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As filed with the Securities and Exchange Commission on October 31, 2018

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 20-F

oREGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 2018

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

oSHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Date of event requiring this shell company report     
For the transition period from       to      

Commission File No. 001-38642

PARINGA RESOURCES LIMITED
(Exact name of Registrant as specified in its charter)

N/A
AUSTRALIA
(Translation of Registrant’s name into English)
(Jurisdiction of incorporation or organization)

28 West 44th Street, Suite 810
New York, NY 10036
(Address of principal executive offices)

David Gay
President
(812) 406-4400 (telephone)
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of each class:
Name of each exchange on which registered or to be registered:
American Depository Shares each representing 50
Ordinary Shares, no par value(1)
The Nasdaq Capital Market
(1)Evidenced by American Depositary Receipts

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

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Number of outstanding shares of each of the issuer’s classes of capital or common stock as of June 30, 2018: 454,386,181 ordinary shares.

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

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act of 1934.
Yes o No  ☒

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months.
Yes ☒ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company.

Large accelerated filer o Accelerated filer o Non-accelerated filer o Emerging growth company ☒

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☒

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing.

U.S. GAAP o

International Financial Reporting Standards as issued by the International Accounting Standards Board  ☒

Other o

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 o Item 18 o

If this is an annual report, indicate by check mark whether the registrant is a shell company.
Yes o No  ☒

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
Yes o No o

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INTRODUCTION

Overview

Paringa Resources Limited is a developer of long-life thermal coal mines known as the Buck Creek Complex, consisting of the Poplar Grove and Cypress Mines located in the western Kentucky section of the Illinois Basin. We believe both the Poplar Grove and Cypress Mines possess geological and logistical advantages that will lower the operating costs of our mines and make our coal product attractive to the coal fired power plants located in the Ohio River and southeast U.S. power markets.

We started construction of the Poplar Grove Mine in August 2017, and we expect to complete construction of the mine by the end of the 2018 calendar year. The Poplar Grove Mine is expected to begin first coal production by the end of the 2018 calendar year, ramp up production during the 2019 calendar year and reach near full production capacity by the end of the 2020 calendar year.

Based on our current financial position, including the debt financing with Macquarie described below, we expect to have sufficient cash flow to complete the construction of the Poplar Grove Mine and commence commercial coal production. We intend to ship thermal coal predominately by barge from the Company’s barge load-out facility on the Green River, leading to major coal transportation routes along the Ohio and Mississippi rivers.

We have not yet decided on the timing to develop the Cypress Mine, which if undertaken would require additional funds.

Our Properties

In March 2013, we acquired the Buck Creek Complex, which consists of the Poplar Grove Mine and Cypress Mine, from Buck Creek Resources, LLC. The complex is located in western Kentucky, approximately 175 miles southwest of the state capital of Frankfort and approximately 25 miles southwest of the city of Owensboro, Kentucky, within the Western Kentucky Coalfield region of the Illinois Basin. The Poplar Grove Mine lies between the towns of Hanson and Slaughters in the west and Calhoun and Sacramento in the east, within the Counties of McLean and Hopkins in Kentucky. The Cypress Mine is located immediately north of the Poplar Grove Mine.


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Corporate Information

Paringa Resources Limited was incorporated under the laws of Australia in 2012. Our ordinary shares have been listed on the Australian Securities Exchange since 2012 under the symbol “PNL.”

Our registered office is located at Level 9, 28 The Esplanade, Perth, Western Australia 6000, and our telephone number there is +61 (8) 9322-6322. Our principal executive office is located at 28 West 44th Street, Suite 810, New York, NY 10036. Our website address is www.paringaresources.com. Information on our website and the websites linked to it do not constitute a part of this annual report on Form 20-F.

Our American Depositary Shares, or ADSs, each representing 50 of our ordinary shares, are traded on the Nasdaq Capital Market, or Nasdaq, under the symbol “PNRL”. The Bank of New York Mellon, acting as depositary, registers and delivers the ADSs.

ABOUT THIS ANNUAL REPORT

Unless otherwise indicated or the context implies otherwise, any reference in this annual report on Form 20-F to:

“Paringa” refers to Paringa Resources Limited, an Australian corporation;
“the Company,” “we,” “us,” or “our” refer to Paringa and its consolidated subsidiaries, through which it conducts its business;
“shares” or “ordinary shares” refers to ordinary shares of Paringa;
“ADSs” refers to the American Depositary Shares, each of which represents 50 ordinary shares;
“ADRs” refers to the American Depositary Receipts evidencing the ADSs; and
“ASX” refers to the Australian Securities Exchange.

Our reporting and functional currency is the U.S. dollar. Unless otherwise noted, all industry and market data in this annual report on Form 20-F, including information provided by independent industry analysts, and all other financial and other data related to us in this annual report on Form 20-F is presented in U.S. dollars.

Presentation of Financial Information

Our fiscal year ends on June 30. We designate our fiscal year by the year in which that fiscal year ends; e.g. fiscal 2018 refers to our fiscal year ended June 30, 2018. All dates in this annual report on Form 20-F refer to calendar years, except where a fiscal year or quarter is indicated.

Unless otherwise indicated, the consolidated financial statements and related notes included in this annual report on Form 20-F are presented in U.S. dollars and have been prepared in accordance with International Financial Reporting Standards, or IFRS, and interpretations issued by the International Accounting Standards Board, or IASB, which differ in certain significant respects from generally accepted accounting principles in the United States, or U.S. GAAP. As a result, our financial statements may not be comparable to the financial statements of U.S. companies. Because the U.S. Securities and Exchange Commission, or SEC, has adopted rules to accept financial statements prepared in accordance with IFRS as issued by the IASB without reconciliation to U.S. GAAP from foreign private issuers such as us, we will not be providing a description of the principal differences between U.S. GAAP and IFRS. Information with respect to the basis of preparation of the unaudited condensed consolidated financial statements is included in the footnotes to our financial statements as set forth elsewhere in this annual report on Form 20-F.

Industry and Market Data

This annual report on Form 20-F includes information with respect to market and industry conditions and market share from third party sources or that is based upon estimates using such sources when available. We believe that such information and estimates are reasonable and reliable. We also believe the information extracted from publications of third party sources has been accurately reproduced. However, we have not independently verified any of the data from third party sources. Similarly, our internal research is based upon the understanding of industry conditions, and such information has not been verified by any independent sources.

Coal Reserve Information

We are required by ASX Listing Rules to report ore reserves and mineral resources in Australia in compliance with the Australasian Joint Ore Reserves Committee Code for Reporting of Mineral Resources and Ore Reserves 2012

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Edition, or JORC Code. Under the SEC’s Industry Guide 7, classifications other than proven and probable reserves are not recognized and, as a result, the SEC generally does not permit mining companies like us to disclose measures of mineral resources, such as measured, indicated or inferred resources, in SEC filings.

We have commissioned Marshall Miller & Associates, Inc., or MM&A, to conduct a review of our expanded bankable feasibility study, or BFS. MM&A have provided reserve coal tonnage estimates that are compliant with the SEC’s Industry Guide 7 and accordingly, the reserves disclosed in this annual report on Form 20-F are compliant with the JORC Code and Industry Guide 7. However, we note for you that we have made assumptions about the likely existence of mineralized material when designing our mine plan.

Reserves are defined by the Industry Guide 7 as the part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Reserves are further classified as proven or probable according to the degree of certainty of existence. In determining whether our reserves meet this standard, we take into account, among other things, our potential ability to obtain a mining permit, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in costs required to be incurred to meet regulatory requirements and obtaining or renewing mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. Further, the economic recoverability of our reserves is based on market conditions including contracted pricing, market pricing and overall demand for our coal. Thus, the actual value at which we no longer consider our reserves to be economically recoverable varies depending on the length of time in which the specific market conditions are expected to last. We consider our reserves to be economically recoverable at a price in excess of our cash costs to mine the coal and fund our ongoing replacement capital. The reserves in this annual report on Form 20-F are classified by reliability or accuracy in decreasing order of geological assurance as Proven (Measured) and Probable (Indicated). The terms and criteria utilized to estimate reserves for this study are based on United States Geological Survey Circular 891 and in general accordance with Industry Guide 7, and are summarized as follows:

Proven (Measured) Reserves: Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; and 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.

The information included in this annual report on Form 20-F regarding estimated quantities and quality of our proven and probable coal reserves is based on estimates included in the reports listed below. Such information is included in this annual report on Form 20-F in reliance upon the authority as experts in these matters of the firms that have issued such reports as indicated in this list:

Resource Estimate for the Buck Creek Property as of August 14, 2013 Located in McLean and Hopkins Counties, Kentucky Prepared in Accordance with JORC Code;
Updated Coal Resource Estimate for the Buck Creek Property in Accordance with the Australasian Code for Reporting of Exploration Results, Mineral Resources and Ore Reserves (the JORC Code) as of October 1, 2015;
Interim Buck Creek No. 2 (Poplar Grove) Seam Thickness and Coal Quality Report for Western Kentucky No. 9 Seam July 2016; and
Updated Coal Resource Estimate for the Buck Creek Property in Accordance with the Australasian Code for Reporting of Exploration Results, Mineral Resources and Ore Reserves (the JORC Code) as of February 15, 2017.

See “Item 4. Information on the Company — A. History and Development of the Company — Summary Reserve Data” for further information regarding our coal reserves.

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In addition, we commissioned MM&A to manage all our technical studies, including our BFS, listed below, in conjunction with local industry consultants, with expertise in coal mine development in the Illinois coal basin, or the Illinois Basin, to analyze the various components of the BFS, including, but not limited to, the design of box cut access, design of the mine, design of processing facilities, and the preparation of coal marketing studies. MM&A has over 40 years of expertise in mining engineering, mine reserve evaluation, feasibility studies, and due diligence services for mining and resource projects across the globe. Certain information in this annual report on Form 20-F has been derived from the following reports prepared by MM&A, on behalf of the Company, and delivered to our management:

Cypress Mine Scoping Study February 2014;
Cypress Mine Pre-Feasibility Study March 2015;
Cypress Mine Bankable Feasibility Study November 2015;
Poplar Grove Mine Scoping Study December 2015;
Poplar Grove Mine Bankable Feasibility Study November 2016; and
Poplar Grove Mine Expanded Bankable Feasibility Study March 2017.

Cautionary Note Regarding Forward-Looking Statements

This annual report on Form 20-F contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this annual report on Form 20-F, regarding our strategy, future operations, financial position, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this annual report on Form 20-F, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements with respect to:

future economic conditions in the thermal coal industry generally;
expected costs of developing our planned mining operations, including the costs to construct necessary processing and transport facilities;
estimates of the quantities or quality of our thermal coal reserves;
expectations relating to dividend payments and our ability to make such payments;
the amount or timing of future expenses;
competition in coal markets;
the impact and costs of future compliance with stringent domestic and foreign laws and regulations, including environmental, climate change and health and safety regulations, and permitting requirements, as well as changes in the regulatory environment, the adoption of new or revised laws, regulations and permitting requirements;
the impact of potential legal proceedings and regulatory inquiries against us;
impact of weather and natural disasters on demand, production and transportation;
the timing and amount of purchases by major customers and our ability to renew sales contracts;
credit and performance risks associated with customers, suppliers, contract miners, co-shippers and trading, banks and other financial counterparties;
geologic, equipment, permitting, site access, operational risks and new technologies related to mining;
transportation availability, performance and costs;
availability, timing and delivery and costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;
the amount of expenses and other liabilities incurred or accrued in connection with listing our ADRs;

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the public market for our securities; and
the other risks identified in this annual report on Form 20-F including, without limitation, those under the headings “Risk Factors,” “Business” and “Related Party Transactions.”

All forward-looking statements speak only as of the date of this annual report on Form 20-F. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, objectives, expectations and intentions reflected in or suggested by the forward-looking statements we make in this annual report on Form 20-F are reasonable, we cannot assure you that these plans, objectives, expectations or intentions will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this annual report on Form 20-F.

The forward-looking statements made in this annual report on Form 20-F relate only to events or information as of the date on which the statements are made in this annual report on Form 20-F. Except as required by law, we undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, after the date on which the statements are made or to reflect the occurrence of unanticipated events.

Enforceability of Civil Liabilities

We are a public limited company incorporated under the laws of Australia. Certain of our directors and officers and certain other persons named in this annual report on Form 20-F are citizens and residents of countries other than the United States and all or a significant portion of their assets may be located outside the United States. As a result, it may not be possible for you to:

effect service of process within the United States upon our non-U.S. resident directors or on us;
enforce in U.S. courts judgments obtained against our non-U.S. resident directors or us in the U.S. courts in any action, including actions under the civil liability provisions of U.S. securities laws;
enforce in U.S. courts judgments obtained against our non-U.S. resident directors or us in courts of jurisdictions outside the United States in any action, including actions under the civil liability provisions of U.S. securities laws; or
bring an original action in an Australian court to enforce liabilities against our non-U.S. resident directors or us based solely upon U.S. securities laws.

You may also have difficulties enforcing in courts outside the United States judgments that are obtained in U.S. courts against any of our non-U.S. resident directors or us, including actions under the civil liability provisions of the U.S. securities laws.

With that noted, there are no treaties between Australia and the United States that would affect the recognition or enforcement of foreign judgments in Australia. We also note that investors may be able to bring an original action in an Australian court against us to enforce liabilities based in part upon U.S. federal securities laws.

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PART I.

ITEM 1.IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
A.Directors and Senior Management

The following table lists the names of our directors and executive officers. The business address for each director and member of senior management is Level 9, 28 The Esplanade, Perth, Western Australia 6000, unless otherwise indicated.

Name
Age
Position
Ian Middlemas
58
Director and Chairman of the Board
Todd Hannigan
45
Director and Deputy Chairman of the Board and interim Chief Executive Officer
David Gay
59
Executive Director and President
Richard Kim
39
Chief Operating Officer
Adam Anderson
48
Senior Vice President, Coal Sales and Marketing
Dominic Allen
35
Vice President, Finance
Bruce Czachor
57
Vice President and General Counsel
Gregory Swan
37
Company Secretary
Jonathan Hjelte
36
Director
Richard McCormick
59
Director
Thomas Todd
44
Director

There are no family relationships among any of our directors or executive officers. The business addresses for each of our directors and executive officers is Paringa Resources Limited, Level 9, 28 The Esplanade, Perth, WA 6000, Australia.

For further details, see “Directors, Senior Management and Employees.”

B.Advisers

Our principal Australian legal advisers are DLA Piper, located at Level 31, Central Park, 152-158 St. Georges Terrace, Perth WA 6000, Australia. Our principal United States legal advisors are Gibson, Dunn & Crutcher LLP, located at 200 Park Avenue, New York, New York 10166, and Frost Brown Todd LLC, located at Lexington Financial Center, 250 West Main Street, Suite 2800, Lexington, Kentucky 40507.

C.Auditors

Deloitte Touche Tohmatsu served as our principal independent registered public accounting firm for the fiscal years ended June 30, 2016, 2017 and 2018. The address of Deloitte Touche Tohmatsu is Tower 2, Brookfield Place, 123 St. Georges Terrace, Perth Western Australia, 6000.

ITEM 2.OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3.KEY INFORMATION
A.Selected Financial Data

The following tables present the selected consolidated financial data of the Company. The selected extracts from the statements of profit or loss and statements of cash flow for the fiscal years ended June 30, 2016, 2017 and 2018 and extracts from the statements of financial position for fiscal years ended June 30, 2017 and 2018 have been derived from our audited consolidated financial statements, which are included in this Annual Report beginning on page F-1. The selected extracts from the statement of profit or loss and statement of cash flow for the fiscal years ended June 30, 2015 and extracts from the statement of financial position for the fiscal year ended June 30, 2016 have been derived from our previously audited consolidated financial statements, which are not included in this Annual Report.

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The summary consolidated financial data below should be read in conjunction with our consolidated financial statements beginning on page F-1 of this annual report on Form 20-F and with the information appearing in the section of this annual report on Form 20-F entitled “Operating and Financial Review and Prospects.” Our historical results do not necessarily indicate results expected for any future period.

Summary Financial Information

Consolidated Statements of Profit or Loss data:
(in thousands, except per share data)
For the year ended June 30,
2018
2017
2016
2015
Interest income
$
341
 
$
111
 
$
50
 
 
143
 
Exploration and evaluation expenses
 
 
 
(1,526
)
 
(1,327
)
 
(1,879
)
Corporate and administrative expenses
 
(1,207
)
 
(594
)
 
(302
)
 
(352
)
Business development expenses
 
(269
)
 
(331
)
 
(96
)
 
(42
)
Foreign stock exchange listing expenses
 
(767
)
 
 
 
 
 
 
Employment expenses
 
(2,958
)
 
(2,337
)
 
(2,245
)
 
(2,308
)
Share-based payment expenses
 
(2,298
)
 
(674
)
 
(507
)
 
(546
)
Depreciation and impairment expenses
 
(13
)
 
(541
)
 
(30
)
 
(34
)
Other income and expenses
 
56
 
 
(63
)
 
(24
)
 
338
 
(Loss) before income tax
 
(7,115
)
 
(5,955
)
 
(4,481
)
 
(4,680
)
Income tax expense
 
 
 
 
 
 
 
 
Net (loss) for the year
 
(7,115
)
 
(5,955
)
 
(4,481
)
 
(4,680
)
Net (loss) attributable to members
 
(7,115
)
$
(5,955
)
$
(4,481
)
$
(0.03
)
Basic and diluted (loss) per share from continuing operations
$
($0.02
)
$
($0.03
)
$
($0.03
)
$
(0.03
)
Weighted average of ordinary shares outstanding (in thousands)
 
326,101
 
 
213,376
 
 
153,123
 
 
136,983
 
Consolidated Statements of Financial Position data:
(in thousands)
As of June 30,
2018
2017
2016
Cash and cash equivalents
$
22,623
 
$
34,802
 
$
303
 
Trade and other receivables
 
78
 
 
265
 
 
15
 
Total current assets
 
22,701
 
 
35,067
 
 
318
 
Property, plant and equipment
 
59,065
 
 
26,068
 
 
120
 
Exploration and evaluation assets
 
 
 
 
 
17,544
 
Other assets
 
6,551
 
 
4,044
 
 
29
 
Total assets
 
88,317
 
 
65,179
 
 
18,011
 
Total current liabilities
 
9,914
 
 
4,604
 
 
1,688
 
Total liabilities
 
11,227
 
 
4,604
 
 
1,688
 
Total equity
$
77,090
 
$
60,575
 
$
16,323
 
Consolidated Statements of Cash Flow data:
(in thousands)
For the year ended June 30,
2018
2017
2016
2015
Net cash outflow from operating activities
 
(4,132
)
$
(4,990
)
$
(3,838
)
 
(4,489
)
Net cash outflow from investing activities
 
(28,179
)
 
(8,575
)
 
(858
)
 
(1,475
)
Net cash inflow from financing activities
 
20,076
 
 
48,128
 
 
3,450
 
 
4,371
 
Net change in cash and cash equivalents
 
(12,235
)
 
34,563
 
 
(1,246
)
 
(1,543
)
Net foreign exchange differences
 
56
 
 
(64
)
 
(62
)
 
(1,055
)
Cash and cash equivalents at beginning of the year
 
34,802
 
 
303
 
 
1,611
 
 
4,259
 
Cash and cash equivalents at the end of the year
 
22,623
 
$
34,802
 
$
303
 
$
1,611
 
B.Capitalization and Indebtedness

Not applicable.

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C.Reasons for the Offer and Use of Proceeds

Not applicable.

D.Risk Factors

You should carefully consider the risks described below, together with all of the other information in this annual report on Form 20-F. If any of the following risks occur, our business, financial condition and results of operations could be seriously harmed and you could lose all or part of your investment. Further, if we fail to meet the expectations of the public market in any given period, the market price of the ADSs could decline. We operate in a competitive environment that involves significant risks and uncertainties, some of which are outside of our control. If any of these risks actually occurs, our business and financial condition could suffer and the price of the ADSs could decline.

Risks Related to our Business

Our properties have not yet been developed into producing coal mines and, if we experience any development delays or cost increases or are unable to complete the construction of our facilities, our business, financial condition, and results of operations could be adversely affected.

We have not yet completed our development plan and do not expect to have full annual production from any of our properties until 2020. We expect to incur significant capital expenditures until we have completed the development of our properties. We previously estimated that total initial capital expenditures of approximately $56.8 million would be required to construct the Poplar Grove Mine. As of September 30, 2018, we estimate that approximately $21.2 million remains to be spent to complete construction of the Poplar Grove Mine. We have also estimated that total initial capital expenditures of approximately $101.8 million will be required to construct the Cypress Mine, if undertaken. In addition, there will be operating losses which need to be funded as the business undergoes commissioning and ramps up to full production. The development of our properties involves numerous regulatory, environmental, political and legal uncertainties that are beyond our control and that may cause delays in, or increase the costs associated with, their completion. Accordingly, we may not be able to complete the development of the properties on schedule, at the budgeted cost or at all, and any delays beyond the expected development periods or increased costs above those expected to be incurred could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to pay dividends to our stockholders.

In connection with the development of our properties, we may encounter unexpected difficulties, including the following:

shortages of materials or delays in delivery of materials;
unexpected operational events;
facility or equipment malfunctions or breakdowns;
unusual or unexpected adverse geological conditions;
cost overruns;
failure to obtain, or delays in obtaining, all necessary governmental and third-party rights-of-way, easements, permits, licenses and approvals for the development, construction and operation of one or more of our properties, including the permits still required at our Poplar Grove and Cypress Mine projects;
adverse weather conditions and other catastrophes, such as explosions, fires, floods and accidents;
difficulties in attracting a sufficient skilled and unskilled workforce, increases in the level of labor costs and the existence of any labor disputes; and
adverse local or general economic or infrastructure conditions.

If we are unable to complete or are substantially delayed in completing the development of any of our properties, our business, financial condition, results of operations or cash flows could be adversely affected.

Because we have no operating history and have not yet generated any operating revenues or operating cash flows, you may have difficulty evaluating our ability to successfully implement our business strategy.

Because of our lack of operating history, the operating performance of our properties and our business strategy have not yet been proven. As a result, our historical financial statements do not provide a meaningful basis to evaluate our

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operations or our ability to achieve our business strategy. Therefore, it may be difficult for you to evaluate our business and results of operations to date and assess our future prospects. In addition, we may encounter risks and difficulties experienced by companies whose performance is dependent upon newly-constructed assets, such as any one of our properties failing to perform as expected, having higher than expected operating costs, having lower than expected customer revenues, or suffering equipment breakdown, failures or operational errors. We may be less successful in achieving a consistent operating level capable of generating cash flows from our operations as compared to a company whose major assets have had longer operating histories. In addition, we may be less equipped to identify and address operating risks and hazards in the conduct of our business than those companies whose major assets have had longer operating histories.

We have no operating history and our future performance is uncertain.

We are a development stage enterprise and will continue to be so until commencement of substantial production from our coal properties. Subject to the risks noted above, we do not expect to commence production until the December 2018 quarter at any of our properties, and therefore we do not expect to generate any revenue until that period. We have generated substantial net losses and negative cash flows from operating and investing activities since our inception and expect to continue to incur substantial net losses as we continue our mine development program. We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. New companies must develop successful business relationships, establish operating procedures, hire staff, install management information and other systems, establish facilities and obtain licenses, as well as take other measures necessary to conduct their intended business activities. We may not be successful in implementing our business strategies or in completing the development of the infrastructure necessary to conduct our business as planned, which may adversely affect our results of operations, financial condition or cash flows. In the event that one or more of our mine development programs are not completed or are delayed or terminated, our operating results will be adversely affected and our operations will differ materially from the activities described in this annual report on Form 20-F.

Global economic conditions or economic conditions in any of the industries in which our customers operate as well as sustained uncertainty in financial markets may adversely affect our results of operations, financial condition or cash flows.

Weakness in global economic conditions or economic conditions in any of the industries we serve or in the financial markets could materially adversely affect our business, financial condition or cash flows. For example:

the demand for electricity in the United States may decline if economic conditions deteriorate, which may adversely affect our revenues, margins and profitability;
any inability of our customers to raise capital could adversely affect their ability to honor their obligations to us; and
our future ability to access the capital markets may be restricted as a result of future economic conditions, which could adversely affect our ability to grow our business, including development of our coal reserves.

A substantial or extended decline in coal prices could reduce our revenues and adversely affect our results of operations, cash flows, financial condition, stock price and the value of our coal reserves.

Our results of operations will depend upon the prices we receive for our coal, as well as our ability to improve productivity and control costs. The prices we will receive for our production may depend upon factors beyond our control, including:

the supply of and demand for coal, which depends significantly on the demand for electricity;
adverse weather conditions and patterns, climatic or other natural conditions, including natural disasters, that affect demand for, or our ability to produce, coal;
the proximity to and availability, reliability and cost of transportation and port facilities;
competition from other coal suppliers and other energy sources;
domestic and foreign governmental regulations and taxes for our industry and those of our customers;
economic conditions, including economic downturns and the strength of the global and U.S. economies;

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the price and availability of natural gas and alternative fuels;
the quantity, quality and pricing of coal available in the resale market;
the effects of worldwide energy conservation or emissions measures;
the effect of worldwide energy consumption, including the impact of technological advances on energy consumption; and
the consumption pattern of industrial customers, electricity generators and residential users.

Any adverse change in these factors could result in weaker demand and lower prices for our products. A substantial or extended decline in coal prices in the United States and other countries may materially adversely affect our operating results and cash flows by decreasing our revenues, 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.

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 expect to compete with numerous other coal producers in various regions of the United States for domestic and international sales. We also expect to compete in international markets against coal producers in other countries. International demand for U.S. coal exports also affects coal demand in the United States. This competition affects coal prices and could adversely affect 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. 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. 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 favourable 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, if any, 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 “Item 4. Information on the Company—B. Business Overview—Competition.”

The most important factors on which we expect to compete are delivered price (i.e., the cost of coal delivered to the customer, including transportation costs, which are generally paid by our customers either directly or indirectly), coal quality characteristics, contract flexibility (e.g., volume optionality and multiple supply sources) and reliability of supply. Some competitors may have, among other things, larger financial and operating resources, lower per ton cost of production, or relationships with specific transportation providers. The competition among coal producers may impact our ability to retain or attract customers and could adversely impact our revenues and cash available for distribution. In addition, declining prices from an oversupply of coal in the market could reduce our revenues and cash available for distribution.

Decreases in consumer demand for electricity and changes in general energy consumption patterns attributable to energy conservation trends could adversely affect our financial condition, results of operations or cash flows.

The electricity utility industry in the United States accounts for over 92.0% of U.S. domestic coal consumption. The amount of coal consumed by the U.S. domestic electricity utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as alternative sources of energy. Electricity generation fueled by natural gas has the potential to displace coal-fueled generation, particularly from older, less efficient coal-powered generators. We expect that many of the new power plants needed in the United States to meet

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increasing demand for electricity generation will be fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain relative to coal-fueled plants.

Future environmental regulation of greenhouse gas, or GHG, emissions also could accelerate the use by utilities of fuels other than coal. In addition, state and federal mandates for increased use of electricity derived from renewable energy sources could affect demand for coal. For example, the Clean Power Plan, or CPP, of the United States Environmental Protection Agency, or EPA, could incentivize additional electricity generation from natural gas and renewable sources, and Congress has extended tax credits for renewable energy. In addition, a number of states have enacted mandates that require electricity suppliers to rely on renewable energy sources in generating a certain percentage of power. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive relative to coal. A decrease in coal consumption by the U.S. electricity utility industry could adversely affect the price of coal, which could adversely affect our results of operations and cash flows.

Efforts to promote energy conservation in recent years could reduce both the demand for electricity and the general energy consumption patterns of consumers worldwide. The ability of energy conservation technologies, public initiatives and government incentives to reduce electricity consumption or to support forms of renewable energy could reduce the price of coal. If coal prices decrease, our financial condition, results of operations or cash flows may be adversely affected.

Feasibility study results are based on assumptions that are subject to uncertainty and the estimates may not reflect actual capital and operating costs or revenues from any potential future production.

Feasibility studies, including our BFS, are used to determine the economic viability of a mineral deposit. Such studies require us to make numerous assumptions, including assumptions about capital and operating costs and future coal prices. These assumptions are made at the time the study is completed based on information then available. We cannot assure you that actual costs or revenues will not vary significantly and adversely from the estimates used in the study. Accordingly, the economic viability of our mines, or the amount of mineral deposits that we will be able to economically extract, may differ materially from our estimates set forth in this annual report on Form 20-F.

We may depend on a limited number of customers for a significant portion of our revenues.

We likely will depend on a limited number of customers for a significant portion of our revenues. The failure to obtain additional customers or the loss of all or a portion of the revenues attributable to any customer as a result of competition, creditworthiness, inability to negotiate extensions or replacement of contracts or otherwise, could have adversely affect our financial condition, results of operations or cash flows.

Economic downturns and disruptions in the global financial markets have had, and may in the future have, an adverse effect on the demand for and price of coal.

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. These sorts of disruptions, and in particular, the tightening of credit in financial markets, could result in a decrease demand for and the price of coal. 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 adversely affect the demand for and price of coal.

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 effect of human activity GHG emissions, such as carbon dioxide and methane, on global climate. 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, steelmaking plants and, to a lesser extent, the mining equipment we use. In addition, coal mining can release methane directly into the atmosphere. Concerns

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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 of many existing coal-fired power plants, fewer new coal-fired power plants, increased mining costs 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:

the 2015 Paris climate summit agreement, which resulted in voluntary commitments by 195 countries (although on June 1, 2017, the Trump administration announced that the U.S. will withdraw from the agreement) to reduce their GHG emissions and could result in additional firm commitments by various nations with respect to future GHG emissions;
federal regulations such as the Clean Power Plan, or 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;
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 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 reduce 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 U.S. Bureau of Land Management, or BLM, and the U.S. Office of Surface Mining Reclamation and Enforcement, or OSM, to challenge not only the issuance of individual

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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 to materially decline and our costs to increase.

Any future laws, regulations or other policies or initiatives of the nature described above may adversely affect 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 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 effect of one or more such laws, regulations or policies, if adopted and ultimately implemented as proposed, may adversely affect our operations, financial condition or cash flows.

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, which may make them unprofitable. Accordingly, some existing power generators have switched to other fuels that generate fewer emissions and others are likely to switch, some power plants have closed and others are likely to close, and fewer new coal-fired plants are being constructed, all of which reduce demand for coal and the amount of coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely affect our results of operations and the value of our coal reserves.

Extensive environmental laws and regulations, including existing and potential future legislation, treaties and regulatory requirements relating to air emissions, waste management and water discharges, affect coal customers, and could further reduce the demand for coal as a fuel source and cause prices and sales of coal to materially decline.

We expect that our customers’ operations will be 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:

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;
implementation of the EPA’s Cross-State Air Pollution Rule, or 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, or 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.

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These costs make coal more expensive to use and make it a less attractive fuel source of energy. 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.

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 coal based on its sulfur content. We plan to sell both higher sulfur and low sulfur coal. If power generators widely install technology that reduces sulfur emissions, demand for high sulfur coal may decrease relative to 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 events could adversely affect our business and results of operations.

Our mining operations are subject to extensive and costly laws and regulations, and current or future laws and regulations could increase current operating costs or limit our ability to produce coal.

Our operations are subject to numerous U.S. federal, state and local laws and regulations affecting the coal mining industry, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge or release of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. We will 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 may 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. In addition, these laws and regulations will require us to obtain numerous governmental permits and comply with the requirements of those permits (described in more detail below).

Certain of these laws and regulations may impose strict liability without regard to fault or legality of the original conduct. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial liabilities, and the issuance of injunctions limiting or prohibiting the performance of operations. Complying with these laws and regulations may be costly and time consuming and may delay commencement or continuation of exploration, development or production operations. It is possible that new laws or regulations may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations may occur, which could adversely affect our results of operations or cash flows.

State and federal laws addressing mine safety practices impose stringent reporting requirements and civil and criminal penalties for violations. Federal and state regulatory agencies continue to interpret and implement these laws and propose new regulations and standards. Implementing and complying with these laws and regulations has increased and will continue to increase our operational expense and adversely affect our financial condition or results of operation.

The Mine Safety and Health Administration, or 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. We expect that these factors will have a significant effect on our costs of production and competitive position, and may adversely affect our financial condition, results of operations or cash flows.

We may be unable to obtain and renew permits, leases or other rights necessary for our operations, which could reduce our production, results of operations or cash flow.

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.

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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 or to deny the issuance of additional permits or the 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 expect that many of our permits will be subject to renewal from time to time, and renewed permits may contain more restrictive conditions than our existing permits.

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.

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 carbon dioxide from electric generating units that use 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 further reduce the demand for coal as a fuel source, causing coal prices to decline, perhaps materially.

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, we may have to purchase coal from third-party sources, if it is available, incur capital expenditures to re-open the facilities or negotiate settlements with 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 materially adversely affect 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 (1) the elimination of current deductions, the 60-month amortization

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period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (2) the repeal of the percentage depletion allowance with respect to coal properties, and (3) the repeal of capital gains treatment of coal and lignite royalties. The passage of these or other similar proposals could negatively affect our results of operations and cash flows.

Changes in U.S. federal, state, or county tax laws, particularly in the areas of non-income taxes and royalties, could adversely affect our financial condition and results of operations.

We expect to pay U.S. federal and state royalties and federal, state and county non-income taxes on the coal we will produce. We expect that a substantial portion of our royalties and non-income taxes will be levied as a percentage of gross revenues, while others will be levied on a per ton basis. If the royalty and non-income tax rates were to significantly increase, our results of operations could be materially and adversely affected.

Defects in title or loss of any leasehold interests in our properties could limit our ability to conduct mining operations on these properties or result in significant unanticipated costs.

A title defect or the loss of any lease upon expiration of its term, upon a default or otherwise, could adversely affect our ability to mine the associated reserves or process the coal that we mine. Title to most of our owned or leased properties and mineral rights is not usually verified until we make a commitment to mine a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our lessors or grantors. Our right to mine certain of our reserves may be adversely affected if defects in title, boundaries or other rights necessary for mining exist or if a lease expires. Any challenge to our title or leasehold interests could delay the mining of the property and could ultimately result in the loss of some or all of our interest in the property. From time to time we also may be in default with respect to leases for properties on which we have mining operations. In such events, we may have to close down or significantly alter the sequence of such mining operations which may adversely affect our future coal production and future revenues. If we mine on property that we do not own or lease, we could incur liability for such mining and be subject to regulatory sanction and penalties.

In order to obtain, maintain or renew leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases or mining contracts for properties containing additional reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease. As a result, our results of operations, business and financial condition may be materially adversely affected.

Numerous political and regulatory authorities and governmental bodies, as well as environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, thereby further reducing the demand and pricing for coal and potentially materially and adversely affecting our financial condition, results of operations or cash flows.

Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion in many jurisdictions, unfavorable lending policies by lending institutions and divestment efforts affecting the investment community, which could adversely affect demand for our products or our securities. Global climate issues continue to attract public and scientific attention. Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. 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, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions of carbon dioxide from coal combustion by power plants.

Federal, state and local governments may pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may decrease demand for coal products. The CPP is one of a number of recent developments aimed at limiting GHG emissions which could limit the market for coal products by encouraging electric generation from sources that do not generate the same amount of GHG emissions. Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S., states, or other countries, could also result in electricity generators further switching from coal to other fuel sources or additional coal-fueled power plant closures. For example, the agreement resulting from the 2015 U.N. Framework Convention on Climate Change

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contains voluntary commitments by numerous countries to reduce their GHG emissions, and could result in additional firm commitments by various nations with respect to future GHG emissions. These commitments could further disfavour coal-fired generation, particularly in the medium-to long-term.

Congress has extended certain tax credits for renewable sources of electric generation, which will increase the ability of these sources to compete with our coal products in the market. In addition, the Department of Interior recently announced a moratorium on issuing certain new coal leases on federal land while the Bureau of Land Management undertakes a programmatic review of the federal coal program. While none of our operations are located on federal lands impacted by this moratorium, it does signal increased attention at the federal level to coal mining practices and the GHG emissions resulting from coal combustion.

There have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. In California, for example, legislation was signed into law in October 2015 that requires California’s state pension funds to divest investments in companies that generate 50% or more of their revenue from coal mining by July 2017. Other activist campaigns have urged banks to cease financing coal-driven businesses. As a result, several major banks have enacted such policies. The impact of such efforts may adversely affect the demand for and price of securities issued by us, and impact our access to the capital and financial markets.

In addition, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation. Collectively, these actions and campaigns could adversely impact our future financial results, liquidity and growth prospects.

Government regulations have resulted and could continue to result in significant retirements of coal-fired electric generating units. Retirements of coal-fired electric generating units decrease the overall capacity to burn coal and negatively affect coal demand, which could adversely affect our business and results of operation.

Since 2010, utilities have formally announced the retirement or conversion of 558 coal-fired electric generating units through 2030. These retirements and conversions amount to over 93,000 megawatts, or MW, or almost 30% of the 2010 total coal electric generating capacity. At the end of 2016 retirement and conversions affecting 60,000 MW, or approximately 19% of the 2010 total coal electric generating capacity, are estimated to have occurred. Most of these announced and completed retirements and conversions have been attributed to the EPA regulations, although other factors such as an aging coal fleet and low natural gas prices have also played a role. The reduction in coal electric capacity negatively impacts overall coal demand. Additional regulations and other factors could lead to additional retirements and conversions and, thereby, additional reductions in the demand for coal which could have an adverse effect on our business and results of operations.

Plaintiffs in federal court litigation have attempted to pursue tort claims based on the alleged effects of climate change.

In 2004, eight states and New York City sued five electric utility companies in Connecticut v. American Electric Power Co. Invoking the federal and state common law of public nuisance, plaintiffs sought an injunction requiring defendants to abate their contribution to the nuisance of climate change by capping carbon dioxide emissions and then reducing them. In June 2011, the U.S. Supreme Court issued a unanimous decision holding that the plaintiffs’ federal common law claims were displaced by federal legislation and regulations. The U.S. Supreme Court did not address the plaintiffs’ state law tort claims and remanded the issue of preemption for the district court to consider. While the U.S. Supreme Court held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, tort-type liabilities remain a possibility and a source of concern. Proliferation of successful climate change litigation could adversely affect demand for coal and ultimately have a material adverse effect on our business, financial condition or results of operations.

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.

We expect that our operations will use certain hazardous materials, and that from time to time we will 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. These and other environmental impacts that our operations may have, as

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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.

Risks Relating to Our Operations

Our coal mining production and delivery will be subject to conditions and events beyond our control that could result in higher operating expenses and decreased production and sales.

We expect that our coal production at our mines will be 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 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;
mine safety accidents, including fires and explosions from methane and other sources;
hazards or occurrences that could result in personal injury and loss of life;
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 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.

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 results of operations or decrease the value of our assets.

We expect to maintain insurance policies that may provide limited coverage for some of these risks. Even when 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 financial condition, results of operations or cash flows.

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Our ability to operate our business 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 continued contributions of our executive officers and other key employees. The loss of any of our key senior executives could have a material adverse effect on our business unless and until we find a replacement. A limited number of persons exist with the requisite experience and skills to serve in our senior management positions. We may not be able to locate or employ qualified executives on acceptable terms. In addition, we believe that our future success will depend on our continued ability to attract and retain highly skilled personnel with coal industry experience. Competition for these persons in the coal industry is intense and we may not be able to successfully recruit, train or retain qualified managerial personnel. As a public company, our future success also will depend on our ability to hire and retain management with public company experience. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future. Our failure to retain or attract key personnel could have a material adverse effect on our ability to effectively operate our business.

A shortage of skilled mining labor in the United States could decrease our labor productivity and increase our labor costs, which would adversely affect our profitability.

Efficient coal mining using complex and sophisticated techniques and equipment requires skilled laborers proficient in multiple mining tasks, including mining equipment maintenance. Any shortage of skilled mining labor reduces the productivity of experienced employees who must assist in training unskilled employees. If a shortage of experienced labor occurs, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our financial condition or results of operations.

Litigation resulting from disputes with our customers may result in substantial costs, liabilities and loss of revenues.

From time to time we may have disputes with our customers over the provisions of long-term coal supply contracts relating to, among other things, coal pricing, quality, quantity and the existence of specified conditions beyond our or our customers’ control that suspend performance obligations under the particular contract. Disputes may occur in the future, and we may not be able to resolve those disputes in a satisfactory manner, which could have a material adverse effect on our business, financial condition or results of operations.

Coal competes with natural gas and renewable energy sources, and factors affecting these industries could adversely affect our sales.

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. Natural gas prices have declined significantly in recent years and may continue to decline, which could lead to reduced coal sales and have a material adverse effect on our financial condition, results of operations or 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.

Major equipment and plant failures could reduce our ability to produce and ship coal and materially and adversely affect our results of operations.

We expect to depend on several major pieces of mining equipment and preparation plants to produce and ship our coal, including, but not limited to, longwall mining systems, preparation plants, and transloading facilities. If any of these pieces of equipment or facilities suffered major damage or were destroyed by fire, abnormal wear, flooding, incorrect operation or otherwise, we may be unable to replace or repair them in a timely or cost efficient manner.

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Although none of our employees are members of unions, our work force may not remain union-free in the future.

None of our employees are currently represented under collective bargaining agreements. However, under the U.S. National Labor Relations Act, employees have the right at any time to form or affiliate with a union. Any future 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. Therefore, all of our work force may not remain union-free in the future, and legislative, regulatory or other governmental action could make it more difficult to remain union-free. If some or all of our currently union-free operations were to become unionized, it could adversely affect our productivity and increase the risk of work stoppages at our mining complexes. In addition, even if we remain union-free, our operations may still be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our operations.

Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenues by causing us to reduce our production or by impairing our ability to supply coal to our customers and could adversely affect our business.

We expect that transportation costs will represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation will be a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources. Disruption of transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events could temporarily impair our ability to supply coal to our customers. 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. Our transportation providers may face difficulties in the future that may impair our ability to supply coal to our customers, resulting in decreased revenues. If there are disruptions of the transportation services provided by our primary rail or barge carriers that transport our coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

Conversely, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, difficulty in coordinating the many eastern coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make coal shipments originating in the eastern United States inherently more expensive on a per-mile basis than coal shipments originating in the western United States. Historically, high coal transportation rates from the western coal producing areas into certain eastern markets limited the use of western coal in those markets. Lower rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created major competitive challenges for eastern coal producers. In the event of further reductions in transportation costs from western coal producing areas, the increased competition with certain eastern coal markets could have a material adverse effect on our business, financial condition and results of operations.

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.

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Completion of growth projects and future expansion could require significant amounts of financing that may not be available to us on acceptable terms, or at all, and failure to obtain this necessary capital when needed may force us to delay, limit or terminate future growth projects.

We plan to fund capital expenditures for our current growth projects with existing cash balances, debt financing and future cash flows from operations. We previously estimated that total initial capital expenditures of approximately $56.8 million would be required to construct the Poplar Grove Mine. As of September 30, 2018, we estimate that approximately $21.2 million remains to be spent to complete construction of the Poplar Grove Mine. We have also estimated that total initial capital expenditures of $101.8 million will be required to construct the Cypress Mine, if undertaken. Weakness in the energy sector in general and coal in particular has significantly reduced access to the debt and equity capital markets for some coal companies. Accordingly, our funding plans may be negatively affected by this constrained environment as well as numerous other factors, including higher than anticipated capital expenditures or lower than expected cash flow from operations. Furthermore, exploration and development of the Cypress Mine or other expansion opportunities could require significant amounts of financing that may not be available to us on acceptable terms or at all.

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.

The estimates of our coal reserves may vary substantially from actual amounts of coal we are able to economically recover. The reserve data set forth in this annual report on Form 20-F represent our engineering estimates. All of the reserves presented in this annual report on Form 20-F constitute proven and probable reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may vary considerably from actual results. These factors and assumptions relate to:

geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our experiences in areas where we currently mine;
the percentage of coal in the ground ultimately recoverable;
historical production from the area compared with production from other producing areas;
the assumed effects of regulation and taxes by governmental agencies;
future improvements in mining technology; and
assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes and development and reclamation costs.

For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. 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.

Substantially all of our coal reserves are leased from landowners and, if we begin construction, additional mineral leases must be acquired in order to execute the life of mine plan of the Poplar Grove and Cypress Mines.

We lease the majority of our coal reserves from landowners and generally have the right to maintain leases in force until the exhaustion of mineable and merchantable coal located within the leased premises or a larger coal reserve area. These leases provide for the payment of annual minimum advance royalties prior to the commencement of mining operations and the payment of earned royalties once mining operations commence. These minimum royalties generally start at $10 per acre per year and escalate every five years to a maximum of $25 per acre beginning in the 15th year. We ordinarily have no obligation to continue paying these minimum royalties once we cease production on a particular landowner’s property. These minimum royalties are normally recoupable against the earned royalties owed to a lessor once coal production has commenced.

Kentucky state law allows the owner or controller of a partial interest tract to develop the tract in a manner consistent with full control of the property. Therefore, we expect, but cannot assure you, that any partial interest tracts that are

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less than 100% leased can be developed. Not all of the mine plans for Poplar Grove and Cypress Mines can be mined on mineral property currently controlled by us. Additional mineral leases representing approximately one-third of the life-of-mine land must be acquired in order to execute the life of mine plan to achieve the projected financial performance of the Poplar Grove and Cypress Mine. If we are unable to successfully negotiate these additional coal leases with any or all of these surface owners, or to do so on commercially reasonable terms, we may be unable to mine these areas which may 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 additional costs to do so, which could increase our operating expenses and could adversely affect our results of operations.

Decreased availability or increased costs of key equipment and materials could adversely affect our costs of production and results of operations.

We expect that our coal mining operations will be affected by commodity prices. We will 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 will pay for these materials will be strongly influenced by the global commodities markets. Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives and diesel and other liquid fuels. If the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses will increase, which could materially adversely impact our profitability. Some materials, such as steel, are needed to comply with regulatory requirements. Furthermore, operating expenses at our mining locations will be sensitive to changes in certain variable costs, including diesel fuel prices, which will be one of our largest variable costs. Our results will 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 will have limited ability to negotiate lower prices.

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 United States. 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 Related to Our Liquidity

We may need additional funds to develop our properties.

Our operations have in the past and will in the future require substantial amounts of cash. We expect to continue to incur substantial capital expenditures to complete development of our mines. To finance our business plan, we have incurred indebtedness through the Project Loan Facility. Based on our current financial position, including the Project Loan Facility, and assuming drawdown of the second and final tranche of the Project Loan Facility, we expect to have sufficient cash flow to complete the construction of the Poplar Grove Mine and commence commercial coal production, but there can be no assurances that we will have sufficient cash to complete construction of the Poplar Grove Mine and maintain adequate liquidity to satisfy all future working capital requirements.

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The terms of the Project Loan Facility contain affirmative and negative covenants, which impose operating and financial limitations and restrictions on us, including restrictions on our ability to enter into particular transactions and to engage in other actions that we may believe are advisable or necessary for our business. In addition, the occurrence of an event of default under the Project Loan Facility may entitle the lenders under such arrangements to exercise certain remedies, including the acceleration of repayment of outstanding borrowings under the Project Loan Facility or the enforcement of security interests over our assets. In such circumstances, if we were unable to raise additional funds through equity or debt financing, we may not have the necessary cash resources to finance our business plan.

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 will require us to place and maintain bonds to secure our obligations to repair and return property to its approximate original state after it has been mined (often referred to as “reclaim” or “reclamation”), to pay federal and state workers’ compensation and pneumoconiosis, or black lung, benefits and to satisfy other miscellaneous obligations. These bonds provide assurance that we will perform our statutorily required obligations and are referred to as “surety” bonds. These bonds are typically renewable on a yearly basis. The failure to maintain or the inability to acquire sufficient surety bonds, as required by state and federal laws, could subject us to fines and penalties and result in the loss of our mining permits. Such failure could result from a variety of factors, including:

lack of availability, higher expense or unreasonable terms of new surety bonds;
the ability of current and future surety bond issuers to increase required collateral, or limitations on availability of collateral for surety bond issuers due to the terms of our credit agreements; and
the exercise by third-party surety bond holders of their rights to refuse to renew the surety.

Our inability to acquire or failure to maintain these bonds, or a substantial increase in the bonding requirements, would have a material adverse effect on us.

Risks Related to the ADSs

The market price and trading volume of the ADSs may be volatile and may be affected by economic conditions beyond our control.

The market price of the ADSs may be highly volatile and subject to wide fluctuations. In addition, the trading volume of the ADSs may fluctuate and cause significant price variations to occur. If the market price of the ADSs declines significantly, you may be unable to resell your ADSs at or above the purchase price, if at all. We cannot assure you that the market price of the ADSs will not fluctuate or significantly decline in the future.

Some specific factors that could adversely affect the price of the ADSs or result in fluctuations in their price and trading volume include:

actual or expected fluctuations in our operating results;
changes in market valuations of similar companies;
changes in our key personnel;
changes in financial estimates or recommendations by securities analysts;
changes in trading volume of ADSs on Nasdaq and of our ordinary shares on the ASX;
sales of the ADSs or ordinary shares by us, our executive officers or our shareholders in the future; and
conditions in the financial markets or changes in general economic conditions.

An active trading market for the ADSs may not develop.

We recently listed our ADSs on the Nasdaq Capital Market. If an active public market in the United States for the ADSs does not develop or is not sustained, the market price and liquidity of the ADSs may be adversely affected.

The dual listing of our ordinary shares and the ADSs may adversely affect the liquidity and value of the ADSs.

Our ordinary shares are listed on the ASX, and our ADSs are listed on the Nasdaq Capital Market. We cannot predict the effect of this dual listing on the value of our ordinary shares and ADSs. However, the dual listing of our ordinary

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shares and the ADSs may dilute the liquidity of these securities in one or both markets and may adversely affect the development of an active trading market for the ADSs in the United States. The price of the ADSs could also be adversely affected by trading in our ordinary shares on the ASX.

Future sales of our ordinary shares or the ADSs, or the perception that such sales may occur, could depress our ordinary share price.

Almost all of our shares may be resold in the public market. In addition, we may engage in future equity financings to finance our business plan. Resale of our securities offered, future equity offerings or the perception that such equity offerings will occur may cause the market price of our ordinary shares to drop significantly. These factors could also make it more difficult for us to raise additional funds through future equity offerings.

As a foreign private issuer, we are permitted and expect to follow certain home country corporate governance practices in lieu of certain Nasdaq requirements applicable to domestic issuers.

As a foreign private issuer listed on Nasdaq, we are permitted to follow certain home country corporate governance practices in lieu of certain Nasdaq requirements. Following our home country corporate governance practices, as opposed to the requirements that would otherwise apply to a U.S. company listed on Nasdaq, may provide less protection than is afforded to investors under Nasdaq rules applicable to domestic issuers. See “Item 10. Additional Information—Share Capital—Exemptions from Certain Nasdaq Corporate Governance Rules.”

In particular, we expect to follow home country law instead of Nasdaq practice in the following ways:

We expect to rely on an exemption from the independence requirements for a majority of our Board of Directors as prescribed by Nasdaq rules. The ASX Listing Rules do not require us to have a majority of independent directors although ASX Corporate Governance Principles do recommend a majority of independent directors. Accordingly, because Australian law and generally accepted business practices in Australia regarding director independence differ from independence requirements under Nasdaq rules, we seek to claim this exemption.
We expect to rely on an exemption from the requirement that our independent directors meet regularly in executive sessions under Nasdaq rules. The ASX Listing Rules and the Corporations Act do not require the independent directors of an Australian company to have such executive sessions and, accordingly, we have claimed this exemption.
We expect to rely on an exemption from the quorum requirements applicable to meetings of shareholders under Nasdaq rules. In compliance with Australian law, our Constitution provides that two shareholders present shall constitute a quorum for a general meeting. The Nasdaq rules require that an issuer provide for a quorum as specified in its by-laws for any meeting of the holders of ordinary shares, which quorum may not be less than 33 1/3 of the outstanding shares of an issuer’s voting ordinary shares. Accordingly, because applicable Australian law and rules governing quorums at shareholder meetings differ from Nasdaq’s quorum requirements, we seek to claim this exemption.
We will rely on an exemption from the requirement that we establish compensation and nominating. The ASX Listing Rules and Australian law do not require an Australian company to establish a compensation committee, known in Australia as a remuneration committee, or a nominating committee comprised solely of non-executive directors if the company is not included in the S&P/ASX300 Index at the beginning of its fiscal year. The Company was not included on the S&P/ASX300 Index at the beginning of its last fiscal year and, hence, is not required under ASX Listing Rules to have a remuneration committee or a nominating committee. The ASX Corporate Governance Principles and Recommendations contain a non-binding recommendation that all ASX-listed companies should have a remuneration committee and nominating committee comprised of at least three members, a majority of whom (including the chair) are “independent”. While these recommendations contain guidelines for assessing independence, ASX-listed entities are able to adopt their own definitions of an independent director for this purpose and is different from the definition in Nasdaq rules.
We expect to rely on an exemption from the requirement prescribed by the Nasdaq rules that issuers obtain shareholder approval prior to the issuance of securities in connection with certain acquisitions, private placements of securities, or the establishment or amendment of certain stock option, purchase or other compensation plans. Applicable Australian law and rules differ from Nasdaq rules, with the ASX Listing

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Rules providing generally for prior shareholder approval in numerous circumstances, including (i) issuance of equity securities exceeding 15% (or an additional 10% capacity to issue equity securities for the proceeding 12 month period if shareholder approval by shareholder resolution is sought at the Company’s annual general meeting) of our issued share capital in any 12-month period (but, in determining the available limit, securities issued under an exception to the rule or with shareholder approval are not counted), (ii) issuance of equity securities to related parties (as defined in the ASX Listing Rules) and (iii) directors or their associates acquiring securities under an employee incentive plan. Due to differences between Australian law and rules and the Nasdaq shareholder approval requirements, we seek to claim this exemption.

We will rely on an exemption from the requirement that issuers must in compliance with Nasdaq rules maintain charters for a nomination committee and compensation committee. In addition, we expect to rely on an exemption from the requirement that issuers must maintain a code of conduct in compliance with the Nasdaq rules. Applicable Australian law does not require the Company to maintain any charters for their committees nor does such law require the Company maintain a code of conduct.

As a foreign private issuer, we are permitted to file less information with the SEC than a company that is not a foreign private issuer or that files as a domestic issuer.

As a foreign private issuer, we will be exempt from certain rules under the Exchange Act that impose disclosure requirements as well as procedural requirements for proxy solicitations under Section 14 of the Exchange Act. In addition, our officers, directors and principal shareholders will be exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act. Moreover, we will not be required to file periodic reports and financial statements with the SEC as frequently or as promptly as a company that files as a domestic issuer whose securities are registered under the Exchange Act, nor will we generally required to comply with the SEC’s Regulation FD, which restricts the selective disclosure of material non-public information. Accordingly, there may be less information publicly available concerning us than there is for a company that files as a domestic issuer.

We are an emerging growth company, and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies may make the ADSs less attractive to investors and, as a result, adversely affect the price of the ADSs and result in a less active trading market for the ADSs.

We are an emerging growth company as defined in the JOBS Act, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies. For example, we have elected to rely on an exemption from the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act relating to internal control over financial reporting, and we will not provide such an attestation from our auditors. We have also elected to rely on an exemption that permits an emerging growth company to include only two years of audited financial statements and only two years of related management’s discussion and analysis of financial condition and results of operations disclosure, and we have therefore only included two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations in this annual report on Form 20-F.

We may avail ourselves of these disclosure exemptions until we are no longer an emerging growth company. We cannot predict whether investors will find the ADSs less attractive because of our reliance on some or all of these exemptions. If investors find the ADSs less attractive, it may adversely affect the price of the ADSs and there may be a less active trading market for the ADSs.

We will cease to be an emerging growth company upon the earliest of:

the last day of the fiscal year during which we have total annual gross revenues of US$1,070,000,000 (as such amount is indexed for inflation every five years by the United States Securities and Exchange Commission, or SEC) or more;
the last day of our fiscal year following the fifth anniversary of the completion of our first sale of common equity securities pursuant to an effective registration statement under the Securities Act;
the date on which we have, during the previous three-year period, issued more than US$1,070,000,000 in non-convertible debt; or

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the date on which we are deemed to be a “large accelerated filer”, as defined in Rule 12b-2 of the Exchange Act, which would occur if the market value of our ordinary shares and ADSs that are held by non-affiliates exceeds US$700,000,000 as of the last day of our most recently-completed second fiscal quarter.

In addition, under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards issued subsequent to the enactment of the JOBS Act until such time as those standards apply to private companies. We have irrevocably elected not to avail ourselves of this exemption from new or revised accounting standards and, therefore, will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies. If we are unable to comply timely with these accounting standards, we may be delayed in providing the disclosures required by the Exchange Act.

If we are unable to favorably assess the effectiveness of our internal control over financial reporting, our stock price could be adversely affected.

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, as amended, our management will be required to report on the effectiveness of our internal control over financial reporting in each of our annual reports. Our management will need to provide such a report commencing with our first annual report after we have been required to file an annual report with the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act for the prior fiscal year, which we anticipate will be our annual report for the year ended June 30, 2019. We may not be able to favorably assess the effectiveness of our internal controls over financial reporting as of June 30, 2019 or beyond. If this occurs, investor confidence and our stock price could be adversely affected.

We will incur significant increased costs as a result of operating as a U.S. listed public company, and our management will be required to devote substantial time and expense to various compliance issues.

After we become a U.S. publicly-traded company, and particularly after we cease to be an “emerging growth company” as defined in the JOBS Act, we will incur substantial additional legal, accounting and other expenses as a result of the reporting requirements of the Exchange Act. In addition, the U.S. Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act, along with rules promulgated by the Securities and Exchange Commission, or SEC, and Nasdaq, where the ADSs will trade, have significant requirements on public companies, including many changes involving corporate governance. Management and other company personnel will be required to devote a substantial amount of time to ensuring our compliance with these regulations. Accordingly, our legal, accounting and financial compliance expenses will significantly increase, and certain corporate actions will become more time-consuming and costly. For example, these regulations may make it more difficult to attract and retain qualified members of our Board of Directors and various corporate committees, and obtaining director and officer liability insurance will be more expensive.

ADS holders may be subject to additional risks related to holding ADSs rather than ordinary shares.

ADS holders do not hold ordinary shares directly and, as such, are subject to, among others, the following additional risks:

As an ADS holder, we will not treat you as one of our shareholders and you will not be able to exercise shareholder rights, except through the Depositary as permitted by the deposit agreement.
Distributions on the ordinary shares represented by your ADSs will be paid to the Depositary, and before the Depositary makes a distribution to you on behalf of your ADSs, any withholding taxes that must be paid will be deducted. Additionally, if the exchange rate fluctuates during a time when the Depositary cannot convert the foreign currency, you may lose some or all of the value of the distribution.
We and the Depositary may amend or terminate the deposit agreement without the ADS holders’ consent in a manner that could prejudice ADS holders.

You must act through the Depositary to exercise your voting rights and, as a result, you may be unable to exercise your voting rights on a timely basis.

As a holder of ADSs (and not the ordinary shares underlying your ADSs), we will not treat you as one of our shareholders, and you will not be able to exercise shareholder rights. The Depositary will be the holder of the ordinary shares underlying your ADSs, and ADS holders will be able to exercise voting rights with respect to the ordinary

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shares represented by the ADSs only in accordance with the deposit agreement relating to the ADSs. There are practical limitations on the ability of ADS holders to exercise their voting rights due to the additional procedural steps involved in communicating with these holders. For example, holders of our ordinary shares will receive notice of shareholders’ meetings by mail and will be able to exercise their voting rights by either attending the shareholders meeting in person or voting by proxy. ADS holders, by comparison, will not receive notice directly from us. Instead, in accordance with the deposit agreement, we will provide notice to the Depositary of any such shareholders meeting and details concerning the matters to be voted upon at least 30 days in advance of the meeting date. If we so instruct, the Depositary will mail to holders of ADSs the notice of the meeting and a statement as to the manner in which voting instructions may be given by holders as soon as practicable after receiving notice from us of any such meeting. To exercise their voting rights, ADS holders must then instruct the Depositary as to voting the ordinary shares represented by their ADSs. Due to these procedural steps involving the Depositary, the process for exercising voting rights may take longer for ADS holders than for holders of ordinary shares. The ordinary shares represented by ADSs for which the Depositary fails to receive timely voting instructions will not be voted.

We believe that we were a “passive foreign investment company,” or PFIC, for U.S. federal income tax purposes for the taxable year ended June 30, 2018, and we may be a PFIC in future taxable years, which could have adverse tax consequences for our investors.

The rules governing passive foreign investment companies, or PFICs, can have adverse consequences for U.S. investors for U.S. federal income tax purposes. Under the Internal Revenue Code of 1986, as amended, or the Code, we will be a PFIC for any taxable year in which, after the application of certain “look-through” rules with respect to our subsidiaries, either (i) 75% or more of our gross income consists of “passive income,” or (ii) 50% or more of the average quarterly value of our assets consist of assets that produce, or are held for the production of, “passive income.” Passive income generally includes interest, dividends, rents, certain non-active royalties and capital gains. As discussed in “Taxation-U.S. Federal Income Tax Considerations—Certain Tax Consequences If We Are a Passive Foreign Investment Company,” we believe that we were a PFIC for the taxable year ended June 30, 2018 because we did not have active business income in that taxable year, and we may be a PFIC in future taxable years.

If we are characterized as a PFIC for any taxable year during which a U.S. Holder (as defined in “Taxation—U.S. Federal Income Tax Considerations”) holds ADSs or ordinary shares, we generally would continue to be treated as a PFIC with respect to that U.S. Holder for all succeeding years during which the U.S. Holder holds ADSs or ordinary shares, even if we ceased to meet the threshold requirements for PFIC status. Such a U.S. Holder may suffer adverse tax consequences, including ineligibility for any preferential tax rates on capital gains or on actual or deemed dividends, interest charges on certain taxes treated as deferred and additional reporting requirements under U.S. federal income tax laws and regulations. A U.S. Holder may, in certain circumstances, make a timely qualified electing fund, or QEF, election or a mark to market election to avoid or minimize the adverse tax consequences described above. We do not, however, expect to provide the information regarding our income that would be necessary in order for a U.S. Holder to make a QEF election. Moreover, our non-U.S. subsidiaries may also constitute PFICs, which could result in double taxation of the same income. Potential investors should consult their own tax advisors regarding all aspects of the application of the PFIC rules to our ADSs and ordinary shares.

Currency fluctuations may adversely affect the price of our ordinary shares.

Our ordinary shares are quoted in Australian dollars on the ASX, and the ADSs will be quoted in U.S. dollars on Nasdaq. Movements in the Australian dollar/U.S. dollar exchange rate may adversely affect the U.S. dollar price of the ADSs. In recent years, the Australian dollar has generally depreciated against the U.S. dollar. Any continuation of this trend may positively affect the U.S. dollar price of the ADSs, even if the price of our ordinary shares in Australian dollars increases or remains unchanged. However, this trend may not continue and may be reversed. If the Australian dollar weakens against the U.S. dollar, the U.S. dollar price of the ADSs could decline, even if the price of our ordinary shares in Australian dollars increases or remains unchanged.

We have never declared or paid dividends on our ordinary shares, and we do not anticipate paying dividends in the foreseeable future.

We have never declared or paid cash dividends on our ordinary shares. For the foreseeable future, we currently intend to retain all available funds and any future earnings to support our operations and to finance the growth and development of our business. Any future determination to declare cash dividends will be made at the discretion of our Board of Directors, subject to compliance with applicable laws and covenants under current or future credit

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facilities, which may restrict or limit our ability to pay dividends, and will depend on our financial condition, operating results, capital requirements, general business conditions and other factors that our Board of Directors may deem relevant. We do not anticipate paying any cash dividends on our ordinary shares in the foreseeable future. As a result, a return on your investment will only occur if the price of our ordinary shares and the ADSs appreciate.

You may not receive distributions on our ordinary shares represented by the ADSs or any value for such distribution if it is illegal or impractical to make them available to holders of ADSs.

While we do not anticipate paying any dividends on our ordinary shares in the foreseeable future, if such a dividend is declared, the depositary for the ADSs has agreed to pay to you the cash dividends or other distributions it or the custodian receives on our ordinary shares or other deposited securities after deducting its fees and expenses. You will receive these distributions in proportion to the number of ordinary shares your ADSs represent. However, in accordance with the limitations set forth in the deposit agreement, it may be unlawful or impractical to make a distribution available to holders of ADSs. We have no obligation to take any other action to permit the distribution of the ADSs, ordinary shares, rights or anything else to holders of the ADSs. This means that you may not receive the distributions we make on our ordinary shares or any value from them if it is unlawful or impractical to make them available to you. These restrictions may have a material adverse effect on the value of your ADSs.

Our Constitution and Australian laws and regulations applicable to us may adversely affect our ability to take actions that could be beneficial to our shareholders.

As an Australian company, we are subject to different corporate requirements than a corporation organized under the laws of the United States. Our Constitution, as well as the Corporations Act, set forth various rights and obligations that are unique to us as an Australian company. These requirements may operate differently than those of many U.S. companies. You should carefully review the summary of these matters set forth under the section entitled, “Item 10. Additional Information—Share Capital” as well as our Constitution, which is included as an exhibit to this annual report to Form 20-F prior to investing in the ADS.

You will have limited ability to bring an action against us or against our directors and officers, or to enforce a judgment against us or them, because we are incorporated in Australia and certain of our directors and officers reside outside the United States.

We are incorporated in Australia, certain of our directors and officers reside outside the United States and substantially all of the assets of those persons are located outside the United States. As a result, it may be impracticable or more expensive for you to bring an action against us or against these individuals in Australia in the event that you believe that your rights have been infringed under the applicable securities laws or otherwise.

You may not be able to participate in rights offerings and may experience dilution of your holdings as a result.

We may from time to time distribute rights to our shareholders, including rights to acquire our securities. However, we may not, and under the Deposit Agreement for the ADSs, the depositary will not, offer those rights to ADS holders unless both the rights and the underlying securities to be distributed to ADS holders are registered under the Securities Act or the distribution of them to ADS holders is exempted from registration under the Securities Act with respect to all holders of ADSs. We are under no obligation to file a registration statement with respect to any such rights or underlying securities or to endeavor to cause such a registration statement to be declared effective. In addition, we may not be able to rely on an exemption from registration under the Securities Act to distribute such rights and securities. Accordingly, holders of the ADSs may be unable to participate in our rights offerings and may experience dilution in their holdings as a result.

You may be subject to limitations on transfer of the ADSs.

The ADSs are only transferable on the books of the depositary. However, the depositary may close its transfer books at any time or from time to time when it deems expedient in connection with the performance of its duties. In addition, the depositary may refuse to deliver, transfer or register transfers of ADSs generally when our books or the books of the depositary are closed, or at any time if we or the depositary deem it advisable to do so because of any requirement of law or of any government or governmental body, or under any provision of the Deposit Agreement, or for any other reason.

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Australian companies may not be able to initiate shareholder derivative actions, thereby depriving shareholders of the ability to protect their interests.

Australian companies may not have standing to initiate a shareholder derivative action in a federal court of the United States. The circumstances in which any such action may be brought, and the procedures and defenses that may be available in respect to any such action, may result in the rights of shareholders of an Australian company being more limited than those of shareholders of a company organized in the United States. Accordingly, shareholders may have fewer alternatives available to them if they believe that corporate wrongdoing has occurred. Australian courts are also unlikely to recognize or enforce against us judgments of courts in the United States based on certain liability provisions of U.S. securities law and to impose liabilities against us, in original actions brought in Australia, based on certain liability provisions of U.S. securities laws that are penal in nature. There is no statutory recognition in Australia of judgments obtained in the United States, although the courts of Australia may recognize and enforce the non-penal judgment of a foreign court of competent jurisdiction without retrial on the merits, upon being satisfied about all the relevant circumstances in which that judgment was obtained.

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ITEM 4.INFORMATION ON THE COMPANY
A.History and Development of the Company

Overview

Paringa Resources Limited is a developer of long-life thermal coal mines known as the Buck Creek Complex, consisting of the Poplar Grove and Cypress Mines located in the western Kentucky section of the Illinois Basin. We believe both the Poplar Grove and Cypress Mines possess geological and logistical advantages that will lower the operating costs of our mines and make our coal product attractive to the coal fired power plants located in the Ohio River and southeast U.S. power markets.

We started construction of the Poplar Grove Mine in August 2017, and we expect to complete construction of the mine by the end of the 2018 calendar year. The Poplar Grove Mine is expected to begin coal production by the end of the 2018 calendar year, ramp up production during the 2019 calendar year and reach near full production capacity by the end of the 2020 calendar year.

Based on our current financial position, including the debt financing with Macquarie described in “—Financial Position” below, we expect to have sufficient cash flow to complete the construction of the Poplar Grove Mine and commence commercial coal production. We intend to ship thermal coal predominately by barge from the Company’s barge load-out facility on the Green River, leading to major coal transportation routes along the Ohio and Mississippi rivers.

We have not yet decided on the timing to develop the Cypress Mine, which if undertaken would require additional funds.

Our Properties

In March 2013, we acquired the Buck Creek Complex, which consists of the Poplar Grove Mine and Cypress Mine, from Buck Creek Resources, LLC. The complex is located in western Kentucky, approximately 175 miles southwest of the state capital of Frankfort and approximately 25 miles southwest of the city of Owensboro, Kentucky, within the Western Kentucky Coalfield region of the Illinois Basin. The Poplar Grove Mine lies between the towns of Hanson and Slaughters in the west and Calhoun and Sacramento in the east, within the Counties of McLean and Hopkins in Kentucky. The Cypress Mine is located immediately north of the Poplar Grove Mine.


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Summary Reserve Data

Our coal reserves, as set forth in the BFS, are summarized by project in the table below. See “—B. Business Overview—Key Factors and Assumptions” for additional information about our reserves.

 
Poplar Grove Mine
Cypress Mine
Location
Kentucky
Kentucky
Mining Method
Underground, room-and-pillar
Underground, room-and-pillar
Reserves ROM Recoverable Tons (in millions)
 
 
Proven
21.0
22.5
Probable
28.4
63.8
Total(1)
49.4
86.3
Estimated Full Production 2024 (million tons per year)
2.8
3.8
Anticipated Production Start Date
2018
2021
Projected Mine Life (years)
25
18
Average Annual Operating Costs (FOB Barge) ($/ton(2))
$28.28
$27.37
Heating Content (Btu/lb(3))
11,200
11,200
Planned Transportation
Barge/Truck
Barge
Sulfur % (product blend)
3.0%
3.0%
Coal prices used to estimate reserves(4)
$40.50 to $53.20 per ton
$40.50 to $53.20 per ton
(1)We estimate that dilution materials and allowances for losses will be approximately 24% of our recoverable reserves.
(2)Represents average operating costs free-on-board, or FOB Barge, at the Green River Barge Load-out Facility during steady state production.
(3)Btu/lb means the British thermal unit (Btu or BTU), which is a traditional unit of heat; it is defined as the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
(4)Based on our sales contract with LG&E and KU for 2018 through 2022 and then escalated (real) pricing (based on the 2022 pricing in the sales contract).

Financial Position

At June 30, 2018 and 2017, the Company had cash and cash equivalents of $22.6 million and $34.8 million, respectively. During fiscal 2018 we raised approximately $22.7 million in an equity offering in Australia (before associated costs).

In addition, we have entered into a debt financing facility with Macquarie Bank Limited (“Macquarie”) to provide a two-tranche $21.7 million Project Loan Facility to develop the Poplar Grove Mine. Subsequent to the end of the fiscal 2018 year, we satisfied all drawdown conditions precedent under the Project Loan Facility Agreement, and in September 2018, we made an initial drawdown of the first $15.0 million tranche. We expect to drawdown the second and final tranche of the Project Loan Facility (being $6.7 million) during the 2019 calendar year.

The terms of the Project Loan Facility include a floating interest rate comprising the 3-month LIBOR plus a margin of 10.5% per annum during the construction phase, falling to a 9.5% margin for the remainder of the loan, as well as customary guarantees and security agreements. The financial covenants under the Project Loan Facility comprise the following (each of which gets tested on a quarterly basis during the term of the loan unless specified otherwise): (1) on or after September 30, 2019, the debt service cover ratio is greater than 1.10:1, (2) the loan life cover ratio that is greater than 1.15:1, (3) the project life cover ratio is greater than 1.50, (4) on or after September 30, 2019, the gross debt to EBITDA ratio is less than 2.50:1, and (5) the reserve tail ratio is greater than 30%. The terms allow the Project Loan Facility to be repaid at the end of any quarterly interest period, throughout the term of the loan, without penalty. Macquarie will be given a first priority security interest in all assets of the Company.

Based on our current financial position, and assuming drawdown of the second and final tranche of the Project Loan Facility, we expect to have sufficient cash flow to complete the construction of the Poplar Grove Mine and commence commercial coal production.

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Our Strengths

We believe that we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

Illinois Basin coal producer with permitted, high quality, long-lived reserves. Upon commencing production at Poplar Grove, which is expected by the end of the 2018 calendar year, we believe we will be one of the few pure-play Illinois Basin thermal coal producers in the United States. As of June 2018, we control a reserve base of approximately 135.7 million ROM tons of high-quality Illinois Basin coal, with an expected mine life of 25 years for the Poplar Grove Mine and 18 years for the Cypress Mine. Both the Poplar Grove and Cypress Mines are fully permitted to begin construction, and our studies indicate that the coal at both mines have attractive properties compared to the coal at other existing mines in the Illinois Basin. Specifically, the coal from the WK No. 11 and WK No. 9 seams are expected to have a high heat content of 12,168 Btu/lb and 12,026 Btu/lb, respectively, at the Poplar Grove Mine, and 11,819 Btu/lb from the WK No. 9 seam at the Cypress Mine, after processing, which compares favorably with the larger producing mines in the Illinois Basin.

Fixed Price Sales Contract. We have entered into two long-term, fixed-price coal supply agreements with major regulated utilities having coal fired power plants on the Ohio River Market. We expect that sales under the agreements will represent approximately 51% of the first five years of production. We believe the “fixed price, fix tons” nature of these agreements will reduce the volatility of our future revenues. See “B. Business Overview—Marketing, Sales and Contracts.”

Low Operating Costs. We project low operating costs for both our mines relative to other U.S. coal producers, resulting from (1) the high in-seam yield of the Poplar Grove Mine’s WK No. 9 and WK No. 11’s coal seams, (2) both mine plans being relatively flat and laterally continuous, (3) favorable mining conditions from a competent mine roof and floor structure, (4) close proximity to the Green River Barge Load-out Facility providing low transportation cost access to coal fired power plants located on the Ohio River. In addition, due to the high heating content (i.e. 11,819 to 12,168 btu/lb) and low moisture content, we have developed a preparation plant flow sheet for our mines that we expect will allow for a portion of the run-of-mine (“ROM”) coal (approximately 20% to 30% of ROM) to bypass the preparation process and be blended back in with the processed coal, which would produce a higher yield, lower operating cost and lower heating content product that still meets customer specifications. In addition, both mines are located in an established coal mining district, which should allow us to access highly skilled, union-free labor and local mining services and equipment providers.

Low Capital Cost Development. We believe that our mines are located in an area that has significant operational and logistical advantages. Construction services, construction personnel, contractors and parts can be supplied by firms who are already operating in the region. The total initial capital expenditures for the Poplar Grove Mine is estimated to be $56.8 million, and includes all major capital items including site development, electrical substation and infrastructure, mine development to access the coal seam, surface facilities, coal preparation plant, materials handling and the Green River barge load-out facility (excluding any contingencies, working capital and financing costs). In addition, we have entered into fixed price construction contracts that account for the majority of our initial construction capital expenditures at Poplar Grove.

Established financing plan. We had approximately $22.6 million of cash and short-term investments at June 30, 2018 and have a $21.7 million Project Loan Facility from Macquarie. In September 2018, we made an initial drawdown of the first $15.0 million tranche of the Project Loan Facility and expect to drawdown the second and final tranche of the Project Loan Facility (being $6.7 million) during the 2019 calendar year. Based on our current financial position, and assuming drawdown the second and final tranche of the Project Loan Facility (being $6.7 million), we expect to have sufficient cash flow to complete the construction of the Poplar Grove Mine and commence commercial coal production.

Highly experienced management team with a long history of acquiring, developing, building and operating coal reserve properties. Our senior management team has significant experience in acquiring, developing, financing and operating coal mines in the United States under various market conditions. They have previously held senior business development, financial, operations, and coal sales positions at both large, publicly traded coal companies as well as successful private coal operations.

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Our Strategies

The key elements of our strategy to grow our business include:

Complete the development of the Poplar Grove Mine and reach full production of 2.8 Mtpa. We started construction of the Poplar Grove Mine in August 2017, and we expect to complete the construction of the mine by the end of the 2018 calendar year. The Poplar Grove Mine is expected to begin coal production by the end of the 2018 calendar year, ramp up production during the 2019 calendar year and reach near full production capacity, estimated as 2.8 Mtpa, by the end of the 2020 calendar year.

Assess development plans for the Cypress Mine. The Cypress Mine is fully permitted for construction with all technical studies completed for its development, including a bankable feasibility study. We may begin construction of the Cypress Mine as early as 2019, in which case we would anticipate completing development in 2020 and, subject to obtaining all permits required for operation of the mine, commencing coal production in 2021. Our decision to construct the Cypress Mine will depend on us securing required debt or equity financing to pay for development and construction costs, our ability to identify and contract with customers who are willing to acquire a significant portion of production at the Cypress Mine and coal prices remaining at profitable levels.

Continue to grow through a highly disciplined and selective acquisition strategy. Our senior management team has a demonstrated track record of identifying and securing geologically and logistically advantaged thermal coal projects. They also have shown success in the exploration and permitting of new mines and the building of long-lived resources through complementary acquisitions.

Pursue our financial strategy. We intend to fund development at the Poplar Grove Mine primarily from our current financial position, the Macquarie Project Loan Facility and projected cash flow from operations. We have projected cash flow from operations based on our fixed price sales contracts, as well as third-party forecasts of coal prices, discounted for expected transportation costs, ash content and the effects of having a blended coal product. We intend to utilize revolving credit arrangements for working capital management, in either the private or public markets, to the extent it is available. We expect to fund the development of the Cypress Mine, if undertaken, and any acquisition activities from operating cash flows and additional future issuances of debt or equity securities.

U.S. Regulations

We are an “emerging growth company” under the U.S. Jumpstart Our Business Startups Act of 2012, or the JOBS Act, and will continue to qualify as an “emerging growth company” until the earliest to occur of:

the last day of the fiscal year during which we have total annual gross revenues of US$1,070,000,000 (as such amount is indexed for inflation every five years by the SEC) or more;
the last day of our fiscal year following the fifth anniversary of the completion of our first sale of common equity securities pursuant to an effective registration statement under the Securities Act;
the date on which we have, during the previous three-year period, issued more than US$1,070,000,000 in non-convertible debt; or
the date on which we are deemed to be a “large accelerated filer”, as defined in Rule 12b-2 of the U.S. Securities Exchange Act of 1934, as amended, or the Exchange Act, which would occur if the market value of our ordinary shares and ADSs that are held by non-affiliates exceeds US$700,000,000 as of the last day of our most recently-completed second fiscal quarter.

An emerging growth company may take advantage of specified exemptions from various requirements that are otherwise applicable to public companies in the United States. Generally, a company that registers any class of its securities under Section 12 of the Exchange Act is required to include in the second and all subsequent annual reports filed by it under the Exchange Act, a management report on internal control over financial reporting and, subject to an exemption available to companies that meet the definition of a “smaller reporting company” in Rule 12b-2 under the Exchange Act, an auditor attestation report on management’s assessment of the company’s internal control over financial reporting. However, for so long as we continue to qualify as an emerging growth company, we will be exempt from the requirement to include an auditor attestation report in our annual reports filed under the Exchange Act, even if we do not qualify as a “smaller reporting company.” In addition, Section 103(a)(3) of the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act, has been amended by the JOBS Act, to provide that, among

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other things, auditors of an emerging growth company are exempt from any rules of the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the company.

Pursuant to Section 107(b) of the JOBS Act, an emerging growth company may elect to utilize an extended transition period for complying with new or revised accounting standards for public companies until such standards apply to private companies. We have elected not to utilize this extended transition period. This election is irrevocable.

We are also considered a “foreign private issuer” pursuant to Rule 405 under the Securities Act. As a foreign private issuer, we are exempt from certain rules under the Exchange Act that impose certain disclosure obligations and procedural requirements for proxy solicitations under Section 14 of the Exchange Act. In addition, our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and the rules under the Exchange Act with respect to their purchases and sales of our ordinary shares or ADSs. Moreover, we are not required to file periodic reports and financial statements with the SEC as frequently or as promptly as United States companies whose securities are registered under the Exchange Act. In addition, we are not required to comply with Regulation FD (Fair Disclosure), which restricts the selective disclosure of material information.

Under Australian law, we prepare financial statements on an annual and semi-annual basis, and we are not required to prepare or file quarterly financial information other than quarterly updates. Our quarterly updates consist of a brief review of operations for the quarter together with a statement of cash expenditure during the quarter, the cash and cash equivalents balance as at the end of the quarter and estimated cash outflows for the following quarter.

For as long as we are a “foreign private issuer” we intend to file our annual financial statements on Form 20-F and furnish our semi-annual financial statements and quarterly updates on Form 6-K to the SEC for so long as we are subject to the reporting requirements of Section 13(g) or 15(d) of the Exchange Act. However, the information we file or furnish is not the same as the information that is required in annual and quarterly reports on Form 10-K or Form 10-Q for U.S. domestic issuers. Accordingly, there may be less information publicly available concerning us than there is for a company that files as a domestic issuer.

We may take advantage of these exemptions until such time as we are no longer a foreign private issuer. We are required to determine our status as a foreign private issuer on an annual basis at the end of our second fiscal quarter. We would cease to be a foreign private issuer at such time as more than 50% of our outstanding voting securities are held by U.S. residents and any of the following three circumstances applies: (1) the majority of our executive officers or directors are U.S. citizens or residents; (2) more than 50% of our assets are located in the United States; or (3) our business is administered principally in the United States. Since more than 50% of our assets are located in the United States, we will lose our status as a foreign private issuer if more than 50% of our outstanding voting securities are held by U.S. residents as of the last day of our second fiscal quarter in any year. See “Risk Factors— We may lose our foreign private issuer status, which would then require us to comply with the Exchange Act’s domestic reporting regime and cause us to incur additional legal, accounting and other expenses.”

Capital Expenditures

Our capital expenditures for fiscal 2016, 2017 and 2018 amounted to $876,000, $8,575,000, and $27,134,000, respectively.

Our capital expenditures have historically consisted principally of payments for property, plant and equipment in relation to the Buck Creek Mining Complex. Previously, our capital expenditures have also included payments for exploration assets (prior to making a decision to proceed with development of the Poplar Grove Mine) and payments for deferred purchase consideration in relation to the original purchase of the Buck Creek Mining Complex in 2012.

B.Business Overview

BUSINESS

Overview

We are a developer of long-life thermal coal mines known as the Buck Creek Complex, consisting of the Poplar Grove and Cypress Mines located in the western Kentucky section of the Illinois Basin, approximately 175 miles southwest of the state capital of Frankfort and approximately 25 miles southwest of the city of Owensboro, Kentucky.

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We believe both the Poplar Grove and Cypress Mines possess geological and logistical advantages that will lower the operating costs of our mines and make our coal product attractive to the coal fired power plants to located in the Ohio River and southeast U.S. power markets.

We started construction of the Poplar Grove Mine in August 2017, and we expect to complete the construction of the mine by the end of the 2018 calendar year. The Poplar Grove Mine is expected to ramp up production in the 2018 and 2019 calendar years. Based on our current financial position, and assuming drawdown of the second and final tranche of the Project Loan Facility, we expect to have sufficient cash flow to complete the construction of the Poplar Grove Mine and commence commercial coal production. We intend to ship thermal coal predominately by barge from the Company’s barge load-out facility on the Green River, leading to major coal transportation routes along the Ohio and Mississippi rivers.

We have not yet decided on the timing to develop the Cypress Mine, which if undertaken would require additional funds.

We are required by ASX Listing Rules to report ore reserves and mineral resources in Australia in compliance with the JORC Code. Under the SEC’s Industry Guide 7, classifications other than proven and probable reserves are not recognized and, as a result, the SEC generally does not permit mining companies like us to disclose measures of mineral resources, such as measured, indicated or inferred resources, in SEC filings.

We have commissioned MM&A to conduct a review of our BFS. MM&A have provided reserve coal tonnage estimates that are compliant with the SEC’s Industry Guide 7 and accordingly, the reserves disclosed in this annual report on Form 20-F are compliant with the JORC Code and Industry Guide 7. However, we note for you that we have made assumptions about the likely existence of mineralized material when designing our mine plan.

The following map shows Buck Creek Complex and surrounding operations in Western Kentucky:


Development and Production Plans

Our plan is to develop low capital and operating cost mines located near low cost river transportation in the Illinois Basin. Both mines are fully permitted to begin construction. Once the Poplar Grove Mine is constructed, we currently plan to make low-cost mine developments to grow our coal production. We intend to support additional production growth with long-term sales contracts to ensure that additional capacity investments generate high levels of free cash flow.

Our development plan can be summarized as follows:

Complete Construction at Poplar Grove Mine. We commenced construction of the Poplar Grove Mine in August 2017, and we expect to complete the construction of the mine by the end of the 2018 calendar year.
First coal production by the end of 2018. We aim to deliver first coal production by the end of the 2018 calendar year. Our plans call for the WK No. 9 seam to be mined throughout the entirety of the project’s

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25 year mine life and the WK No. 11 to be accessed and mined during two periods. We project that the Poplar Grove Mine will process approximately 3.6 million tons of ROM coal annually including the raw coal bypass, which equates to approximately 2.8 Mtpa of saleable coal over a 25 year mine life. The Poplar Grove Mine plan includes a total production of 89.0 million ROM tons, or 67.7 million saleable tons.

Assess development plans for the Cypress Mine. The Cypress Mine is fully permitted for construction with all technical studies completed for its development, including a bankable feasibility study. We may begin construction of the Cypress Mine as early as 2019, in which case we would anticipate completing development in 2020 and, subject to obtaining all permits required for operation of the mine, commencing coal production in 2021. Our decision to construct the Cypress Mine will depend on us securing required debt or equity financing to pay for development and construction costs, our ability to identify and contract with customers who are willing to acquire a significant portion of production at the Cypress Mine and coal prices remaining at profitable levels.

Estimates to develop the Poplar Grove and Cypress Mines have been based in part on the BFS conducted by MM&A. We have estimated that total capital expenditures to develop the Poplar Grove Mine and Cypress Mine will be approximately $56.8 million and $101.2 million, respectively.

Our Competitive Strengths

We believe that we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

Illinois Basin coal producer with permitted, high quality, long-lived reserves. Upon commencing production at Poplar Grove, which is expected by the end of the 2018 calendar year, we believe we will be one of the few pure-play Illinois Basin thermal coal producers in the United States. As of March 2017, we control a reserve base of approximately 135.7 million ROM tons of marketable, high-quality Illinois Basin coal, with an expected mine life of 25 years for the Poplar Grove Mine and 18 years for the Cypress Mine. Both the Poplar Grove and Cypress Mines are fully permitted to begin construction, and our studies indicate that the coal at both mines have attractive properties compared to the coal at other existing mines in the Illinois Basin. Specifically, the coal from the WK No. 11 and WK No. 9 seams are expected to have a high heat content of 12,168 Btu/lb and 12,026 Btu/lb, respectively, at the Poplar Grove Mine, and 11,819 Btu/lb from the WK No. 9 seam at the Cypress Mine, after processing, which compares favorably with the larger producing mines in the Illinois Basin.
Fixed Price Sales Contracts. We have entered into two long-term, fixed-price coal supply agreements with major regulated utilities having coal fired power plants on the Ohio River Market. We expect that sales under the agreements will represent approximately 51% of the first five years of production. We believe the “fixed price, fix tons” nature of this agreement will reduce the volatility of our future revenues. See “—Marketing, Sales and Contracts.”
Low Operating Costs. We project low operating costs for both our mines relative to other U.S. coal producers, resulting from (1) the high in-seam yield of the Poplar Grove Mine’s WK No. 9 and WK No. 11’s coal seams, (2) both mine plans being relatively flat and laterally continuous, (3) favorable mining conditions from a competent mine roof and floor structure, (4) close proximity to the Green River Barge Load-out Facility providing low transportation cost access to coal fired power plants located on the Ohio River. In addition, due to the high heating content (i.e. 11,819 to 12,168 btu/lb) and low moisture content, we have developed a preparation plant flow sheet for our mines that we expect will allow for a portion of the ROM coal (approximately 20% to 30% of ROM) to bypass the preparation process and be blended back in with the processed coal, which would produce a higher yield, lower operating cost and lower heating content product that still meets customer specifications. In addition, both mines are located in an established coal mining district, which should allow us to access highly skilled, union-free labor and local mining services and equipment providers.
Low Capital Cost Development. We believe that our mines are located in an area that has significant operational and logistical advantages. Construction services, construction personnel, contractors and parts can be supplied by firms who are already operating in the region. The total initial capital expenditures for the Poplar Grove Mine is estimated to be $56.8 million, and includes all major capital items including site development, electrical substation and infrastructure, mine development to access the coal seam, surface

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facilities, coal preparation plant, materials handling and the Green River barge load-out facility (excluding any contingencies, working capital and financing costs). In addition, we have entered into fixed price construction contracts that account for nearly 90% of our initial construction capital expenditures at Poplar Grove.

Established financing plan. We had approximately $22.6 million of cash and short-term investments at June 30, 2018 and have a $21.7 million Project Loan Facility from Macquarie. In September 2018, we made an initial drawdown of the first $15.0 million tranche of the Project Loan Facility and expect to drawdown the second and final tranche of the Project Loan Facility (being $6.7 million) during the 2019 calendar year. Based on our current financial position, and assuming drawdown of the second and final tranche of the Project Loan Facility, we expect to have sufficient cash flow to complete the construction of the Poplar Grove Mine and commence commercial coal production.
Highly experienced management team with a long history of acquiring, developing, building and operating coal reserve properties. Our senior management team has significant experience in acquiring, developing, financing and operating coal mines in the United States under various market conditions. They have previously held senior business development, financial, operations, and coal sales positions at both large, publicly traded coal companies as well as successful private coal operations.

Our Strategies

The key elements of our strategy to grow our business include:

Complete the development of the Poplar Grove Mine and reach full production of 2.8 Mtpa. We commenced construction of the Poplar Grove Mine in August 2017. The Company aims to deliver first coal production by the end of the 2018 calendar year and reach steady state production, estimated as 2.8 Mtpa, by the end of the 2020 calendar year.
Assess development plans for the Cypress Mine. The Cypress Mine is fully permitted for construction with all technical studies completed for its development, including a bankable feasibility study. We may begin construction of the Cypress Mine as early as 2019, in which case we would anticipate completing development in 2020 and, subject to obtaining all permits required for operation of the mine, commencing coal production in 2021. Our decision to construct the Cypress Mine will depend on us securing required debt or equity financing to pay for development and construction costs, our ability to identify and contract with customers who are willing to acquire a significant portion of production at the Cypress Mine and coal prices remaining at profitable levels.
Continue to grow through a highly disciplined and selective acquisition strategy. Our senior management team has a demonstrated track record of identifying and securing geologically and logistically advantaged thermal coal projects. They also have shown success in the exploration and permitting of new mines and the building of long-lived resources through complementary acquisitions.
Pursue our financial strategy. We intend to fund development at the Poplar Grove Mine primarily from our current financial position, the Macquarie Project Loan Facility and projected cash flow from operations. We have projected cash flow from operations based on our fixed price sales contracts, as well as third-party forecasts of coal prices, discounted for expected transportation costs, ash content and the effects of having a blended coal product. We intend to utilize revolving credit arrangements for working capital management, in either the private or public markets, to the extent it is available. We expect to fund the development of the Cypress Mine, if undertaken, and any acquisition activities from operating cash flows and additional future issuances of debt or equity securities.

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Summary Reserve Data

Our reserves by mine are summarized below:

 
Poplar Grove Mine
Cypress Mine
Location
Kentucky
Kentucky
Mining Method
Underground, room-and-pillar
Underground, room-and-pillar
Reserves ROM Recoverable Tons (in millions)
 
 
Proven
21.0
22.5
Probable
28.40
63.8
Total(1)
49.40
86.3
Estimated Full Production 2024 (million tons per year)
2.8
3.8
Anticipated Production Start Date
2018
2021
Projected Mine Life (years)
25
18
Estimated cost of Production ($/ton(2))
$28.28
$27.37
Heating Content (Btu/lb(3))
11,200
11,200
Planned Transportation
Barge/Truck
Barge
Sulfur % (product blend)
3.0%
3.0%
Coal price used to estimate reserves(4)
$40.50 to $53.20 per ton
$40.50 to $53.20 per ton
(1)We estimate that dilution materials and allowances for losses will be approximately 24% of our recoverable reserves.
(2)Represents average operating costs free-on-board, or FOB Barge, at the Green River Barge Load-out Facility during steady state production.
(3)Btu/lb means the British thermal unit (Btu or BTU) is a traditional unit of heat; it is defined as the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
(4)Based on our sales contract with LG&E and KU for 2018 through 2022 and then escalated (real) pricing (based on the 2022 pricing in the sales contract).

Please see “—Key Factors and Assumptions” for important information about the methodology applicable to our mine plan and reserve estimates, including key factors and assumptions that could cause actual results to differ materially from our expectations.

Overview of Poplar Grove Mine and Cypress Mine

Property Rights

In March 2013, we acquired the Buck Creek Complex from Buck Creek Resources, LLC. Buck Creek Resources, LLC assembled the original Buck Creek property consisting of a series of coal leases totalling 25,000 acres within 327 property tracts, all of which were acquired by us. We have subsequently leased approximately 15,750 acres of additional mineral property adjacent to existing leases. As of June 30, 2018, we controlled approximately 41,000 acres of mineral property pursuant to over 300 individual leases with local landowners. Of the total marketable production profile of 133.9 million tons at the Poplar Grove Mine and Cypress mine, approximately 103.8 million tons of the mine plan can be mined on mineral property currently controlled by us. Additional mineral leases must be acquired in order to execute the life of mine plan to achieve the projected financial performance of the Poplar Grove Mine.

There are 318 acres on three tracts of surface property controlled at Poplar Grove Mine that are necessary for surface facilities, and 500 acres on five tracts of options to acquire surface property controlled at the Cypress Mine that are necessary for surface facilities. If and when the mines are developed, these sites are expected to house the preparation plant, refuse area and associated support facilities.

Royalties

Kentucky state law allows the owner or controller of a partial interest tract to develop the tract in a manner consistent with full control of the property. Therefore, we expect that any partial interest tracts that are less than 100% leased can be developed. Any royalties due to the owners of the uncontrolled portion of the tract are escrowed and administered by a local court. The partial interest tracts are included within our 41,000 controlled acres. In addition to annual minimum royalties, a production royalty equalling the greater of $1.25 per ton or four percent of the average gross sales price Free on Board, or F.O.B., mine is applicable.

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Coal Seam Access

We expect that access to the underground coal seam at both mines will be provided by a decline entryway from the surface for transport of personnel, materials and ROM coal. The mine slopes will accommodate a conveyor belt to transport ROM coal to the mine site area and a travelway for the transportation of personnel, supplies, and equipment. Two vertical airshafts will be constructed at each mine to ventilate the slope and mine.

Surface Access

The mine portal, coal preparation plant and refuse disposal facility will be located in McLean County in the eastern portion of the property along Kentucky Route 2385. Trucks will transport product to a river load-out on the Green River, approximately seven miles to the northeast along Kentucky Routes 81 and 138. Routes 2385, 81 and 138 are all paved roads maintained by Kentucky’s state government, and they currently handle industrial truck traffic mostly related to the large-scale agricultural operations in the area. The local infrastructure is classified as very good to excellent in terms of supporting a sizable mining operation.

Poplar Grove Mine

Location

Contained within McLean and Hopkins Counties, Kentucky, the Poplar Grove Mine lies between the towns of Hanson and Slaughters in the west and Calhoun and Sacramento in the east. The navigable Green River flows through the north-eastern corner of the property and the Pond River flows north through the center of the Poplar Grove Mine to its confluence with the Green River near the northern property boundary. The Pond River also forms the common border between McLean and Hopkins Counties. A CSX Corporation rail line that parallels the Pennyrile Parkway, recently upgraded and renamed Interstate 69, is adjacent to the western end of the project area.

Geological Setting

The coal deposits in the Western Kentucky Coal Field are among the earliest exploited and most extensively-developed coal deposits in the United States. The coal-bearing formations on the property belong to the Middle Pennsylvanian system (including the Carbondale Formation). These coal-bearing formations extend over 400 miles from northern Illinois to western Kentucky and are part of what is identified as the Illinois Basin. The Illinois Basin is more than 200 miles wide and, in some portions, it contains over 30 named coal seams. The mineable coal horizons in the Carbondale Formation range from one foot to over six feet in thickness. Structurally, the coal horizons are typically characterized as gently-dipping, but may steepen along the margins of the basin.

Sediment of the Carbondale Formation includes conglomerate, sandstone, siltstone, shale, limestone and coal that were deposited primarily in coastal-deltaic settings. The coal rank is generally high volatile bituminous C. Higher-rank coals are sometimes located along major structural fault systems. The Poplar Grove Mine will extract coal from both the WK No.9 and WK No.11 coal seams, and the Cypress Mine will be mining the WK No.9 seam only.

Exploration

The reserve estimation for WK No. 9 entailed a total of 193 drill holes, including 143 core holes, 25 rotary holes and 25 gas wells. The reserve estimation for WK No. 11 entailed a total of 191 drill holes, including 115 core holes, 52 rotary holes and 24 gas wells. In total, there are over 1,200 coal seam intercepts at the Poplar Grove and Cypress Mines, providing a significant level of information and understanding of the WK No.9 and WK No.11 coal seams.

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Coal Quality

Coal seam quality data, available from exploration drill holes, has been utilized to determine the Poplar Grove Mine resource coal quality. Results are typical of the coal quality generally found in the west Kentucky portion of the Illinois Basin. A summary of the WK No. 9 and WK No. 11 drill hole quality data for the Poplar Grove Mine is set forth below.

 
Raw Proximate Analysis
(As Received)
Average Washed Core Product Qualities
(Float 1.60 SG with Moisture = Equilibrium Moisture +4%)
 
EQ
Moisture
Ash
Volatile
Matter
Fixed
Carbon
Chlorine
HGI
Calorific
Value
(Btu/lb)
Ash
Sulfur
Yield (@
1.60 Float)
WK No. 11
 
4.9
%
 
15.7
%
 
38.6
%
 
40.1
%
 
0.12
%
 
58
 
 
12,168
 
 
8.4
%
 
3.4
%
 
84.2
%
WK No. 9
 
5.6
%
 
11.6
%
 
38.3
%
 
43.8
%
 
0.12
%
 
60
 
 
12,026
 
 
9.0
%
 
2.8
%
 
93.6
%

Mining Conditions

The rock strata above the WK No. 9 seam generally consists of Turner Mine Shale, which is a thin, black shale, on top of which there is Canton Shale and Vermillionville Sandstone. Immediately below the WK No. 9 seam is claystone followed by shale and sandy shale. Coal seam thickness of the WK No.11 seam averages 4.2 feet with clean coal quality characteristics similar to the Poplar Grove Mine’s WK No.9 seam. Mining conditions for the WK No.11 coal seam appear to be excellent with the immediate roof consisting of a thin black shale horizon overlain by limestone. The roof conditions in the WK No. 11 seam are expected to result in lower operating cost compared to the WK No. 9 because the density of roof support materials is less. Both the WK No. 9 and No. 11 seams are relatively flat with a dip towards the northwest.

Like almost all coal seams in the United States, the seams studied at Buck Creek Complex liberate methane gas. Based on historical mining in the area and desorption testing conducted for the project, we believe the amount of gas encountered during mining should not require degasification drilling nor is it expected to it adversely affect productivity.

Mines in the WK No. 9 and No. 11 seams are generally dry, and drilling at the project indicates that the potential for water in the mine is low. Our mining plan, however, dictates that the underground mines will construct sumps and provide infrastructure necessary to pump water during mining. Our estimates of capital and operating cash costs for the Poplar Grove and Cypress Mines include costs for doing so.

Coal Mining Activities

We recently completed the foundations at the Poplar Grove Mine and began erecting structural steel for the coal handling and preparation plant, or CHPP, with initial production planned by the end of the 2018 calendar year. Production from the proposed Poplar Grove Mine will come exclusively from continuous miner units using room-and-pillar methods.

Underground mining operations at the Poplar Grove Mine will consist of three “super section units”, or Units, with each operating two continuous miners to undertake initial driving of mains and coal mining of panels. Each Unit is equipped with two continuous miners and two roof-bolting machines for enhanced productivity. In addition, each Unit will be equipped with a minimum of four battery haulers which transport mined coal to a belt feeder/breaker, which provides surge capacity to reduce haulage dump times. The Units utilize scoops for clean-up of spillage, and supply cars for distribution of supplies and materials, rockdusting and other utility purposes.

Intake air will be directed through central entries and used to provide fresh air for the continuous miners. After ventilating the working faces, the return air will be routed through the exterior entries to exit the mine at the return portal or air shaft.

At steady state production, the continuous miner advance rate projected for each Unit is a nominal 560 feet per unit-shift, comparable to the performance of other producers in the Illinois Basin. At full capacity, each Unit is expected to produce, on average, approximately 900,000 tons of saleable coal per year.

Coal Processing

ROM production from the Poplar Grove Mine will require processing in order to meet market specifications. We and our contractors and vendors have developed a preparation plant flow sheet that allows for a portion of ROM coal to

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bypass the preparation process and be blended back in with the processed coal, which would produce a higher yield, lower operating cost and lower heating content product that still meets customer specifications. The amount of bypassed coal can be varied to produce a range of product qualities.

The coal product from Poplar Grove Mine will be a blend of processed and bypassed coal to meet a target specification of 11,200 to 11,300 Btu/lb. This target coal quality is expected to result in an overall yield of approximately 76.1%. Following the processing and blend of both the WK No. 9 and WK No. 11 coal seams, the Poplar Grove washed qualities are expected to be as follows:

 
Ash (%)
Sulfur (%)
Moisture (%)
Product Blend
 
11.8
%
 
3.02
%
 
10.6
%

Shown below is a summary of the Poplar Grove Preparation Plant design:

Scheduled (Raw tons per Year)
 
3,900,000
 
Planned Annual Processing Days
 
350
 
Scheduled Operating Hours per Day
 
24
 
Utilization
 
90
%
Design Capacity (Raw tons per hour)
 
400
 
Required Capacity (Raw tons per hour @ average 25% plant bypass)
 
361
 

Out-of-seam dilution will be removed from the product by coal processing. Precise monitoring and control of the specific gravity of separation during operation of the coal preparation plant is intended to provide a consistent and predictable product in conformity with specifications of our coal supply agreements.

The coal preparation plant design throughput capacity will be a nominal 400 tons per hour. Following the initial ramp-up period, the mine is expected to produce an estimated average of 3.6 million ROM tons per year. At full production, the plant is expected to be scheduled for operation with 250 to 350 processing days planned each year, which will vary depending on ROM production and percent direct ship.

The design capacity allows for adjustment to operating and maintenance schedules to efficiently meet annual processing requirements.

Initial Capital Costs

The total initial capital expenditure estimate of $56.8 million for construction of the 2.8 Mtpa Poplar Grove Mine includes all major capital items including site development, electrical substation and infrastructure, coal access mine development, surface facilities, equipment leasing, coal preparation plant, materials handling and the Green River barge load-out facility.

We believe the Poplar Grove Mine is located in one of the best-serviced and infrastructure advantaged coal regions in the United States. We expect that construction services, construction personnel, contractors and parts will be supplied by firms who are already operating in the region. The cost of sustaining capital expenditures for the Poplar Grove Mine, mine site infrastructure, CHPP, cost of the incline to the WK No. 11 seam and additional air shafts has been estimated at $1.99 per ton. Our estimates of capital costs for the Poplar Grove and Cypress Mines are based in part on the capital costs of similar mines in the region operating in similar conditions, utilizing identical mining or processing techniques and equipment.

Operating Costs

The average (steady state) annual operating cost for the Poplar Grove Mine free-on-board barge, is estimated to be approximately $28.28 per saleable ton. Operating costs are projected for each year of the mine plan, considering projected annual ROM tonnage, clean tonnage and feet of advance. Operating cost projections are based on current pricing provided by reputable vendors and contractors and our estimates of staffing, wage and salary levels, employee benefits, operating and maintenance and supply costs per ton produced (for the mine) or processed (for the plant and dock). Other costs include outside services, sales and administrative costs, royalties, black lung federal excise tax, OSM reclamation fees and property tax and insurance.

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Refuse Disposal

In the plant, fine refuse will be separated from process water using plate and frame presses, a technology utilized in the Illinois Basin by other operating companies. Once separated, the dewatered fine refuse will be combined with coarse refuse and will exit the plant on a refuse collecting conveyor belt. The combined refuse will be placed in permitted refuse-disposal facilities; the location of the refuse disposal area will be immediately adjacent to the CHPP. Process water, once separated from the fine refuse will be recycled and reused in the CHPP. We expect the Poplar Grove Mine to generate approximately 21.2 million tons of refuse, or approximately 16.9 million cubic yards, over the life of the mine. The designed refuse storage area at the Poplar Grove Mine has a capacity of 26.7 million cubic yards.

Electricity and Water

The Poplar Grove Mine development plan calls for the construction of approximately 4.3 miles of high-voltage transmission line from the existing Kenergy 69 kV line to serve the mine and plant. In addition, a main surface substation to supply the mine, plant, and surface facilities, along with internal distribution lines, will be needed.

The Poplar Grove Mine development plan calls for fresh water for the mine and plant to be pumped from groundwater wells to a freshwater supply pond adjacent to the surface facilities. In addition to the water needed to run the mine and plant on a daily basis, fresh water will also be stored in a tank for firefighting. Potable water for the bath house and offices will come from a public water supply, located adjacent to the property.

Barge Load-out Facility

The Company holds permits required to construct the barge load-out facility located approximately seven miles northwest of the Poplar Grove Mine’s plant site. Coal trucked from the Poplar Grove CHPP will be dumped into a stockpile and reclaimed into a chain feeder by a bulldozer. From the feeder, conveyor belts will transport the coal approximately 550 ft. into a 1,500 ton capacity barge. In order to accommodate changes in river level, the loading conveyor will be supported by a work barge and allowed to rise and fall as the river level changes.

Barge Waterways

The primary market access point for the Poplar Grove Mine’s saleable product is via barge on the Green River. The Green River is part of the Mississippi River System, a 12,350-mile (19,871 km) network of navigable waterways serving much of the Eastern and Midwestern United States.

Cypress Mine

Location

Located immediately north of the Poplar Grove Mine, the Cypress Mine is contained within McLean and Hopkins Counties, Kentucky, the Poplar Grove Mine lies between the towns of Hanson and Slaughters in the west and Calhoun and Sacramento in the east. The navigable Green River flows through the north-eastern corner of the Cypress Mine and the Pond River flows north through the center of the Property to its confluence with the Green River near the northern property boundary. The Pond River also forms the common border between McLean and Hopkins Counties. The property is located near a CSX Corporation rail line that parallels the Pennyrile Parkway, recently upgraded and renamed Interstate 69, along the western end of the project area.

Geological Setting

Subject to market conditions and securing required financing, the Cypress Mine will be mining the WK No. 9 coal seam approximately 650 feet below the surface at the proposed mine portal site. The coal seam is flat lying with a modest dip of 2 to 3 degrees generally to the northwest and toward the centre of the bowl-shaped Illinois Basin. Thickness of the WK No. 9 coal seam averages approximately 3.8 feet (46 inches), a suitable seam thickness for high-productivity underground mining with approximately 0.7 feet (8 inches) of out-of-seam mining needed to achieve an average mining height of 4.5 feet, or 54 inches, required for equipment clearance. Seam and mining heights are similar to a number of underground mines in the region.

Coal Quality

Coal seam quality data, available from exploration drill holes, has been utilized to determine the Poplar Grove Mine resource coal quality. Results are typical of the coal quality generally found in the west Kentucky portion of the Illinois Basin. A summary of the WK No. 9 drill hole quality data for the Cypress Mine is provided.

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Cypress Mine - Coal Quality Specifications

Raw Proximate Analysis
(As Received)
Washed Core Quality
(Equilibrium Moisture +4%)
EQ Moisture
Ash
Volatile Matter
Fixed Carbon
Chlorine
HGI
Calorific Value (Btu/lb)
Ash
Yield @
1.60
Float
6.7%
 
11.9
%
 
36.9
%
 
44.6
%
 
0.18
%
 
60
 
 
11,819
 
 
8.4
%
 
93.1
%

Coal Processing

The project will include a modern, fully-integrated, coal preparation plant in order to provide a consistent product, which meets the specifications of the Company’s customers. At full production, the coal preparation plant is expected to be capable of processing 5.1 million tons of ROM coal annually, which equates to approximately 3.8 million marketable tons per year. Average product yield is estimated at 77.0%, which includes direct shipment/preparation plant bypass of approximately 14% of the ROM production.

Mine Production

The mine plan includes a total production of 86.3 million ROM tons and 66.2 million saleable tons over an 18-year period including a two-year ramp-up period. At planned productivity, each super-section will produce approximately 2,300 to 2,400 tons of ROM coal per shift. ROM production for the project will total approximately 5.1 million tons per year at full production.

Initial Capital Costs

Total initial capital is estimated at $101.2 million which includes the cost of surface property, surface and underground mine development and infrastructure estimated at $61 million and the cost of a 700 ton per hour wash plant, barge load-out and surface facilities of $44 million. The total initial capital cost with an added 10% contingency reserve is $115 million. Sustaining capital for the mine, mine site infrastructure and CHPP have been estimated at $1.28 per ton.

Operating Costs

The average (steady state) annual operating cost for the Cypress Mine free-on-board barge, is estimated to be approximately $27.37 per saleable ton. Operating costs are projected for each year of the mine plan, considering projected annual ROM tonnage, clean tonnage and feet of advance. Operating cost projections are based on current pricing provided by reputable vendors and contractors and our estimates of staffing, wage and salary levels, employee benefits, operating and maintenance and supply costs per ton produced (for the mine) or processed (for the plant and dock). Other costs include outside services, sales and administrative costs, royalties, black lung federal excise tax, OSM reclamation fees and property tax and insurance.

Materials Handling and Barge Load-out Facility

Clean coal originating from the stockpiles located at the preparation plant will be reclaimed using a system of underground feeders. At the dock site, the conveyor will dump coal into a 500-ton capacity bin, which allows the loading of barges without re-handling coal. The bin will be equipped with two feeders allowing trucks to be loaded or coal to be transferred to the barge loader.

Mining Permits and Approvals

We believe that we have the permits necessary to construct the Poplar Grove and Cypress Mines. Construction of the Poplar Grove and Cypress Mines requires multiple permits for coal preparation and mine access-related facilities, spoil storage and for haul roads, transportation, loading and other incidental permits necessary for mining to occur. A listing of all current and pending permits is provided in the table below. In each case, the permit was issued in the name of our wholly-owned subsidiary, Hartshorne Mining LLC.

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Once we have completed construction, we will need to obtain and maintain additional permits to operate our mines.

Issued Permits:

Agency
Permit Type
Permit Description
Permit Number
Facility
KY DNR
SMCRA
Surface Area
875-8002
Poplar Grove Mine
KY DNR
SMCRA
Underground Mine
875-5010
Poplar Grove Mine
KY DNR
KPDES
Mine & Prep Plant
KYGW40071
Poplar Grove Mine
KY DNR
SMCRA
Dock Facility
875-6001
Buck Creek Dock
KY DNR
SMCRA
Underground Mine
875-5009
Cypress Mine
U.S. ACOE
US ACOE 404
Underground Mine
LRL-2011-707-b-
MOD
Cypress Mine &
Buck Creek Dock
KY DNR
KPDES
Underground Mine
KYGW40003
Cypress Mine &
Buck Creek Dock

Pending Permits:

Agency
Permit Type
Permit Description
Permit Number
Facility
KY DNR
SMCRA (revision)
Surface Area
875-8002
Poplar Grove Mine
KY DNR
KPDES (revision)
Mine & Prep Plan
KYGW40071
Poplar Grove Mine

Permitting Process and Risks

Applications for permits require extensive engineering and data analysis and presentation and must address a variety of environmental, health and safety matters associated with a proposed mining operation. Meeting all requirements imposed by applicable regulatory authorities may be costly and time consuming, and may delay or prevent commencement or continuation of mining operations. The permitting process for certain mining operations can extend over several years and can be subject to administrative and judicial challenge. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We cannot assure you that we will not experience difficulty or delays in obtaining mining permits in the future or that a current permit will not be revoked.

We are required to post bonds to secure performance under our permits. Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws and regulations described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws and regulations. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations that have outstanding environmental violations.

Markets and Transportation

We believe the location of the Poplar Grove and Cypress Mines provides us significant logistical advantages and access to secure infrastructure that will help us reach future customers. We have initially identified two key potential markets:

Initial Target Market – Ohio River Market. The Buck Creek Complex has low cost barge access to the Green and Ohio rivers, providing a transportation cost advantage over other Illinois Basin and U.S. coal producers. Our initial target market is 17 of the large base-load coal fired power plants located on the Ohio River. These plants consume approximately 50 million tons of coal per year, primarily from the Illinois Basin, and have all installed environmental controls.
Secondary Target Market – South East Market. We also have identified a secondary target market, the southeast U.S. market, which has traditionally been supplied by the Central Appalachian region. The increase in scrubber installations in the United States has provided an opportunity for low cost Illinois Basin coal to increasingly penetrate a large proportion of the eastern U.S. power market.

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Set forth below is a chart estimating Illinois Basin nominal contract prices per ton of 11,500 btu coal:


Marketing, Sales and Contracts

We have signed a coal supply agreement with Louisville Gas and Electric, or LG&E, and KU Energy LLC, to deliver coal from the Poplar Grove Mine. Set forth below is a summary of the key terms of that sales agreement (US$ in millions per ton):

Contracted Production
Fixed Contract Price
(FOB Barge; 11,200 btu/lb)
0 – 750,000 tons
$40.50
750,001 – 1,750,000
$41.50
1,750,001 – 2,750,000
$43.00
2,750,001 – 3,750,000
$44.25
3,750,001 – 4,750,000
$45.75
Total Sales Contract Value
$205 million

The agreement calls for fixed sales prices based on a F.O.B. basis delivered at the Green River barge load-out facility on the Green River and, under its terms, we are obligated to deliver a total of 4.75 million tons of 11,200 btu/lb product over a 5-year period, commencing around the end of the 2018 calendar year. The fixed coal sales prices for our 11,200 btu/lb coal specification begins at $40.50 per ton for the first 750,000 tons of coal delivered to the counterparties, escalating to $45.75 per ton for the final 1,000,000 tons sold.

The counterparties are subsidiaries of the PPL Corporation that are regulated utilities serving approximately 1.2 million customers. The counterparties own three power plants within our initial target Ohio River Market – in Trimble County, Ghent and Mill Creek.

Additionally, in October 2018 we signed an additional coal sales agreement with Ohio Valley Electric Corporation and its subsidiary Indiana-Kentucky Electric Corporation (“OVEC-IKEC”) to deliver 650,000 tons of coal from the Poplar Grove Mine from 2019 to 2020. OVEC-IKEC’s largest shareholder is American Electric Power (“AEP”) which is one of the largest electric utilities in the United States, serving nearly 5.4 million customers in 11 states.

Coal Sales Marketing Strategy. Our initial focus was to enter into a cornerstone sales contract (or mine opening contract) with an investment grade, highly respected utility that would be considered a “bankable document” and facilitate the execution of a debt facility for the construction of the Poplar Grove Mine. In addition to our cornerstone sales contract with LG&E and KU to deliver 4.75 million tons of coal over a 5-year period, we have now signed an

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additional coal sales agreement with OVEC-IKEC to deliver 650,000 tons of coal from 2019 to 2020. In the future, we plan to participate in the bi-annual coal solicitation process to sell additional coal to utilities initially located in the Ohio River Market. As we expand production at Poplar Grove and Cypress Mines, we also will aggressively target coal sales to the secondary southeast U.S. market.

Competition

The coal industry is highly competitive. We compete for U.S. sales with numerous coal producers in the Illinois Basin, Appalachian region 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.

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 affected by the price and availability of high sulfur coal.

Consultants

The BFS was managed by MM&A with utilization of local industry consultants, with expertise in coal mine development in the Illinois Basin region, to analyze the various components of the BFS, including, but not limited to, the design of coal seam access and slope portal, design of the mine, design of processing facilities, and the preparation of coal marketing studies.

THERMAL COAL INDUSTRY

Coal is a fossil fuel and is the altered remains of prehistoric vegetation that originally accumulated in swamps and peat bogs. The build-up of silt and other sediments, together with movements in the earth’s crust, known as tectonic movements, buried swamps and peat bogs, often to great depths. With burial, the plant material was subjected to high temperatures and pressures. This caused physical and chemical changes in the vegetation, transforming it into peat and then into coal (Source: www.worldcoal.org; December 2017).

Coal is generally categorized into metallurgical coal (for steel making) and thermal coal (to produce electricity). Coal has historically been a relatively inexpensive fuel for power generation and remains a major fuel for global energy. 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. Underground mining employs one of the following two methods: longwall mining or continuous (or room and pillar) mining. The Company will be adopting the continuous mining method, whereby 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. Generally, 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.

There are an estimated 1.1 trillion metric tonnes of proven coal reserves worldwide providing enough coal to last around 150 years at current rates of production. In contrast, proven oil and gas reserves are equivalent to around 50 and 52 years at current production levels (Source: www.worldcoal.org; December 2017). According to the BP Statistical Review published in June 2017, coal provided 28% of the world’s primary energy consumption.

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REGULATORY MATTERS

The coal mining industry is subject to extensive regulation by federal, state and local authorities on matters such as:

employee health and safety;
mine permits and other licensing requirements;
air quality standards;
water quality standards;
storage of petroleum products and substances that are regarded as hazardous under applicable laws or that, if spilled, could reach waterways or wetlands;
plant and wildlife protection;
reclamation and restoration of mining properties after mining is completed;
discharge of materials;
storage and handling of explosives;
wetlands protection;
surface subsidence from underground mining; and
the effects, if any, that mining has on groundwater quality and availability.

In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which has adversely affected demand for coal. It is possible that new legislation or regulations may be adopted, or that existing laws or regulations may be differently interpreted or more stringently enforced, any of which could have a significant impact on our mining operations or our customers’ ability to use coal.

We are committed to conducting mining operations in compliance with applicable federal, state and local laws and regulations. However, because of the extensive and detailed nature of these regulatory requirements, particularly the regulatory system of the MSHA where citations can be issued without regard to fault and many of the standards include subjective elements, it is not reasonable to expect any coal mining company to be free of citations. When we receive a citation, we attempt to remediate any identified condition immediately. While we have not quantified all of the costs of compliance with applicable federal and state laws and associated regulations, those costs have been and are expected to continue to be significant. Compliance with these laws and regulations has substantially increased the cost of coal mining for domestic coal producers.

Capital expenditures for environmental matters have not been material in recent years. We have accrued for the present value of the estimated cost of asset retirement obligations and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement obligations and mine closing costs are based upon permit requirements and the costs and timing of asset retirement obligations and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if these accruals were insufficient.

Mine Health and Safety Laws

Stringent safety and health standards have been imposed by federal legislation since the Federal Coal Mine Health and Safety Act of 1969, or CMHSA, was adopted. The Federal Mine Safety and Health Act of 1977, or FMSHA, and regulations adopted pursuant thereto, significantly expanded the enforcement of health and safety standards of the CMHSA, and imposed extensive and detailed safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations, and numerous other matters. MSHA monitors and rigorously enforces compliance with these federal laws and regulations. In addition, most of the states where we operate have state programs for mine safety and health regulation and enforcement. Federal and state safety and health regulations affecting the coal mining industry are perhaps the most comprehensive and rigorous system in the U.S. for protection of employee safety and have a significant effect on our operating costs. Although many of the requirements primarily impact underground mining, our competitors in all of the areas in which we operate are subject to the same laws and regulations.

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The FMSHA has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability, or liability without fault, and FMSHA requires imposition of a civil penalty for each cited violation. Negligence and gravity assessments, and other factors can result in the issuance of various types of orders, including orders requiring withdrawal from the mine or the affected area, and some orders can also result in the imposition of civil penalties. The FMSHA also contains criminal liability provisions. For example, criminal liability may be imposed upon corporate operators who knowingly and willfully authorize, order or carry out violations of the FMSHA, or its mandatory health and safety standards.

The Federal Mine Improvement and New Emergency Response Act of 2006, or MINER Act, significantly amended the FMSHA, imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, MSHA has issued new or more stringent rules and policies on a variety of topics, including:

sealing off abandoned areas of underground coal mines;
mine safety equipment, training and emergency reporting requirements;
substantially increased civil penalties for regulatory violations;
training and availability of mine rescue teams;
underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;
flame-resistant conveyor belts, fire prevention and detection, and use of air from the belt entry; and
post-accident two-way communications and electronic tracking systems.

MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards.

In 2014, MSHA began implementation of a finalized new regulation titled “Lowering Miner’s Exposure Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors.” The final rule implements a reduction in the allowable respirable coal mine dust exposure limits, requires the use of sampling data taken from a single sample rather than an average of samples, and increases oversight by MSHA regarding coal mine dust and ventilation issues at each mine, including the approval process for ventilation plans at each mine, all of which increase mining costs. The second phase of the rule began in February 2016 and requires additional sampling for designated and other occupations using the new continuous personal dust monitor technology, which provides real time dust exposure information to the miner. Phase three of the rule began in August 2016, and resulted in lowering the current respirable dust level of 2.0 milligrams per cubic meter to 1.5 milligrams per cubic meter of air. Compliance with these rules can result in increased costs on our operations, including, but not limited to, the purchasing of new equipment and the hiring of additional personnel to assist with monitoring, reporting, and recordkeeping obligations.

Additionally, in July 2014, MSHA proposed a rule addressing the “criteria and procedures for assessment of civil penalties.” Public commenters have expressed concern that the proposed rule exceeds MSHA’s rulemaking authority and would result in substantially increased civil penalties for regulatory violations cited by MSHA. MSHA last revised the process for proposing civil penalties in 2006 and, as discussed above, civil penalties increased significantly. The notice-and-comment period for this proposed rule closed, and it is uncertain when MSHA will present a final rule addressing these civil penalties.

In January 2015, MSHA published a final rule requiring mine operators to install proximity detection systems on continuous mining machines, over a staggered time frame ranging from November 2015 through March 2018. The proximity detection systems initiate a warning or shutdown the continuous mining machine depending on the proximity of the machine to a miner. MSHA subsequently proposed a rule requiring mine operators to also install proximity detection systems on other types of underground mobile mining equipment. The comment period for this proposed rule closed on April 10, 2017.

Subsequent to passage of the MINER Act, Illinois, Kentucky, Pennsylvania and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Additionally, state administrative agencies can promulgate administrative rules and regulations affecting our operations. Other states may pass similar legislation or administrative regulations in the future.

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Some of the costs of complying with existing regulations and implementing new safety and health regulations may be passed on to our customers. Although we have not quantified the full impact, implementing and complying with these new state and federal safety laws and regulations have had, and are expected to continue to have, an adverse impact on our results of operations and financial position.

Black Lung Benefits Act

The Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, or BLBA, requires businesses that conduct current mining operations to make payments of black lung benefits to current and former coal miners with black lung disease and to some survivors of a miner who dies from this disease. The BLBA levies a tax on production of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price, in order to compensate miners who are totally disabled due to black lung disease and some survivors of miners who died from this disease, and who were last employed as miners prior to 1970 or subsequently where no responsible coal mine operator has been identified for claims. In addition, the BLBA provides that some claims for which coal operators had previously been responsible are or will become obligations of the government trust funded by the tax. The Revenue Act of 1987 extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent. For miners last employed as miners after 1969 and who are determined to have contracted black lung, we intend to self-insure the potential cost of compensating such miners using our actuary estimates of the cost of present and future claims. We may also be liable under state statutes for black lung claims. Congress and state legislatures regularly consider various items of black lung legislation, which, if enacted, could adversely affect our business, results of operations and financial position.

The revised BLBA regulations took effect in January 2001, relaxing the stringent award criteria established under previous regulations and thus potentially allowing new federal claims to be awarded and allowing previously denied claimants to re-file under the revised criteria. These regulations may also increase black lung related medical costs by broadening the scope of conditions for which medical costs are reimbursable and increase legal costs by shifting more of the burden of proof to the employer.

The Patient Protection and Affordable Care Act, enacted in 2010, includes significant changes to the federal black lung program retroactive to 2005, 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.

Workers’ Compensation

We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers’ compensation laws also compensate survivors of workers who suffer employment related deaths. Several states in which we operate consider changes in workers’ compensation laws from time to time. We generally intend to self-insure this potential expense using our actuary estimates of the cost of present and future claims. For more information concerning our requirement to maintain bonds to secure our workers’ compensation obligations, see the discussion of surety bonds below under “Bonding Requirements.

Coal Industry Retiree Health Benefits Act

The Federal Coal Industry Retiree Health Benefits Act, or CIRHBA, was enacted to fund health benefits for some United Mine Workers of America retirees. CIRHBA merged previously established union benefit plans into a single fund into which “signatory operators” and “related persons” are obligated to pay annual premiums for beneficiaries. CIRHBA also created a second benefit fund for miners who retired between July 21, 1992 and September 30, 1994, and whose former employers are no longer in business. Because of our union-free status, we are not required to make payments to retired miners under CIRHBA.

Surface Mining Control and Reclamation Act

The Federal Surface Mining Control and Reclamation Act of 1977, or SMCRA, and similar state statutes establish operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. Although we have minimal surface mining activity and no mountaintop removal mining activity, SMCRA nevertheless requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of our mining activities.

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SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore the surface to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. We believe we are in compliance in all material respects with applicable regulations relating to reclamation.

In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The tax for surface-mined and underground-mined coal is $0.28 per ton and $0.12 per ton, respectively. We will provide for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when there is a present obligation to do so, which we expect will occur as mine development occurs. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation or orphaned mine sites and acid mine drainage control on a statewide basis.

Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine operators and other third parties can be imputed to other companies that are deemed, according to the regulations, to have owned or controlled the third-party violator. Sanctions against the owner or controller are quite severe and can include being blocked from receiving new permits and having any permits revoked that were issued after the time of the violations or after the time civil penalties or reclamation fees became due. We are not aware of any currently pending or asserted claims against us relating to the ownership or control theories discussed above. However, we cannot assure you that such claims will not be asserted in the future.

The OSM in November 2009 published an Advance Notice of Proposed Rulemaking, announcing its intent to revise the Stream Buffer Zone, or SBZ, rule published in December 2008. The SBZ rule prohibits mining disturbances within 100 feet of streams if there would be a negative effect on water quality. Environmental groups brought lawsuits challenging the rule, and in a March 2010 settlement, the OSM agreed to rewrite the SBZ rule. In January 2013, the environmental groups reopened the litigation against OSM for failure to abide by the terms of the settlement. Oral arguments were heard on January 31, 2014. OSM published a notice in December 2014 to vacate the 2008 SBZ rule to comply with an order issued by the U.S. District Court for the District of Columbia and reimplemented the 1983 SBZ rule.

OSM issued its final Stream Protection Rule, or SPR, in December 2016 to replace the vacated SBZ rule. The rule would have generally prohibited the approval of permits issued pursuant to SMCRA where the proposed operations would result in “material damage to the hydrologic balance outside the permit area.” Pursuant to the rule, permittees would have also been required to restore any perennial or intermittent streams that a permittee mined through. Finally, the rule would have also imposed additional baseline data collection, surface/groundwater monitoring, and bonding and financial assurance requirements. However, in February 2017, both the U.S. House of Representatives and the Senate passed resolutions disapproving the SPR under the Congressional Review Act, or CRA. President Trump signed the resolution on February 16, 2017 and, pursuant to the CRA, the SPR “shall have no force or effect” and OSM cannot promulgate a substantially similar rule absent future legislation. Whether Congress will enact future legislation to require a new SPR rule remains uncertain.

Following the spill of coal combustion residues, or CCRs, in the Tennessee Valley Authority impoundment in Kingston, Tennessee, in December 2009, the EPA issued proposed rules on CCRs in 2010. This final rule was published in December 2014. The EPA’s final rule does not address the placement of CCRs in minefills or non-minefill uses of CCRs at coal mine sites. OSM has announced their intention to release a proposed rule to regulate placement and use of CCRs at coal mine sites, but, to date, no further action has been taken. These actions by OSM, could potentially result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities, and additional enforcement actions.

Bonding Requirements

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, to pay certain black lung claims, and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for us and for our competitors to secure new surety bonds without posting collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. It is possible that surety bond issuers may refuse

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to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow.

Air Emissions

The CAA and similar state and local laws and regulations regulate emissions into the air and affect coal mining operations. The CAA directly impacts our coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, achieve certain emissions standards, or implement certain work practices on sources that emit various air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other coal-burning facilities. There have been a series of federal rulemakings focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and any additional measures required under applicable state and federal laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans, or SIPs, could make coal a less attractive fuel alternative in the planning and building of power plants in the future. A significant reduction in coal’s share of power generating capacity could have a material adverse effect on our business, financial condition and results of operations. Since 2010, utilities have completed or formally announced the retirement or conversion of over 500 coal-fired electric generating units through 2030.

In addition to the GHG issues discussed below, the air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the following:

The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower-sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels. These requirements would not be supplanted by a replacement rule for the Clean Air Interstate Rule, or CAIR, discussed below.
The CAIR calls for power plants in 28 states and Washington, D.C. to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system in effect for acid rain. In June 2011, the EPA finalized the Cross-State Air Pollution Rule, or CSAPR, a replacement rule for CAIR, which would have required 28 states in the Midwest and eastern seaboard to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions would have commenced in 2012 with further reductions effective in 2014. However, in August 2012, the D.C. Circuit Court of Appeals vacated CSAPR, finding the EPA exceeded its statutory authority under the CAA and striking down the EPA’s decision to require federal implementation plans, or FIPs, rather than SIPs, to implement mandated reductions. In its ruling, the D.C. Circuit Court of Appeals ordered the EPA to continue administering CAIR but proceed expeditiously to promulgate a replacement rule for CAIR. The U.S. Supreme Court granted the EPA’s certiorari petition appealing the D.C. Circuit Court of Appeals’ decision and heard oral arguments in December 2013. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit Court of Appeals’ decision, concluding that the EPA’s approach is lawful. CSAPR has been reinstated and the EPA began implementation of Phase 1 requirements in January 2015. In September 2016, EPA finalized the CSAPR Update to respond to the remand by the D.C. Circuit Court of Appeals. Implementation of Phase 2 began in 2017. Further litigation is expected against the CSAPR Update in the D.C. Circuit Court of Appeals. The impacts of CSAPR Update are unknown at the present time due to the implementation of MATS, discussed below, and the significant number of coal retirements that have resulted and that potentially will result from MATS.
In February 2012, the EPA adopted the MATS, which regulates the emission of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal and oil-fired power plants. In March

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2013, the EPA finalized a reconsideration of the MATS rule as it pertains to new power plants, principally adjusting emissions limits to levels attainable by existing control technologies. Appeals were filed and oral arguments were heard by the D.C. Circuit Court of Appeals in December 2013. In April 2014, the D.C. Circuit Court of Appeals upheld MATS. In June 2015, the U.S. Supreme Court remanded the final rule back to the D.C. Circuit holding that the agency must consider cost before deciding whether regulation is necessary and appropriate. In December 2015, the EPA issued, for comment, the proposed supplemental finding. In April 2016, the EPA issued a final supplemental finding upholding the rule and concluding that a cost analysis supports the MATS rule. Many electric generators have already announced retirements due to the MATS rule. In April 2017, the D.C. Circuit Court of Appeals for the District of Columbia granted a request by the EPA to delay oral arguments in the pending appeal over the MATS rule. EPA requested that the court delay oral arguments to provide the new presidential administration with additional time to evaluate supplemental agency findings on the costs associated with the MATS rule. Although various issues surrounding the MATS rule remain subject to litigation in the D.C. Circuit, the MATS will force generators to make capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating units. The announced and possible additional retirements are likely to reduce the demand for coal. 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, or Congress may decrease the future demand for coal. We continue to evaluate the possible scenarios associated with CSAPR Update and MATS and the effects they may have on our business and our results of operations, financial condition or cash flows.

In January 2013, the EPA issued final Maximum Achievable Control Technology, or MACT, standards for several classes of boilers and process heaters, including large coal-fired boilers and process heaters, or Boiler MACT, which require owners of industrial, commercial, and institutional boilers to comply with standards for air pollutants, including mercury and other metals, fine particulates, and acid gases such as hydrogen chloride. Businesses and environmental groups have filed legal challenges to Boiler MACT in the D.C. Circuit Court of Appeals and petitioned the EPA to reconsider the rule. In December 2014, the EPA announced reconsideration of the standard and will accept public comment on five issues for its standards on area sources, will review three issues related to its major-source boiler standards, and four issues relating to commercial and solid waste incinerator units. Before reconsideration, the EPA estimated the rule will affect 1,700 existing major source facilities with an estimated 14,316 boilers and process heaters. While some owners would make capital expenditures to retrofit boilers and process heaters, a number of boilers and process heaters could be prematurely retired. Retirements are likely to reduce the demand for coal. In August 2016, the D.C. Circuit Court of Appeals vacated a portion of the rule while remanding portions back to the EPA. In December 2016, the D.C. Circuit Court of Appeals agreed to the EPA request to remand the rule back to the EPA without vacatur. The impact of the regulations will depend on the EPA’s reconsideration and the outcome of subsequent legal challenges.
The EPA is required by the CAA to periodically re-evaluate the available health effects information to determine whether the national ambient air quality standards, or NAAQS, should be revised. Pursuant to this process, the EPA has adopted more stringent NAAQS for fine particulate matter, ozone, nitrogen oxide and sulfur dioxide. As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards and other states will be required to develop new SIPs for areas that were previously in “attainment” but do not attain the new standards. In addition, under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants. Initial non-attainment determinations related to the revised sulfur dioxide standard became effective in October 2013. In addition, in January 2013, the EPA updated the NAAQS for fine particulate matter emitted by a wide variety of sources including power plants, industrial facilities, and gasoline and diesel engines, tightening the annual PM 2.5 standard to 12 micrograms per cubic meter. The revised standard became effective in March 2013. In November 2013, the EPA proposed a rule to clarify PM 2.5 implementation requirements to the states for current 1997 and 2006 non-attainment areas. In July 2016, EPA issued a final rule for states to use in creating their plans to address particulate matter. In October 2015, the EPA published a final rule that reduced the ozone NAAQS from 75 to 70 parts per billion. Murray Energy filed a challenge to the final rule in the D.C. Circuit. Since that time, other industry and state petitioners have filed challenges as have several environmental groups. Attainment dates for the new

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standards range between 2013 and 2030, depending on the severity of the non-attainment. In July 2009, the D.C. Circuit Court of Appeals vacated part of a rule implementing the ozone NAAQS and remanded certain other aspects of the rule to the EPA for further consideration. In June 2013, the EPA proposed a rule for implementing the 2008 ozone NAAQS. Under a consent decree published in the Federal Register in January 2017, EPA agreed to review the NAAQS for sulfur oxide with a final decision due by 2019. New standards may impose additional emissions control requirements on new and expanded coal-fired power plants and industrial boilers. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our mining operations and our customers could be affected when the new standards are implemented by the applicable states, and developments might indirectly reduce the demand for coal.

The EPA’s regional haze program is designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. Under the program, states are required to develop SIPs to improve visibility. Typically, these plans call for reductions in sulfur dioxide and nitrogen oxide emissions from coal-fueled electric plants. In recent cases, the EPA has decided to negate the SIPs and impose stringent requirements through FIPs. The regional haze program, including particularly the EPA’s FIPs, and any future regulations may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions. These requirements could limit the demand for coal in some locations.
The EPA’s new source review, or NSR, program under the CAA in certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install more stringent air emissions control equipment. The Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the NSR program. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the program. Several of these lawsuits have settled, but others remain pending. Depending on the ultimate resolution of these cases, demand for coal could be affected.

Carbon Dioxide Emissions

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide, which is considered a GHG. Combustion of fuel for mining equipment used in coal production also emits GHGs. Future regulation of GHG emissions in the United States could occur pursuant to future U.S. treaty commitments, new domestic legislation or regulation by the EPA. Former President Obama expressed support for a mandatory cap and trade program to restrict or regulate emissions of GHGs and Congress has considered various proposals to reduce GHG emissions, and it is possible federal legislation could be adopted in the future. Internationally, the Kyoto Protocol set binding emission targets for developed countries that ratified it (the United States did not ratify, and Canada officially withdrew from its Kyoto commitment in 2012) to reduce their global GHG emissions. The Kyoto Protocol was nominally extended past its expiration date of December 2012, with a requirement for a new legal construct to be put into place by 2015. The United Nations Framework Convention on Climate Change met in Paris, France in December 2015 and agreed to an international climate agreement, which we refer to as the Paris Agreement. 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. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement cannot be predicted at this time. Future participation in the Paris Agreement by the United States remains uncertain. However, many states, regions and governmental bodies have adopted GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-fired electric generating facilities. Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal could be negatively impacted, which would have an adverse effect on our operations.

Even in the absence of new federal legislation, the EPA has begun to regulate GHG emissions under the CAA based on the U.S. Supreme Court’s 2007 decision in Massachusetts v. Environmental Protection Agency that the EPA has authority to regulate GHG emissions. In 2009, the EPA issued a final rule, known as the “Endangerment Finding”,

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declaring that GHG emissions, including carbon dioxide and methane, endanger public health and welfare and that six GHGs, including carbon dioxide and methane, emitted by motor vehicles endanger both the public health and welfare.

In May 2010, the EPA issued its final “tailoring rule” for GHG emissions, a policy aimed at shielding small emission sources from CAA permitting requirements. The EPA’s rule phases in various GHG-related permitting requirements beginning in January 2011. Beginning July 1, 2011, the EPA requires facilities that must already obtain NSR permits (new or modified stationary sources) for other pollutants to include GHGs in their permits for new construction projects that emit at least 100,000 tons per year of GHGs and existing facilities that increase their emissions by at least 75,000 tons per year. These permits require that the permittee adopt the Best Available Control Technology, or BACT. In June 2014, the U.S. Supreme Court invalidated the EPA’s position that power plants and other sources can be subject to permitting requirements based on their GHG emissions alone. For carbon dioxide BACT to apply, CAA permitting must be triggered by another regulated pollutant (e.g., sulfur dioxide, or SO2).

As a result of revisions to its preconstruction permitting rules that became fully effective in 2011, the EPA is now requiring new sources, including coal-fired power plants, to undergo control technology reviews for GHGs (predominantly 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. The EPA has also issued final rules requiring the monitoring and reporting of greenhouse gas emissions from certain sources.

In March 2012, the EPA proposed New Source Performance Standards, or NSPS, for carbon dioxide emissions from new fossil fuel-fired power plants. The proposal requires new coal units to meet a carbon dioxide emissions standard of 1,000 lbs. CO2/MWh, which is equivalent to the carbon dioxide emitted by a natural gas combined cycle unit. In January 2014, the EPA formally published its re-proposed NSPS for carbon dioxide emissions from new power plants. The re-proposed rule requires an emissions standard of 1,100 lbs. CO2/MWh for new coal-fired power plants. To meet such a standard, new coal plants would be required to install CCS technology. In August 2015, the EPA released final rules requiring newly constructed coal-fired steam electric generating units to emit no more than 1,400 lbs CO2/MWh (gross) and be constructed with CCS to capture 16% of CO2 produced by an electric generating unit burning bituminous coal. At the same time, the EPA finalized GHG emissions regulations for modified and existing power plants. The rule for modified sources required reducing GHG emissions from any modified or reconstructed source and could limit the ability of generators to upgrade coal-fired power plants thereby reducing the demand for coal. The rule for existing sources proposes to establish different target emission rates (lbs per megawatt hour) for each state and has an overall goal to achieve a 32% reduction of carbon dioxide emissions from 2005 levels by 2030. The compliance period begins in 2022 and in 2030 CO2 emissions goals must be met. In October 2017, the EPA proposed to repeal the new NSPS. A public hearing on the repeal was held in November 2017.

In June 2014, the EPA proposed CO2 emission “guidelines” for modified and existing fossil fuel-fired power plants under Section 111(d) of the CAA. The EPA finalized the CPP in August 2015, which established carbon pollution standards for 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 due in September 2016, subject to potential extensions of up to 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. Although each state can determine its own method of compliance, the requirements rely on decreased use of coal and increased use of natural gas and renewables for electricity generation, as well as reductions in the amount of electricity used by consumers. Judicial challenges have been filed and oral arguments were heard by the D.C. Circuit Court of Appeals in September 2016, but a final decision has not yet been issued. On February 9, 2016, the U.S. Supreme Court issued a stay, halting implementation of the regulations. On March 28, 2017, President Trump signed an Executive Order directing the EPA to review the regulations, and on April 4, 2017, the EPA announced that it was reviewing the 2015 carbon dioxide regulations. On April 28, 2017, the U.S. Court of Appeals for the District of Columbia stayed the litigation pending the current administration’s review. That stay was extended for another 60 days on August 8, 2017. On October 10, 2017, the EPA initiated the formal rulemaking process to repeal the regulations. The EPA’s proposal will be subject to public comment and likely legal challenge, and as such we cannot predict at this time what impact the rulemaking will have on the demand for coal.

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Collectively, these requirements have led to premature retirements and could lead to additional premature retirements of coal-fired generating units and reduce the demand for coal. Congress has rejected legislation to restrict carbon dioxide emissions from existing power plants and it is unclear whether the EPA has the legal authority to regulate carbon dioxide emissions from existing and modified power plants as proposed in the NSPS and CPP. Substantial limitations on GHG emissions could adversely affect demand for the coal we produce.

There have been numerous protests of and challenges to the permitting of new coal-fired power plants by environmental organizations and state regulators for concerns related to GHG emissions. For instance, various state regulatory authorities have rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fueled power plants without limits on GHG emissions have been appealed to the EPA’s Environmental Appeals Board. In addition, over thirty states have currently adopted “renewable energy standards” or “renewable portfolio standards,” which encourage or require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until between 2020 and 2030. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers, they may reduce the demand for coal-fired power, and may affect long-term demand for our coal. Finally, a federal appeals court allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, while a second federal appeals court dismissed a similar case on procedural grounds. The U.S. Supreme Court overturned that decision in June 2011, holding that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions. The U.S. Supreme Court did not, however, decide whether similar claims can be brought under state common law. As a result, despite this favorable ruling, tort-type liabilities remain a concern. In 2017, for example, New York City as well as multiple California counties and localities filed suits against oil, natural gas, and coal companies, seeking recompense, under common law, for damages allegedly caused by these companies’ roles in intensifying climate change. These actions are currently pending.

In addition, environmental advocacy groups have filed a variety of judicial challenges claiming that the environmental analyses conducted by federal agencies before granting permits and other approvals necessary for certain coal activities do not satisfy the requirements of the National Environmental Policy Act, or NEPA. These groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects. In December 2014, the Council on Environmental Quality released updated draft guidance discussing how federal agencies should consider the effects of GHG emissions and climate change in their NEPA evaluations. The guidance encourages agencies to provide more detailed discussion of the direct, indirect, and cumulative impacts of a proposed action’s reasonably foreseeable emissions and effects. This guidance could create additional delays and costs in the NEPA review process or in our operations, or even an inability to obtain necessary federal approvals for our future operations, including due to the increased risk of legal challenges from environmental groups seeking additional analysis of climate impacts.

Many states and regions have adopted GHG initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHG by certain facilities, including coal-fired electric generating facilities. For example, in 2005, ten north-eastern states entered into the Regional Greenhouse Gas Initiative agreement, or RGGI, calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states. The members of RGGI have established in statutes and/or regulations a carbon dioxide trading program. Auctions for carbon dioxide allowances under the program began in September 2008. Though New Jersey withdrew from RGGI in 2011, since its inception, several additional north-eastern states and Canadian provinces have joined as participants or observers.

Following the RGGI model, five Western states launched the Western Regional Climate Action Initiative to identify, evaluate, and implement collective and cooperative methods of reducing GHG in the region to 15% below 2005 levels by 2020. These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, in November 2011, six states withdrew, leaving California and the four Canadian provinces as members. At a January 2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largest carbon market in North America and provide a model to guide future efforts to establish national approaches in both Canada and the United States to reduce GHG emissions. It is likely that these regional efforts will continue.

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It is possible that future international, federal and state initiatives to control GHG emissions could result in increased costs associated with coal production and consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for coal consumption could result in some customers switching to alternative sources of fuel, or otherwise adversely affect our operations and demand for our products, which could have a material adverse effect on our business, financial condition and results of operations.

Water Discharge

The Clean Water Act, or CWA, and similar state and local laws and regulations affect coal mining operations by imposing restrictions on effluent discharge into waters and the discharge of dredged or fill material into the waters of the U.S. Regular monitoring, as well as compliance with reporting requirements and performance standards, is a precondition for the issuance and renewal of permits governing the discharge of pollutants into water. Section 404 of the CWA imposes permitting and mitigation requirements associated with the dredging and filling of wetlands and streams. The CWA and equivalent state legislation, where such equivalent state legislation exists, affect coal mining operations that impact wetlands and streams. Although permitting requirements have been tightened in recent years, we believe we have obtained all necessary permits required under CWA Section 404 as it has traditionally been interpreted by the responsible agencies. However, mitigation requirements under existing and possible future “fill” permits may vary considerably. For that reason, the setting of post-mine asset retirement obligation accruals for such mitigation projects is difficult to ascertain with certainty and may increase in the future. Although more stringent permitting requirements may be imposed in the future, we are not able to accurately predict the impact, if any, of such permitting requirements.

The U.S. Army Corps of Engineers, or Corps of Engineers, maintains two permitting programs under CWA Section 404 for the discharge of dredged or fill material – one for “individual” permits and a more streamlined program for “general” permits. In June 2010, the Corps of Engineers suspended the use of “general” permits under Nationwide Permit 21, or NWP 21, in the Appalachian states. In February 2012, the Corps of Engineers reissued the final 2012 NWP 21. The Center for Biological Diversity later filed a notice of intent to sue the Corps of Engineers based on allegations the 2012 NWP 21 program violated the Endangered Species Act, or ESA. The Corps of Engineers and National Marine Fisheries Service, or NMFS, have completed their programmatic ESA Section 7 consultation process on the Corps of Engineers’ 2012 NWP 21 package, and NMFS has issued a revised biological opinion finding that the NWP 21 program does not jeopardize the continued existence of threatened and endangered species and will not result in the destruction or adverse modification of designated critical habitat. However, the opinion contains 12 additional protective measures the Corps of Engineers will implement in certain districts to “enhance the protection of listed species and critical habitat.” While these measures will not affect previously verified permit activities where construction has not yet been completed, several Corps of Engineers districts with mining operations will be impacted by the additional protective measures going forward. These measures include additional reporting and notification requirements, potential imposition of new regional conditions and additional actions concerning cumulative effects analyses and mitigation. Our coal mining operations typically require Section 404 permits to authorize activities such as the creation of slurry ponds and stream impoundments. The CWA authorizes the EPA to review Section 404 permits issued by the Corps of Engineers, and in 2009, the EPA began reviewing Section 404 permits issued by the Corps of Engineers for coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

For instance, even though the State of West Virginia has been delegated the authority to issue permits for coal mines in that state, the EPA is taking a more active role in its review of National Pollutant Discharge Elimination System, or NPDES, permit applications for coal mining operations in Appalachia. The EPA has stated that it plans to review all applications for NPDES permits. Indeed, final guidance issued by the EPA in July 2011, encouraged the EPA regions 3, 4 and 5 to object to the issuance of state program NPDES permits where the region does not believe that the proposed permit satisfies the requirements of the CWA, and with regard to state issued general Section 404 permits, support the previously drafted Enhanced Coordination Procedures, or ECP. In October 2011, the U.S. District Court for the District of Columbia rejected the ECP on several different legal grounds and later, this same court enjoined the EPA from any further usage of its final guidance. The U.S. Supreme Court denied a request to review this decision. Any future application of procedures similar to ECP, such as may be enacted following notice and comment rulemaking, would have the potential to delay issuance of permits for surface coal mines, or to change the conditions or restrictions imposed in those permits.

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The EPA also has statutory “veto” power over a Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an “unacceptable adverse effect.” In January 2011, the EPA exercised its veto power to withdraw or restrict the use of a previously issued permit for Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action was the first time that such power was exercised with regard to a previously permitted coal mining project. A challenge to the EPA’s exercise of this authority was made in the U.S. District Court for the District of Columbia and in March 2012, that court ruled that the EPA lacked the statutory authority to invalidate an already issued Section 404 permit retroactively. In April 2013, the D.C. Circuit Court of Appeals reversed this decision and authorized the EPA to retroactively veto portions of a Section 404 permit. The U.S. Supreme Court denied a request to review this decision. Any future use of the EPA’s Section 404 “veto” power could create uncertainly with regard to our continued use of current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our coal revenues. In addition, the EPA initiated a preemptive veto prior to the filing of any actual permit application for a copper and gold mine based on fictitious mine scenario. The implications of this decision could allow the EPA to bypass the state permitting process and engage in watershed and land use planning.

Total Maximum Daily Load, or TMDL, regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired water body can receive and still meet state water quality standards, and to allocate pollutant loads among the point and non-point pollutant sources discharging into that water body. Likewise, when water quality in a receiving stream is better than required, states are required to conduct an antidegradation review before approving discharge permits. The adoption of new TMDL-related allocations or any changes to antidegradation policies for streams near our coal mines could require more costly water treatment and could adversely affect our coal production.

In June 2015, the EPA issued a new rule providing a definition of “waters of the United States”, or WOTUS, under the CAA. This rule is broadly written and expands the EPA and Corps of Engineers jurisdiction. WOTUS creates new federal authority over lands, ditches, and potentially on-site mining waters. Of critical concern to our industry is the possibility that many water features commonly found on mine sites which are currently not considered jurisdictional could nevertheless fall within the definition of WOTUS under the proposed rule. Ditches, closed loop systems, on-site ponds, impoundments, and other water management features are integral to mining operations, and are used to manage on-site waters in an environmentally sound and frequently statutorily mandated manner. The rule could lead to substantially increased permitting requirements with more costs, delays, and increased risk of litigation. Industry groups have challenged the final rule. Multiple suits were filed across the country by states, industry, and outside parties. The Coal Industry is currently active in suits in the Texas District Court and Sixth Circuit Court of Appeals, though the coalition has moved to intervene in several suits (to both defend certain provisions in the rule important to industry and contest overly-broad provisions). The Sixth Circuit ordered a nationwide stay of the rule that will remain in effect at least until it issues its jurisdictional determination (expected in the near future). In January 2018, the U.S. Supreme Court ruled that the WOTUS rule must first be reviewed in federal district courts, remanding the case at issue to the district level and putting the status of the Sixth Circuit’s stay into question. In addition, in June 2017, the EPA and the U.S. Army Corps proposed a rule that would initiate the first step in a two-step process intended to review and revise the definition of WOTUS. Under the proposal, the first step would be to rescind the May 2015 final rule and put back into effect the narrower language defining WOTUS under the Clean Water Act that existed prior to the rule. The second step would be a notice-and-comment rule-making in which the agencies will conduct a substantive reevaluation of the definition of WOTUS.

Hazardous Substances and Wastes

The Federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, otherwise known as the “Superfund” law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the present and former owners or operators of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for the release of hazardous substances may be subject to joint and several liability under CERCLA for the costs of cleaning up releases of hazardous substances and natural resource damages. Some products used in coal mining operations generate waste containing hazardous substances. We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.

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The Federal Resource Conservation and Recovery Act, or RCRA, and corresponding state laws regulating hazardous waste affect coal mining operations by imposing requirements for the generation, transportation, treatment, storage, disposal, and clean-up of hazardous wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous substances. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, we believe such costs will not have a material impact on our operations.

In June 2010, the EPA released a proposed rule to regulate the disposal of certain coal combustion by-products, or CCB. The proposed rule set forth two very different options for regulating CCB under RCRA. The first option called for regulation of CCB as a hazardous waste under Subtitle C, which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option utilized Subtitle D, which would give the EPA authority to set performance standards for waste management facilities and would be enforced primarily through citizen suits. The proposal leaves intact the Bevill exemption for beneficial uses of CCB. In April 2012, several environmental organizations filed suit against the EPA to compel the EPA to take action on the proposed rule. Several companies and industry groups intervened. A consent decree was entered on January 29, 2014.

The EPA finalized the CCB rule on December 19, 2014, setting nationwide solid nonhazardous waste standards for CCB disposal. On April 17, 2015, the EPA finalized regulations under the solid waste provisions of RCRA and not the hazardous waste provisions which became effective on October 19, 2015. EPA affirms in the preamble to the final rule that “this rule does not apply to CCR placed in active or abandoned underground or surface mines.” Instead, the U.S. Department of Interior and EPA will address the management of CCR in mine fills in a separate regulatory action. While classification of CCB as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase our customers’ operating costs and potentially reduce their ability to purchase coal.

On November 3, 2015, EPA published the final rule Effluent Limitations Guidelines and Standards, revising the regulations for the Steam Electric Power Generating category which became effective on January 4, 2016. The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last three decades. The combined effect of these rules and the CCR regulations has forced power generating companies to close existing ash ponds and will likely force the closure of certain older existing coal burning power plants that cannot comply with the new standards. These regulations add costs to the operation of coal burning power plants on top of other regulations like the 2014 regulations issued under Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment. Individually and collectively, these regulations could, in turn, impact the market for our products. However, on September 13, 2017, the EPA postponed the compliance dates for the best available technology economically achievable effluent limitations and pretreatment standards for two wastestreams at existing sources, bottom ash transport water and flue gas desulfurization wastewater, for a period of two years.

Endangered Species Act

The federal ESA and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from mining-related impacts. If the service were to designate species indigenous to the areas in which we operate as threatened or endangered, we could be subject to additional regulatory and permitting requirements.

Other Environmental, Health and Safety Regulations

In addition to the laws and regulations described above, we are subject to regulations regarding underground and above ground storage tanks in which we may store petroleum or other substances. Some monitoring equipment that we use is subject to licensing under the Federal Atomic Energy Act. Water supply wells located on our properties are subject to federal, state, and local regulation. In addition, our use of explosives is subject to the Federal Safe Explosives Act. We are also required to comply with the Federal Safe Drinking Water Act, the Toxic Substance Control Act, and the Emergency Planning and Community Right-to-Know Act. The costs of compliance with these regulations should not have a material adverse effect on our business, financial condition or results of operations.

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KEY FACTORS AND ASSUMPTIONS

Reserve Estimate Methodology

We are required by ASX Listing Rules to report ore reserves and mineral resources in Australia in compliance with the Australasian Joint Ore Reserves Committee Code for Reporting of Mineral Resources and Ore Reserves 2012 Edition, or JORC Code. Under the SEC’s Industry Guide 7, classifications oth