
(696
)
 
—

Accumulated benefit obligation at end of period
$
13,501

 
 
$
31,944

 
$
28,309

Change in fair value of plan assets:
 
 
 
 
 
 
Fair value of plan assets at beginning of period
$
—

 
 
$
1,831

 
$
1,826

Actual return on plan assets
—

 
 
29

 
5

Benefits paid
—

 
 
(838
)
 
(780
)
Employer contributions
—

 
 
838

 
780

Fair value of plan assets at end of period (1)
—

 
 
1,860

 
1,831

Funded status
$
(13,501
)
 
 
$
(30,084
)
 
$
(26,478
)
Accrued benefit cost at end of period
$
(13,501
)
 
 
$
(30,084
)
 
$
(26,478
)
______________
(1)
Assets of the plan during the Predecessor period were held in a Section 501(c)(21) tax-exempt trust fund and consisted primarily of government debt securities. All assets were classified as Level 1 and valued based on quoted market prices.

F-42


The table below presents amounts recognized in the Balance Sheets:
 
Successor
 
 
Predecessor
 
December 31, 2016
 
 
December 31, 2015
Current liabilities
$
—

 
 
$
2,663

Long-term liabilities
13,501

 
 
23,814

 
$
13,501

 
 
$
26,477

Gross amounts related to the black lung obligations recognized in accumulated other comprehensive (income) loss consisted of the following as of December 31, 2016 and 2015: 
 
Successor
 
 
Predecessor
 
December 31, 2016
 
 
December 31, 2015
Prior service cost
$
—

 
 
$
9,800

Net actuarial loss (gain)
(2,182
)
 
 
(17,045
)
Accumulated Other Comprehensive (Income) Loss
$
(2,182
)
 
 
$
(7,245
)
The following table details the components of the net periodic benefit cost for black lung obligations:
 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31,
2015
 
Year Ended December 31,
2014
Service cost
$
300

 
 
$
353

 
$
394

 
$
780

Interest cost
225

 
 
703

 
865

 
1,190

Expected return on plan assets
—

 
 
(27
)
 
(39
)
 
(52
)
Amortization of net actuarial loss
—

 
 
206

 
121

 
41

Amortization of prior service cost
—

 
 
824

 
181

 
—

Curtailment loss
—

 
 
2,712

 
—

 
—

Net periodic expense
$
525


 
$
4,771

 
$
1,522

 
$
1,959


F-43


Other changes in the black lung plan assets and benefit obligations recognized in other comprehensive (income) loss are as follows:
 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31,
2015
 
Year Ended December 31,
2014
Actuarial loss (gain)
$
(2,182
)
 
 
$
3,415

 
$
(6,818
)
 
$
(670
)
Amortization of net actuarial loss
—

 
 
(206
)
 
(121
)
 
(41
)
Prior service cost
—

 
 
—

 
8,854

 
1,127

Amortization of prior service cost
—

 
 
(824
)
 
(181
)
 
—

Curtailment loss (gain)
—

 
 
(2,712
)
 
—

 
—

Total recognized in other comprehensive (income) loss
$
(2,182
)
 
 
$
(327
)
 
$
1,734

 
$
416

 
 
 
 
 
 
 
 
 
Total recognized in net periodic benefit cost and other comprehensive loss (income)
$
(1,657
)
 
 
$
4,444

 
$
3,256

 
$
2,375

The weighted-average assumptions related to black lung obligations used to determine the benefit obligation as of December 31, 2016 and 2015 were as follows: 
 
Successor
 
 
Predecessor
 
December 31, 2016
 
 
December 31, 2015
Discount rate
4.27
%
 
 
4.29
%
Federal black lung benefit trend rate
2.50
%
 
 
3.00
%
Black lung medical benefit trend rate
5.00
%
 
 
N/A

Black lung benefit expense inflation rate
2.50
%
 
 
N/A

The weighted-average assumptions related to black lung obligations used to determine net periodic benefit cost were as follows:
 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31,
2015
 
Year Ended December 31,
2014
Discount rate for benefit obligations
3.62
%
 
 
3.90
%
 
4.02
%
 
4.60
%
Discount rate for service cost
3.66
%
 
 
N/A

 
N/A

 
N/A

Discount rate for interest cost
3.49
%
 
 
N/A

 
N/A

 
N/A

Federal black lung benefit trend rate
2.50
%
 
 
3.00
%
 
3.00
%
 
3.00
%
Black lung medical benefit trend rate
5.00
%
 
 
N/A

 
N/A

 
N/A

Black lung benefit expense inflation rate
2.50
%
 
 
N/A

 
N/A

 
N/A

Expected return on plan assets
N/A

 
 
2.50
%
 
2.50
%
 
3.00
%

F-44


Estimated future cash payments related to black lung obligations for the next ten years ending after December 31, 2016 are as follows: 
Year ending December 31:
 
2017
$
—

2018
—

2019
—

2020
—

2021
16

2022-2026
1,840

 
$
1,856

Life Insurance Benefits
As part of the Alpha restructuring and the Retiree Committee Settlement Agreement (see Note 12), 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 Consolidated Balance Sheet as accrued expenses and other current liabilities and other non-current liabilities. At December 31, 2016, the Company had $12,553 of life insurance benefits liability primarily related to obligations assumed in the acquisition.
The following tables set forth the accumulated life insurance benefit obligations, fair value of plan assets and funded status for the period from July 26, 2016 to December 31, 2016:
 
December 31, 2016
Change in benefit obligation:
 
Accumulated benefit obligation at beginning of period
$
13,628

Interest cost
148

Actuarial gain
(1,086
)
Benefits paid
(137
)
Accumulated benefit obligation at end of period
$
12,553

Change in fair value of plan assets:
 
Benefits paid (1)
(137
)
Employer contributions (1)
137

Fair value of plan assets at end of period
$
—

Funded status
—

Accrued benefit cost at end of year
$
12,553

 
 
Amounts recognized in the consolidated balance sheets:
 
Current liabilities
$
866

Long-term liabilities
11,687

 
$
12,553

______________
(1)
Amount is comprised of premium payments to commercial life insurance provider.

F-45


Gross amounts related to the life insurance benefit obligations recognized in accumulated other comprehensive income consisted of the following as of December 31, 2016: 
 
December 31, 2016
Net actuarial gain
$
(1,086
)
Accumulated Other Comprehensive Income
$
(1,086
)
The following table details the components of the net periodic benefit cost for life insurance benefit obligations:
 
Period from July 26, 2016 to
December 31, 2016
Interest cost
$
148

Net periodic expense
$
148

Other changes in the life insurance plan assets and benefit obligations recognized in other comprehensive income (loss) are as follows:
 
Period from July 26, 2016 to
December 31, 2016
Current year actuarial gain
$
(1,086
)
Total recognized in other comprehensive income (loss)
$
(1,086
)
The weighted-average assumptions related to life insurance benefit obligations used to determine the benefit obligation as of December 31, 2016 was as follows: 
 
2016
Discount rate
4.03
%
The weighted-average assumptions related to life insurance benefit obligations used to determine net periodic benefit cost were as follows:
 
Period from July 26, 2016 to
December 31, 2016
Discount rate for benefit obligations
3.36%
Discount rate for interest cost
2.71%

F-46


Estimated future cash payments related to life insurance benefit obligations for the next ten years ending after December 31, 2016 are as follows: 
Year ending December 31:
 
2017
$
866

2018
806

2019
727

2020
680

2021
670

2022-2026
3,249

 
$
6,998

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 period from July 26, 2016 to December 31, 2016 was $1,057.
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, $3,062, and $1,066 for the period from January 1, 2016 to July 25, 2016 and for the years ended December 31, 2015 and 2014, respectively, which is reflected within cost of coal sales and selling, general and administrative expenses in the Statement of Operations.
Self-Insured Medical Plan
The Company is self-insured for health insurance 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 period from July 26, 2016 to December 31, 2016, the Company incurred total expenses of $18,034 which primarily includes claims processed and an estimate for claims incurred but not paid.
In 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 $22,161, $43,311 and $65,459 for the period from January 1, 2016 to July 25, 2016, and for the years ended December 31, 2015 and 2014, respectively, which is reflected within cost of coal sales and selling, general and administrative expenses in the Results of Operations.
(19) Stock-Based Compensation Awards
Successor
The Management Incentive Plan (the “Plan”) is currently authorized for the issuance of awards of up to 1,201,202 shares of common stock, and as of December 31, 2016, 572,474 shares of common stock were available for grant under the Plan.
On July 26, 2016, 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. Additionally, during the period from July 26,

F-47


2016 to December 31, 2016, the Company granted 28,122 time-based restricted stock units to its non-employee directors, all of which remained outstanding as of December 31, 2016.
The Company is 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 stock grants. Shares that are repurchased to satisfy the employees’ minimum statutory tax withholdings are recorded in treasury stock at cost. The Company did not repurchase any common shares from employees during the period from July 26, 2016 to December 31, 2016.
Stock-based compensation expense totaled $1,424 for the period from July 26, 2016 to December 31, 2016. For the period from July 26, 2016 to December 31, 2016, approximately 91% of stock-based compensation expense was reported as selling, general and administrative expenses and the remainder was recorded as cost of coal sales.
Restricted Stock Shares
During the period from July 26, 2016 to December 31, 2016, the Company granted 309,310 shares of common stock to certain of its officers and key employees, all of which were fully vested on the grant date.
Restricted stock shares activity for 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
—

 
$
—

Restricted Share Units
Time-Based Share Units
During the period from July 26, 2016 to December 31, 2016, the Company granted 28,122 time-based restricted stock units to its non-employee directors, all of which remained outstanding as of December 31, 2016. These time-based units granted to the Company’s non-employee directors will vest on the first to occur of (i) 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, and (iii) a change in control, subject in each case to the director’s continuous service with the Company through such date. Upon vesting of time-based share units, the Company issues authorized and unissued shares of the Company’s common stock to the recipient.

F-48


Time-based share unit activity for 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

As of December 31, 2016, there was $263 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 0.58 years.
Non-Qualified Stock Options
Fixed Value Non-Qualified 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. The units granted to the officers and key employees were fully vested on the grant date.
Fixed value non-qualified stock option activity for 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
As of December 31, 2016, the options outstanding and exercisable had an aggregate intrinsic value of $68.50. As of December 31, 2016, there was no unrecognized compensation cost related to the fixed value non-qualified stock options.
30-Day Volume-Weighted Average Price (“VWAP”) Non-Qualified Stock Options
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. The units granted to the officers and key employees were fully vested on the grant date.

F-49


30-day VWAP non-qualified stock option activity for 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
As of December 31, 2016, the options outstanding and exercisable had an aggregate intrinsic value of $66.00. As of December 31, 2016, there was no unrecognized compensation cost related to the 30-day VWAP non-qualified stock options.
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 plan. The 2012 LTIP provides 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.
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 and the years ended December 31, 2015 and 2014, Alpha repurchased 0, 442,035, and 311,437, respectively, of common shares from employees at an average price paid per share of $0, $0.95, and $4.69, respectively.

F-50


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 $658, $2,666, and $9,872, for the period from January 1, 2016 to July 25, 2016 and the years ended December 31, 2015 and 2014, respectively. For the period from January 1, 2016 to July 25, 2016 and the years ended December 31, 2015 and 2014, approximately 75%, 51%, and 73%, 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 total excess tax benefit recognized for stock-based compensation was $0 for the period from January 1, 2016 to July 25, 2016 and the years ended December 31, 2015 and 2014.
Restricted Share Units
Time-Based Share Units
During the period from January 1, 2016 to July 25, 2016 and the years ended December 31, 2015 and 2014, Alpha granted time-based share units under the 2012 LTIP to certain executive officers, directors and key employees in the amount of 0, 3,760,612 and 1,632,824, respectively, of which 3,275,961 remained outstanding as of July 25, 2016. Additionally, during the period from January 1, 2016 to July 25, 2016 and the years ended December 31, 2015 and 2014, Alpha also awarded certain of its executives and key employees time-based cash units in the amount of 0, 9,942,699 and 2,077,491, respectively, of which 9,399,807 remained outstanding as of July 25, 2016. Time-based cash units were accounted for as liability awards and subject to variable accounting.
Alpha’s time-based share unit activity for the period from January 1, 2016 to July 25, 2016 and the years ended December 31, 2015 and 2014 is summarized in the following table: 
 
Number of
Shares
 
Weighted-
Average
Grant Date
Fair Value
Alpha
 
 
 
Non-vested shares outstanding at December 31, 2013
3,099,289

 
$
11.66

Granted
1,632,824

 
$
4.25

Earned
(906,424
)
 
$
16.26

Forfeited or Expired
(57,256
)
 
$
10.34

Non-vested shares outstanding at December 31, 2014
3,768,433

 
$
7.32

Granted
3,760,612

 
$
1.25

Earned
(1,390,009
)
 
$
7.91

Forfeited or Expired
(1,416,837
)
 
$
4.15

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


F-51


Alpha’s time-based cash unit activity for the period from January 1, 2016 to July 25, 2016 and the years ended December 31, 2015 and 2014 is summarized in the following table: 
 
Number of
Shares
 
Weighted-
Average
Grant Date
Fair Value (1)
Alpha
 
 
 
Non-vested shares outstanding at December 31, 2013
—

 
$
—

Granted
2,077,491

 
$
4.38

Earned
(98,335
)
 
$
2.46

Forfeited or Expired
(59,476
)
 
$
2.28

Non-vested shares outstanding at December 31, 2014
1,919,680

 
$
1.67

Granted
9,942,699

 
$
0.95

Earned
(454,626
)
 
$
0.89

Forfeited or Expired
(1,457,293
)
 
$
0.11

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 and the years ended December 31, 2015 and 2014 was $0, $1,687 and $4,470, respectively. As of July 25, 2016, Alpha had $2,184 of unrecognized compensation cost related to non-vested time-based share units which was 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 shareholder 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.

F-52


During the period from January 1, 2016 to July 25, 2016 and year ended December 31, 2015, Alpha awarded 0 total shareholder return performance-based share units. During the year ended December 31, 2014, Alpha awarded 1,378,486 total shareholder return performance-based share units, of which 912,474 remain outstanding as of July 25, 2016. As of July 25, 2016, was Alpha had $480 of unrecognized compensation cost related to the 2014 performance-based share units which was expected to be recognized as expense over a weighted-average period of 0.44 years. Additionally, during the year ended December 31, 2014, Alpha also awarded certain of its executives and key employees 1,378,486 cash flow performance-based cash units which were accounted for as liability awards and subject to variable accounting, of which 0 remained outstanding as of July 25, 2016. At December 31, 2014, Alpha had assessed the cash flow performance target as not probable of achievement and subsequently cancelled the awards during the three months ended March 31, 2015.
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, 2013
5,566,158

 
$
15.25

Granted
2,756,972

 
$
4.33

Earned
(11,027
)
 
$
2.60

Forfeited or Expired
(493,472
)
 
$
58.60

Non-vested shares outstanding at December 31, 2014
7,818,631

 
$
8.78

Granted
—

 
$
—

Earned
—

 
$
—

Forfeited or Expired
(3,422,914
)
 
$
11.84

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.

F-53


Alpha’s performance-based cash unit activity is summarized in the following table: 
 
Number of 
Shares (1)
 
Weighted-Average Grant Date Fair Value(2)
Alpha
 
 
 
Non-vested shares outstanding at December 31, 2013
—

 
$
—

Granted
2,756,972

 
$
4.33

Earned
—

 
$
—

Forfeited or Expired
(12,692
)
 
$
3.37

Non-vested shares outstanding at December 31, 2014
2,744,280

 
$
1.67

Granted
—

 
$
—

Earned
—

 
$
—

Forfeited or Expired
(2,744,280
)
 
$
1.14

Non-vested shares outstanding at December 31, 2015
—

 
$
—

Granted
—

 
$
—

Earned
—

 
$
—

Forfeited or Expired
—

 
$
—

Non-vested shares outstanding at July 25, 2016
—

 
$
—

______________
(1)
Shares in the table above were based on the maximum shares that can be awarded based on the achievement of the performance criteria.
(2)
The performance-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, forfeited/expired date, and outstanding dates.

F-54


Non-Qualified Stock Options
Alpha’s stock option activity for the period from January 1, 2016 to July 25, 2016 and years ended December 31, 2015 and 2014 is summarized in the following table:
Alpha
Number of
Shares
 
Weighted-
Average
Exercise
Price
 
Weighted-
Average
Remaining
Contractual
Term (Years)
Outstanding at December 31, 2013
937,977

 
$
21.77

 
 
Exercised
—

 
$
—

 
 
Forfeited or Expired
(351,255
)
 
$
15.58

 
 
Outstanding at December 31, 2014
586,722

 
$
25.48

 
3.41

Exercisable at December 31, 2014
586,722

 
$
25.48

 
3.41

Exercised
—

 
$
—

 
 
Forfeited or Expired
(227,695
)
 
$
24.39

 
 
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

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 and years ended December 31, 2015 and 2014 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 and the years ended December 31, 2015 and 2014 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:
Alpha
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

(20) 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

F-55


obligations, (ii) debt-related obligations and (iii) litigation and other contingent claims, some of which were recorded in accounts payable.
Liabilities subject to compromise consisted of the following: 
 
Predecessor
 
December 31,
2015
Trade accounts payable
$
49,087

Maintenance and repair contracts
13,326

Unsecured/partially secured debt and accrued interest
3,946

Litigation reserve
3,600

Other accruals
1,597

Provision for rejected contracts and leases
686

Liabilities subject to compromise
$
72,242

Reorganization items consisted of the following:
 
Predecessor
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
Professional fees (1)
$
(28,652
)
 
$
(14,598
)
Provision for rejected contracts and leases
(3,524
)
 
(2,326
)
Trade accounts payable and other
1,103

 
790

Reorganization items, net
$
(31,073
)
 
$
(16,134
)
______________
(1)
Net cash paid for reorganization items for the period from January 1, 2016 to July 25, 2016 and year ended December 31, 2015 totaled approximately $27,236 and $8,408, respectively, related to professional fees.
(21) Related Party Transactions
Successor
There were no material related party transactions for the period July 26, 2016 to December 31, 2016.
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, and in the accompanying Combined Statements of Stockholders’ / Predecessor Business Equity as changes in Alpha’s investment.

F-56


During the period from January 1, 2016 to July 25, 2016, and years ended December 31, 2015 and December 31, 2014, the Company was allocated $57,217, $92,009 and $103,996, respectively, of indirect general corporate expenses incurred by Alpha, which are included within cost of coal sales and selling, general and administrative expenses in the Statements of Operations. These amounts exclude allocated reorganization items, which are discussed in Note 20.
(22) 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, 2016, 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:
 
 
 
2017
$
1,147

 
$
3,284

2018
532

 
1,046

2019
270

 
269

2020
38

 
229

2021
38

 
239

Thereafter
363

 
734

Total
$
2,388

 
$
5,801

Net rent expense under operating leases was $1,609, $1,439, $3,768, and $4,182 and coal royalty expense was $30,761, $30,530, $68,190 and $68,112 for the period July 26, 2016 to December 31, 2016, for the period January 1, 2016 to July 25, 2016, and for the years ended December 31, 2015 and 2014, respectively.

F-57


The following is a schedule by years of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2016:
 
Capital Leases
Year Ending December 31:
 
2017
$
1,153

2018
1,051

2019
793

Total minimum lease payments
$
2,997

Less: Amount representing interest (rates range from 4.72% to 9.50%)
(252
)
Present value of net minimum lease payments
$
2,745

Other Commitments
The Company has obligations under certain coal purchase agreements and equipment purchase agreements that contain minimum quantities to be purchased in 2017 totaling $47,021 and $16,829, respectively. The Company also has obligations under certain coal transportation agreements that contain minimum quantities to be shipped each year. Minimum amounts due under these contracts for the next four years are $921, $3,042, $3,072, and $3,102, respectively.
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 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.
(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, 2016, the Company had outstanding surety bonds with a total face amount of $315,072 to secure various obligations and commitments.
As of December 31, 2016, the Company had mining equipment and real property collateralizing $102,357 of reclamation bonds.
Letters of Credit
As of December 31, 2016, the Company had no letters of credit outstanding under the LC facility.
(d) Legal Proceedings

F-58


West Virginia DEP Complaint (Successor)
On November 16, 2016, the West Virginia Department of Environmental Protection (“DEP”) filed a complaint with the Bankruptcy Court (Adversary Case 16-03334) against Alpha Natural Resources, Inc., Contura Energy, Inc., Citicorp North America, Inc. and certain former members of Alpha management who are now affiliated with the Company. The complaint made, among other claims, allegations regarding the accuracy of financial projections prepared in connection with the confirmation of Alpha’s plan of reorganization in July 2016. On November 28, 2016, the parties reached a settlement pursuant to which the Company would provide financial guarantees, for the benefit of the DEP, in connection with ANR’s performance of certain of its environmental obligations through 2018. On December 7, 2016, the Bankruptcy Court approved the settlement and dismissed the DEP complaint with prejudice. The period for the appeal of this decision has passed.
Per the terms of the settlement agreement, the Company placed $4,000 cash into escrow during December 2016 in support of ANR’s payment obligations under the Permitting and Reclamation Plan Settlement Agreement for the State of West Virginia, dated as of July 12, 2016 by and among ANR, Contura and DEP and the Reclamation Funding Agreement, dated as of July 12, 2016, by and among ANR, Contura the relevant agencies of the states of Illinois, Kentucky, Virginia and West Virginia and the United States government. The Company also provided a secured guaranty for ANR’s payment obligations under the two agreements described above in the amount of $4,500, with security for this guaranty to be put in place on or before March 31, 2017. Pursuant to the terms of the settlement agreement, as the collateralization of this guaranty was not effectuated on or before March 31, 2017, the Company secured the guaranty by placing $4,500 cash into escrow on March 30, 2017.
Emerald Purported Securities Class Action (Predecessor)
On July 13, 2012, a purported class action brought on behalf of a putative class of former Massey stockholders was filed in Boone County, West Virginia Circuit Court. The complaint asserts claims under the Securities Act of 1933, as amended, against the Predecessor and certain of its officers and current and former directors, and generally asserts that the defendants made false statements about the Predecessor’s Emerald mine in its public filings associated with the Massey Acquisition. The plaintiff seeks, among other relief, an award of compensatory damages in an amount to be proven at trial. The plaintiff filed an amended complaint in the Boone County Circuit Court on February 6, 2013. The defendants filed motions to dismiss the amended complaint on March 22, 2013 and March 29, 2013. On January 8, 2015, the Boone County Circuit Court dismissed all claims in the plaintiff’s amended complaint. The plaintiffs did not appeal the dismissal.
On April 25, 2014, the named plaintiff in the West Virginia Circuit Court action described above filed a second complaint in Greene County, Pennsylvania, Court of Common Pleas, again asserting claims under the Securities Act of 1933, as amended, against the Predecessor and certain of the Predecessor’s officers and current and former directors, and generally asserts that the defendants made false statements about the Predecessor’s Emerald mine in its public filings associated with the Massey Acquisition. The plaintiff seeks, among other relief, an award of compensatory damages in an amount to be proven at trial. By agreement of the parties, the defendants’ time to answer, move or otherwise respond to the Pennsylvania complaint was extended until May 7, 2015.
On April 24, 2015, the parties reached agreement on definitive terms for settlement of the Greene County, Pennsylvania litigation. On July 23, 2015, the parties executed definitive settlement documentation, which received preliminary approval by the Green County court on August 3, 2015. On October 8, 2015, the Bankruptcy Court entered an order that modified the Automatic Stay to authorize the Predecessor’s insurers to fund the proposed Settlement, and further authorized related relief to allow the parties to consummate the settlement in accordance with its terms. On October 15, 2015, proceeds from its insurance policies funded the settlement escrow account.
On March 1, 2016, following a fairness hearing, the Green County court approved the settlement and entered a final order dismissing the case with prejudice as to the Predecessor and the individual defendants.

F-59


Other Legal Proceedings 
The Company could also become party to other 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, 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.
(23) 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 period from July 26, 2016 to December 31, 2016, January 1, 2016 to July 25, 2016, and for the years ended December 31, 2015 and 2014.
Top customers as a percentage of total revenue and steam and met coal as % of coal sales volume were as follows:
 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Total revenue
$
689,419

 
 
$
607,938

 
$
1,361,631

 
$
1,587,025

Top customer as % of total revenue
11
%
 
 
6
%
 
8
%
 
8
%
Top 10 customers as % of total revenue
54
%
 
 
42
%
 
52
%
 
52
%
Steam coal as % of coal sales volume
86
%
 
 
89
%
 
89
%
 
91
%
Met coal as % of coal sales volume
14
%
 
 
11
%
 
11
%
 
9
%
Additionally, three of the Company’s customers had outstanding balances each in excess of 10% of the total accounts receivable balance as of December 31, 2016.
(24) Segment Information
The Company extracts, processes and markets steam and met coal from surface and deep mines for sale to electric utilities, steel and coke producers, and industrial customers. The Company operates only in the United States with mines in Northern and Central Appalachia and the Powder River Basin. The Company has four reportable segments: CAPP, NAPP, PRB and Trading and Logistics. CAPP consists of nine active mines and two preparation plants in Virginia, one active mine and one preparation plant in West Virginia, as well as expenses associated with certain closed mines. NAPP consists of one active mine in Pennsylvania and one preparation plant, as well as expenses associated with one closed mine. PRB consists of two active mines in Wyoming. Trading and Logistics segment primarily engages in coal trading activities and coal terminal services.

F-60


In addition to the four reportable segments, the All Other category includes general corporate overhead and corporate assets and liabilities.
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 period from July 26, 2016 to December 31, 2016 were as follows: 
 
Successor
 
Period from July 26, 2016 to December 31, 2016
 
CAPP
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Consolidated
Total revenues
$
138,973

 
$
132,363

 
$
183,123

 
$
234,704

 
$
256

 
$
689,419

Depreciation, depletion, and amortization
$
6,442

 
$
(772
)
 
$
38,005

 
$
—

 
$
303

 
$
43,978

Amortization of acquired intangibles, net
$
—

 
$
—

 
$
—

 
$
61,281

 
$
—

 
$
61,281

Adjusted EBITDA
$
43,969

 
$
25,833

 
$
39,768

 
$
39,228

 
$
(19,429
)
 
$
129,369

Capital expenditures
$
4,626

 
$
18,136

 
$
11,123

 
$
—

 
$
612

 
$
34,497

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
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Combined
Total revenues
$
169,411

 
$
229,323

 
$
196,827

 
$
12,377

 
$
—

 
$
607,938

Depreciation, depletion, and amortization
$
15,389

 
$
49,852

 
$
19,303

 
$
3

 
$
832

 
$
85,379

Amortization of acquired intangibles, net
$
—

 
$
11,567

 
$
—

 
$
—

 
$
—

 
$
11,567

Adjusted EBITDA
$
(1,162
)
 
$
32,202

 
$
29,418

 
$
(1,180
)
 
$
(29,571
)
 
$
29,707

Capital expenditures
$
894

 
$
5,803

 
$
16,736

 
$
—

 
$
—

 
$
23,433


F-61


Segment operating results and capital expenditures for the year ended December 31, 2015 were as follows: 
 
Predecessor
 
Year ended December 31, 2015
 
CAPP
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Combined
Total revenues
$
367,662

 
$
492,005

 
$
435,610

 
$
66,354

 
$
—

 
$
1,361,631

Depreciation, depletion, and amortization
$
42,869

 
$
104,479

 
$
52,918

 
$
13

 
$
1,836

 
$
202,115

Amortization of acquired intangibles, net
$
350

 
$
1,873

 
$
—

 
$
—

 
$
—

 
$
2,223

Adjusted EBITDA
$
(911
)
 
$
86,840

 
$
55,070

 
$
1,265

 
$
(44,159
)
 
$
98,105

Capital expenditures
$
20,826

 
$
23,868

 
$
14,839

 
$
—

 
$
—

 
$
59,533

Acquisition of mineral rights under federal lease
$
—

 
$
—

 
$
42,130

 
$
—

 
$
—

 
$
42,130

Segment operating results and capital expenditures for the year ended December 31, 2014 were as follows: 
 
Predecessor
 
Year ended December 31, 2014
 
CAPP
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Combined
Total revenues
$
430,789

 
$
627,739

 
$
444,268

 
$
84,229

 
$
—

 
$
1,587,025

Depreciation, depletion, and amortization
$
55,487

 
$
89,970

 
$
55,224

 
$
4

 
$
2,676

 
$
203,361

Amortization of acquired intangibles, net
$
454

 
$
(33
)
 
$
(2,120
)
 
$
—

 
$
—

 
$
(1,699
)
Adjusted EBITDA
$
24,903

 
$
210,529

 
$
28,150

 
$
6,714

 
$
(52,256
)
 
$
218,040

Capital expenditures
$
15,088

 
$
41,320

 
$
12,298

 
$
—

 
$
—

 
$
68,706

Acquisition of mineral rights under federal lease
$
—

 
$
—

 
$
42,130

 
$
—

 
$
—

 
$
42,130


F-62


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
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Consolidated
Net income (loss)
$
37,436

 
$
26,434

 
$
1,467

 
$
(22,053
)
 
$
(54,214
)
 
$
(10,930
)
Interest expense
97

 
171

 
296

 
—

 
20,228

 
$
20,792

Interest income
(6
)
 
—

 
—

 
—

 
(17
)
 
$
(23
)
Income tax benefit
—

 
—

 
—

 
—

 
(1,369
)
 
$
(1,369
)
Depreciation, depletion and amortization
6,442

 
(772
)
 
38,005

 
—

 
303

 
$
43,978

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
)
Amortization of acquired intangibles, net
—

 
—

 
—

 
61,281

 
—

 
$
61,281

Adjusted EBITDA
$
43,969

 
$
25,833

 
$
39,768

 
$
39,228

 
$
(19,429
)
 
$
129,369

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
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Combined
Net (loss) income
$
(26,407
)
 
$
(43,143
)
 
$
(679
)
 
$
(1,452
)
 
$
4,469

 
$
(67,212
)
Interest expense
2

 
—

 
61

 
—

 
—

 
$
63

Interest income
(9
)
 
(10
)
 
(10
)
 
—

 
—

 
$
(29
)
Income tax benefit
—

 
—

 
—

 
—

 
(34,889
)
 
$
(34,889
)
Depreciation, depletion and amortization
15,389

 
49,852

 
19,303

 
3

 
832

 
$
85,379

Reorganization items, net
8,196

 
12,528

 
10,084

 
248

 
17

 
$
31,073

Restructuring
1,667

 
1,408

 
659

 
21

 
—

 
$
3,755

Amortization of acquired intangibles, net
—

 
11,567

 
—

 
—

 
—

 
$
11,567

Adjusted EBITDA
$
(1,162
)
 
$
32,202

 
$
29,418

 
$
(1,180
)
 
$
(29,571
)
 
$
29,707


F-63


The following table presents a reconciliation of net (loss) income to adjusted EBITDA for the year ended December 31, 2015:
 
Predecessor
 
Year ended December 31, 2015
 
CAPP
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Combined
Net (loss) income
$
(118,543
)
 
$
(249,090
)
 
$
(259,317
)
 
$
795

 
$
208,595

 
$
(417,560
)
Interest expense
28

 
—

 
409

 
—

 
—

 
$
437

Interest income
(3
)
 
(1
)
 
—

 
—

 
—

 
$
(4
)
Income tax benefit
—

 
—

 
—

 
—

 
(254,595
)
 
$
(254,595
)
Depreciation, depletion and amortization
42,869

 
104,479

 
52,918

 
13

 
1,836

 
$
202,115

Reorganization items, net
3,438

 
6,306

 
6,049

 
336

 
5

 
$
16,134

Impairments
72,012

 
224,139

 
260,011

 
3

 
—

 
$
556,165

Restructuring
1,573

 
(420
)
 
1,263

 
118

 
—

 
$
2,534

Mark-to-market adjustment for other derivatives
(2,635
)
 
(446
)
 
(6,263
)
 
—

 
—

 
$
(9,344
)
Amortization of acquired intangibles, net
350

 
1,873

 
—

 
—

 
—

 
$
2,223

Adjusted EBITDA
$
(911
)
 
$
86,840

 
$
55,070

 
$
1,265

 
$
(44,159
)
 
$
98,105

The following table presents a reconciliation of net (loss) income to adjusted EBITDA for the year ended December 31, 2014:
 
Predecessor
 
Year ended December 31, 2014
 
CAPP
 
NAPP
 
PRB
 
Trading and Logistics
 
All
Other
 
Combined
Net (loss) income
$
(102,830
)
 
$
114,952

 
$
(33,972
)
 
$
6,697

 
$
(37,192
)
 
$
(52,345
)
Interest expense
87

 
14

 
611

 
—

 
—

 
$
712

Interest income
(3
)
 
(1
)
 
(3
)
 
—

 
—

 
$
(7
)
Income tax benefit
—

 
—

 
—

 
—

 
(17,740
)
 
$
(17,740
)
Depreciation, depletion and amortization
55,487

 
89,970

 
55,224

 
4

 
2,676

 
$
203,361

Impairments
70,017

 
—

 
—

 
—

 
—

 
$
70,017

Restructuring
1,092

 
5,627

 
117

 
13

 
—

 
$
6,849

Mark-to-market adjustment for other derivatives
599

 
—

 
8,293

 
—

 
—

 
$
8,892

Amortization of acquired intangibles, net
454

 
(33
)
 
(2,120
)
 
—

 
—

 
$
(1,699
)
Adjusted EBITDA
$
24,903

 
$
210,529

 
$
28,150

 
$
6,714

 
$
(52,256
)
 
$
218,040

No asset information has been provided for these reportable segments as the CODM does not regularly review asset information by reportable segment.

F-64


The Company markets produced, processed and purchased coal to customers in the United States and in international markets, primarily India, Italy, Mexico, Brazil, and Turkey. Export coal revenues, including freight and handling revenues, were the following:
 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016
 
 
Period from January 1, 2016 to July 25, 2016
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Total coal revenue (1)
$
682,791

 
 
$
589,396

 
$
1,340,927

 
$
1,562,425

Export coal revenue (1)
$
357,343

 
 
$
155,735

 
$
339,066

 
$
421,190

Export coal revenue as % of total coal revenue (1)
52
%
 
 
26
%
 
25
%
 
27
%
______________
(1)
Amounts include freight and handling revenues
(25) Investment in Unconsolidated Affiliate
Dominion Terminal Associates
Alpha held a 40.6% non-controlling interest in the Dominion Terminal Associates (“DTA”) coal export terminal in eastern Virginia. As indicated in Note 1, the Company acquired Alpha’s DTA ownership interest in conjunction with the acquisition of Alpha’s core coal operations. Accordingly, the Company accounts for its investment in DTA under the equity method of accounting. DTA provides the Company and its consortium partners with the ability to fulfill a broad range of customer coal quality requirements, coal storage capacity and transportation flexibility through use of DTA’s coal export terminal. DTA’s fiscal year end is December 31 and is a limited liability partnership. Refer to Note 26 for its disclosure related to the Company’s increased ownership interest in DTA acquired on March 31, 2017.
The Company recorded equity method losses, before taxes, from DTA of ($2,287), ($2,735), ($7,154) and ($8,466) for the period from July 26, 2016 to December 31, 2016, for the period January 1, 2016 to July 25, 2016 and for the years ended December 31, 2015 and 2014, respectively, which are reflected within miscellaneous income, net in the Statements of Operations. As of December 31, 2016 and 2015, the Company’s investment in DTA was $172 and $3,314, respectively, and is recorded within other non-current assets within the Balance Sheets.
Condensed balance sheet information as of December 31, 2016 and 2015 and condensed income statement information for the period from July 26, 2016 to December 31, 2016, for the period January 1, 2016 to July 25, 2016 and for the years ended December 31, 2015 and 2014 for DTA is presented in the tables that follow.
 
Successor
 
 
Predecessor
 
December 31, 2016
 
 
December 31, 2015
Current assets
$
3,453

 
 
$
3,327

Non-current assets
63,630

 
 
66,839

Current liabilities
1,397

 
 
1,768

Non-current liabilities
7,147

 
 
47,477

Partners’ equity
58,538

 
 
20,921


F-65


 
Successor
 
 
Predecessor
 
Period from July 26, 2016 to December 31, 2016 (1)
 
 
Period from January 1, 2016 to July 25, 2016 (1)
 
Year ended December 31, 2015
 
Year ended December 31, 2014
Operating expenses
$
9,792

 
 
$
12,271

 
$
28,187

 
$
32,990

Other income, net
(3,683
)
 
 
(5,032
)
 
(10,720
)
 
(13,124
)
Total expenses, net
6,109

 
 
7,239

 
17,467

 
19,866

Contributions from partners to fund continuing operations
6,243

 
 
4,883

 
14,953

 
18,930

Expenses under (over) contributions
134

 
 
(2,356
)
 
(2,514
)
 
(936
)
Depreciation and amortization
1,223

 
 
2,413

 
4,590

 
(5,384
)
______________
(1)
DTA’s condensed income statement presented for the period July 26, 2016 to December 31, 2016 and for the period January 1, 2016 to July 25, 2016 reflect its operating results for the period August 1, 2016 to December 31, 2016 and for the period January 1, 2016 to July 31, 2016, respectively. The Company does not readily have information available to match its Successor and Predecessor presentation, but do not believe this six day difference to be significant to its results of operations
(26) Subsequent Events
On January 12, 2017, Peabody Energy filed a motion with the U.S. Bankruptcy Court (“Court”), Eastern District of Missouri, requesting approval of bidding procedures for the sale of its ownership stake in the DTA as part of its ongoing Chapter 11 restructuring. That order was approved by the Court on January 30, 2017, and an auction was held for the asset on March 6, 2017. The Company participated in the bidding process jointly with Arch Coal, a current partner at the DTA Facility. On March 9, 2017, the Court approved the Company’s successful bid to increase its ownership stake in the DTA Facility to sixty-five percent majority ownership through its affiliate Contura Terminal, LLC. The Company’s portion of the bid was $13,293. The transaction closed on March 31, 2017.
On March 17, 2017, the Company entered into a $400,000 Term Loan Credit Facility with a maturity date on March 17, 2024. The Term Loan Credit Facility carries an interest rate of LIBOR plus five percent, with a one percent LIBOR floor. In connection with the transaction, the Company paid all of its outstanding 10.00% Senior Secured First Lien Notes due 2021. The aggregate principal amount outstanding of the notes was $300,000. The redemption price for the notes is equal to 107.5% of the principal amount thereof, including accrued interest, for a total payment to holders of the notes of approximately $329,000 in aggregate. The proceeds of the Term Loan Credit Facility were used to repay certain other long-term liabilities including the Term Facility, the Closing Tranche Term Loan and the GUC Distribution Note, pay related fees, costs and expenses, and for general corporate purposes.
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 (the “Lender”), and Citibank N.A., BMO Harris Bank N.A. and Credit Suisse AG as letter of credit issuers (“LC Lenders”). The Asset-Based Revolving Credit Agreement includes a senior secured asset-based revolving credit facility (the “Facility”). Under the 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 amount up to $125,000, subject to certain limitations set forth therein. Any borrowings under the Facility will have a maturity date of April 4, 2022 and will bear interest at rates ranging from 2.00% to 2.50% for Eurocurrency Rate Loans and 1.00% to 1.50% for Base Rate Loans, depending on the amount of credit available. No letters of credit were outstanding, no cash borrowing transactions had taken place and $125,000 was available under the Facility.

F-66










outsidebackcoverlogo.jpg






Through and including          , 2017 (25 days after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.



II. INFORMATION NOT REQUIRED IN PROSPECTUS
Item 13. Other Expenses of Issuance and Distribution
 
Amount to Be Paid
SEC registration fee
$
*
FINRA filing fee
 
*
NYSE listing fee
 
*
Transfer agent’s fees
 
*
Printing and engraving expenses
 
*
Legal fees and expenses
 
*
Accounting fees and expenses
 
*
Blue Sky fees and expenses
 
*
Miscellaneous
 
*
Total
$
*
______________
*
To be completed by amendment.

Each of the amounts set forth above, other than the SEC registration fee, the FINRA filing fee and the NYSE listing fee is an estimate.
Item 14. Indemnification of Directors and Officers
Section 145 of the DGCL provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with any threatened, pending or completed actions, suits or proceedings in which such person is made a party by reason of such person being or having been a director, officer, employee or agent to the registrant. The DGCL provides that Section 145 is not exclusive of other rights to which those seeking indemnification may be entitled under any bylaw, agreement, vote of stockholders or disinterested directors or otherwise. Section 8(a) of the registrant’s Amended and Restated Certificate of Incorporation provides for indemnification by the registrant of its directors, officers and employees to the fullest extent permitted by the DGCL. The registrant has entered into indemnification agreements with each of its current directors and executive officers to provide these directors and executive officers additional contractual assurances regarding the scope of the indemnification set forth in the registrant’s amended and restated certificate of incorporation and amended and restated bylaws and to provide additional procedural protections. There is no pending litigation or proceeding involving a director or executive officer of the registrant for which indemnification is sought.
Section 102(b)(7) of the DGCL permits a corporation to provide in its certificate of incorporation that a director of the corporation shall not be personally liable to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (i) for any breach of the director’s duty of loyalty to the corporation or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) for unlawful payments of dividends or unlawful stock repurchases, redemptions or other distributions, or (iv) for any transaction from which the director derived an improper personal benefit. The registrant’s Certificate of Incorporation provides for such limitation of liability.
The registrant maintains standard policies of insurance under which coverage is provided (a) to its directors and officers against loss rising from claims made by reason of breach of duty or other wrongful act, and (b) to the registrant with respect to payments which may be made by the registrant to such officers and directors pursuant to the above indemnification provision or otherwise as a matter of law.

II-1



The proposed form of underwriting agreement to be filed as Exhibit 1.1 to this registration statement will provide for indemnification of directors and officers of the registrant by the underwriters against certain liabilities.
Item 15. Recent Sales of Unregistered Securities
In connection with the Alpha Restructuring, effective July 26, 2016, Contura Energy, Inc. issued an aggregate of:
•
9,350,000 shares of common stock to holders of certain first lien claims, second lien claims and general unsecured claims against Alpha;
•
650,000 shares of common stock to lenders of the company’s ABL Facility as consideration for providing the ABL Facility; and
•
810,811 warrants to purchase common stock to holders of certain unsecured claims against Alpha.
The warrants are exercisable into a maximum of 810,811 shares of common stock with an initial exercise price of $55.93 per share and are exercisable for cash or on a cashless basis at any time from July 26, 2016 until July 26, 2023. These transactions did not involve any underwriters or any public offering. The company believes the issuance of the shares of common stock to holders of such first lien claims, second lien claims and general unsecured claims against Alpha and the issuance of the warrants to holders of such unsecured claims against Alpha were exempt from the registration requirements of the Securities Act pursuant to Section 1145 of the Bankruptcy Code. The company believes that the issuance of the shares of common stock to lenders of the company’s ABL Facility was exempt from the registration requirements of the Securities Act pursuant to Section 4(a)(2) thereof.
On July 26, 2016, the company issued $300 million of 10.00% Senior Secured First Lien Notes due 2021 to holders of first lien claims against Alpha. This transaction did not involve any underwriters or any public offering, and the company believes that such issuance was exempt from the registration requirements of the Securities Act pursuant to Section 4(a)(2) thereof.
On July 26, 2016, pursuant to the company’s Management Incentive Plan, 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 awards granted to the officers and key employees were fully vested on the grant date. Additionally, during the period from July 26, 2016 to December 31, 2016, the company granted 28,122 time-based restricted stock units to its non-employee directors, all of which remained outstanding as of December 31, 2016. These transactions did not involve any underwriters or any public offering, and the company believes that these transactions were exempt from the registration requirements of the Securities Act pursuant to Rule 701 thereof.
Item 16. Exhibits and Financial Statement Schedules
(a) Exhibits
See Exhibit Index beginning on page II–5 of this Registration Statement.
(b) Financial Statement Schedules
All supplemental schedules are omitted because of the absence of conditions under which they are required or because the information is shown in the financial statements or notes thereto.

II-2



Item 17. Undertakings
a)
The undersigned registrant hereby undertakes to provide to the underwriter at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriter to permit prompt delivery to each purchaser.
b)
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant under the provisions described in Item 14, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
c)
The undersigned registrant hereby undertakes that:
(1)
For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant under Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.
(2)
For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-3



SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-1 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Bristol, Tennessee on May 8, 2017.
CONTURA ENERGY, INC.
By:
/s/ Kevin S. Crutchfield
 
Name: Kevin S. Crutchfield
 
Title: Chief Executive Officer and Director
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below does hereby constitute and appoint Charles Andrew Eidson and Mark M. Manno, and each of them singly, as his or her true and lawful attorneys-in-fact and agents, each with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and sign any registration statement for the same offering covered by this Registration Statement that is to be effective upon filing pursuant to Rule 462(b) promulgated under the Securities Act of 1933, as amended, and all post-effective amendments thereto and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his or her substitutes or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated.
Signature
Capacity
Date
/s/ Kevin S. Crutchfield
Chief Executive Officer and Director (Principal Executive Officer)
May 8, 2017

Kevin S. Crutchfield
/s/ Charles Andrew Eidson
Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
May 8, 2017

Charles Andrew Eidson
/s/ Neale X. Trangucci
Chairman
May 8, 2017

Neale X. Trangucci
/s/ Albert E. Ferrara, Jr.
Director
May 8, 2017

Albert E. Ferrara, Jr.
/s/ Jonathan Segal
Director
May 8, 2017

Jonathan Segal

II-4



EXHIBITS
Exhibit No.
 
Description of Exhibit
1.1**
 
Form of Underwriting Agreement
2.1*
 
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
3.1**
 
Amended and Restated Certificate of Incorporation of Contura Energy, Inc.
3.2**
 
Amended and Restated Bylaws of Contura Energy, Inc.
4.1**
 
Specimen Certificate for shares of Common Stock
5.1**
 
Form of Opinion of Davis Polk & Wardwell LLP
10.1*
 
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)
10.2*
 
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
10.3*
 
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
10.4*
 
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
10.5*
 
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
10.6*
 
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
10.7*
 
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
10.8*
 
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
10.9*
 
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
10.10*
 
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

II-5



Exhibit No.
 
Description of Exhibit
10.11*
 
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
10.12*
 
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
10.13*
 
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
10.14*
 
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
10.15*
 
Form of Indemnification Agreement by and between Contura Energy, Inc. and each of its current and future directors and officers
10.16*†
 
Employment Agreement, dated July 26, 2016 by and between Contura Energy, Inc. and Kevin S. Crutchfield
10.17*†
 
Contura Energy, Inc. Management Incentive Plan effective as of July 26, 2016
10.18*†
 
Amendment 1 to Contura Energy, Inc. Management Incentive Plan dated as of January 18, 2017
10.19*†
 
Form of Contura Energy, Inc. Option Agreement
10.20*†
 
Form of Contura Energy, Inc. Restricted Share Agreement
10.21*†
 
Form of Contura Energy, Inc. Emergence Award Agreement
10.22*†
 
Contura Energy, Inc. Deferred Compensation Plan
10.23*†
 
Contura Energy, Inc. Annual Incentive Bonus Program
10.24*†
 
Contura Energy, Inc. Key Employee Separation Plan effective July 26, 2016
10.25*†
 
Contura Energy, Inc. Non-Employee Director Compensation Policy, effective August 1, 2016
10.26*†
 
Amendment 1 to Contura Energy, Inc. Non-Employee Director Compensation Policy, dated January 18, 2017
10.27*†
 
Amendment 2 to Contura Energy, Inc. Non-Employee Director Compensation Policy, dated April 19, 2017
10.28*
 
Warrant Agreement, dated July 26, 2016, between Contura Energy, Inc., Computershare, Inc. and Computershare Trust Company, N.A.
21.1*
 
List of Subsidiaries of the Company
23.1*
 
Consent of KPMG LLP
23.2*
 
Consent of Marshall Miller & Associates, Inc.
23.3*
 
Consent of Wood Mackenzie, Inc.
23.4**
 
Consent of Davis Polk & Wardwell LLP (included in Exhibit 5.1)
24.1*
 
Power of Attorney (included on signature page to the original Registration Statement)
* Filed herewith.
** To be filed by amendment.
† Management contract, compensatory plan or arrangement.

II-6